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Executives

Robert Daniels - Senior Vice President of Worldwide Exploration

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

R. Walker - President and Chief Operating Officer

John Colglazier - Vice President of Investor Relations & Communications

Charles Meloy - Senior Vice President of Worldwide Operations

Analysts

Philip Dodge - Stanford Group Company

Brian Singer - Goldman Sachs Group Inc.

Dean Barber - Deutsche Asset Management

David Tameron - Wells Fargo Securities, LLC

Peter Kissel - Howard Weil Incorporated

David Kistler - Simmons & Company

Douglas Leggate - BofA Merrill Lynch

Joseph Allman - JP Morgan Chase & Co

Phil Corbett - RBS Research

Anadarko Petroleum (APC) Q4 2010 Earnings Call February 1, 2011 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Q4 2010 Anadarko Petroleum Corporation Earnings Conference Call. My name is Michael, and I will be your coordinator for today. [Operator Instructions] I will now turn the presentation over to your host for today's conference, Mr. John Colglazier. You may proceed.

John Colglazier

Thanks, Michael. Good morning, everyone, and I'm glad you could join us today for Anadarko's Fourth Quarter and Year End 2010 Conference Call. Please note we will only be addressing our 2010 results today. We plan to host an extended conference call on February 24 to provide additional details surrounding our 2011 capital plan, guidance and how that plays into attaining our five-year strategic plan, as well as some additional property-level details. We'll be sending out more information for that call in the coming days.

I want to take a few seconds to thank Chris Campbell for his contributions during the last four years as a valuable member of our Investor Relations team. Chris is continuing to play an important role at Anadarko and has joined our Corporate Planning Group. Dean Hennings and I look forward to continuing to work with you guys.

I will 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 today. You should read our full disclosure on forward-looking statements in our latest presentation slides, our latest 10-K, other filings and press releases and for the risk factors associated with our business.

In addition, we'll reference certain non-GAAP measures so be sure to see the reconciliations in our earnings release and on our website. We encourage you to read the cautionary note to U.S. investors contained in the presentation slides for this call. And as we do each quarter, we've included additional information in our quarterly operations report that's available on our website.

With that, let me turn the call over to Jim Hackett, our Chairman and CEO, who will discuss our 2010 results, and Jim is joined by other executives who will be available to answer questions later in the call. Jim?

James Hackett

Thanks, John, and good morning, everybody. Anadarko had a great operational year in 2010, and we surpassed the guidance we provided earlier in the year in almost every category. Starting with sales volumes at our Investor Conference in March of last year, we projected that we would grow about 4% over 2009 levels, and that we would spend about $5.5 billion in capital. We were able to outperform these objectives with almost 7% sales volumes growth in 2010 while spending almost $200 million less in capital.

Also in March, we forecasted an organic reserve replacement ratio of at least 130%, and we achieved 140%, adding 330 million barrels of oil equivalent of proved reserves before the effects of price revisions. Costs incurred amounted to just over $5 billion, resulting in better-than-anticipated reserve replacement costs as well. We've talked previously about our ongoing efforts to reduce our lease operating expense per unit, and the 2010 results in this area continued to improve. Results were favorable to guidance by more than $0.80 per barrel of oil equivalent, representing the savings of more than $170 million.

Coming off one of Anadarko's best exploration years in its history in 2009, we again reached a high mark in 2010. Our offshore exploration and appraisal drilling program has achieved a combined 75% success rate. Another one of our goals, as we discussed in March, was attaining 10% production growth per debt adjusted share. We met this target as we delivered record production levels in 2010.

The 2010 results reflect the depth and quality of Anadarko's portfolio. The record sales volumes were about 6.5 million barrels of oil equivalent higher than the midpoint of the original guidance, and 100% of this incremental growth was driven by increases in our liquids production as we allocated and redirected capital to liquids-rich areas of the portfolio. These areas included the Eagleford Shale, Bone Spring, Wattenberg and Greater Natural Buttes, among others.

Also partly as a result of our focus on liquids-rich assets within the portfolio, adjusted EBITDAX improved almost 40% versus 2009 to about $30.50 per barrel of oil equivalent, excluding items affecting comparability.

The 13% year-over-year growth in our higher-margin liquid volumes, coupled with our efforts to manage cost more efficiently, contributed significantly to the improved EBITDAX for the year. We also continued to achieve reduced drilling cycle times, with notable improvements throughout the onshore portfolio. One of the most dramatic examples was in the Eagleford Shale, where our spud-to-release times are now less than 12 days compared to more than 22 days in mid-2009.

From a broader perspective, seven of 10 major assets in the southern region had record cycle times during the quarter, and the Rockies industry study recognized four of Anadarko's contracted rigs as being among the top 10 rigs in the U.S. onshore for total footage drilled. All major areas of the portfolio provided year-over-year growth, led by the Rockies and the accelerated development activities in the shale plays.

In the Rockies, we delivered an 11% increase in sales volumes, and several areas continued to achieve record production levels, including Greater Natural Buttes, Wattenberg, our operated Wamsutter and Salt Creek EOR. In the Southern Appalachian region, the advancement of our shale and other unconventional resource plays contributed significant increases in sales volumes during the year as well. With the additions of the Grugan Gathering System and other infrastructure expansions in Marcellus Shale in Pennsylvania, by the end of the fourth quarter, we had nearly doubled gross sales volumes versus the end of the third quarter. The Marcellus continues to be the only major area where we are drilling for dry natural gas due to the proximity to premium gas markets, which further enhance the already robust economics of the play. We exited the year with approximate gross sales volumes in the Marcellus of 330 million cubic feet per day from about 70 wells.

Turning to the Eagleford Shale in South Texas, we recently established ourselves as the largest producer in this play. With the existing infrastructure and service agreements in place, about 94% of all completed wells have been flowing to sales. We ended the quarter with gross sales volumes of about 27,000 barrels of oil equivalent per day, of which 75% is liquids. This represents a six-fold increase in volumes versus the prior year fourth quarter.

At current market prices, the Eagleford is generating excellent economics. And with 450 million barrels of oil equivalent and net risk resource potential on our acreage and more than 2,000 identified well sites, we plan to ramp up to 10 rigs by the end of the first quarter of 2011 from two rigs at the beginning of 2010. We continue to evaluate a joint venture structure for our Eagleford program similar to what we have done in the Marcellus.

Beyond the phenomenal growth in our shale assets in the southern region, five of our seven major operating areas achieved their lowest base decline rate during the quarter, as we continued to focus on maintaining our existing base production. Additionally, we're actively pursuing other emerging growth plays in the Bone Spring, Avalon Shale and horizontal Niobrara plays, each with encouraging results, high liquids yields and substantial running room.

Moving to our sanctioned mega projects, as you all know, the Jubilee field offshore Ghana reached its first oil milestone in a record three and a half years following discovery, which is twice as fast as the industry average. We're proud of the integrated project team to safely deliver upon the time and cost schedules for this deepwater development. Jubilee is currently producing around 50,000 barrels of oil per day from four wells, and we expect to ramp up to capacity of around 120,000 barrels per day by midyear. Jubilee also gives us an excellent foundation in Ghana from which we can grow in future years, given our additional exploration and development opportunities in these blocks.

In Algeria, development drilling and construction work are progressing at the El Merk mega project. Initial production is anticipated around the beginning of 2012 and will be increased as the full facility is commissioned. In the Gulf of Mexico, we were making good progress on the Caesar/Tonga project and had received the necessary permits to begin completion activities in the first two wells. However, as we announced yesterday, we're disappointed that the project will not begin first production by the first half of this year, as a result of the production riser system failing our recent hydro-testing procedures. We have a team in place that is actively working toward a safe and reliable alternative. In the meantime, we want to assure you that we fully expect to be well within our 2011 production guidance of 240 million to 250 million barrels of oil equivalent that we provided last March.

Also in the Gulf of Mexico, we are fully utilizing our two contracted rigs. We recently brought the Callisto well in line of Independence Hub and completed work-over activities on two wells in the K2 area, returning them to production.

During 2010, as you recall, we announced several successful appraisal wells in both the Lucius and Vito fields. During the moratorium, these future mega projects continued to advance with feasibility and preliminary front-end engineering studies, as well as permit applications for additional drilling. We filed for permits with the BOEMRE to resume appraisal drilling around our Heidelberg discovery in the deepwater Gulf of Mexico as well.

Our worldwide exploration program continued to create differentiating value for our stockholders in 2010. We believe we were again one of the most active deepwater drillers in the world, announcing eight offshore discoveries with a 60% success rate. We also were nine-for-nine in our offshore appraisal program. In addition, we continued to be successful at evaluation and development of the Eagleford and Marcellus Shales, which enabled us to establish a net risk resource potential of about 1.5 billion barrels of oil equivalent in these two major growth areas. These successful activities and discoveries continue to expand the resource potential, confirm our geologic understanding and de-risk our positions in the U.S. onshore and in our offshore acreage positions in Brazil, Ghana, Mozambique and Sierra Leone.

Beyond the overall high success rate in Africa, according to IHS Energy, four of our exploration wells were among the five largest offshore discoveries in 2010. Three of those were in the Rovuma Basin in Mozambique where we hold a 36.5% working interest in the 2.6 million acre Offshore Area 1. These natural gas discoveries were made at the Windjammer, Barquentine and Lagosta prospects. Based on the results of those wells, our partnership is designing an accelerated appraisal program in analyzing various development options. We plan to keep at least one rig in the basin throughout 2011 to carry out an active appraisal and exploration program, as well as to conduct at least one drill stem test.

Currently in Mozambique, we are drilling the Deepwater Tuburão's prospect, which is located approximately 19 miles southwest of the Lagosta discovery. Tuburão is a 15,000-foot test of an Eocene fan system and we hope to have results from this well within the next week.

In West Africa, we made our second discovery offshore at Sierra Leone at the Mercury prospect, which we operate with a 65% working interest. The well encountered approximately 135 net feet of oil pay in two Cretaceous-age fan systems. The discovery also demonstrated the stratigraphic trapping systems we've identified are working, and that the petroleum system is generating high-quality oil. We expect to have an active exploration and appraisal drilling program offshore at Sierra Leone, Liberia and potentially Cote d'Ivoire, with three to five wells planned this year.

Our partnership's 2010 activities in Ghana continues to expand the potential of this world-class petroleum province with the discovery and continuing appraisal of the Enyenra field, formerly known as Owo. Enyenra is adjacent to our Tweneboa discovery in the Deepwater Tano license, where we hold an 18% working interest.

The partnership drilled four successful appraisal wells in this block during the year, three in the Tweneboa field and one side track in the Enyenra field. We plan to continue an active appraisal program in 2011 and expect to submit a plan of development for the area by the end of this year.

In the adjacent West Cape Three Points Block, where we hold a 31% working interest, we drilled another successful appraisal at the Mahogany East area to the southeast of the Jubilee Field. The M5 well follow three other successful wells in the area that have enabled the partnership to submit a Declaration of Commerciality to the Ghanaian government.

We are currently drilling the Teak prospect on the same block, about 2.5 miles northeast of the Jubilee Unit boundary. Teak is testing multiple Campanian and Tweneboa objectives, and we are encouraged by what we have seen so far in this well with results expected soon. The partnership plans to drill at least another four exploration wells this year on the block.

In Brazil, drilling is ongoing at the Itauna discovery on block BM-C-29, where we hold a 50% working interest. Back in November, we announced Itauna's discovery after the well encountered more than 275 net feet of oil pay in the post-salt section. We've begun drilling a bypass to the original wellbore that should enable us to obtain core data and additional reservoir and fluid information to better define the discovery. We plan to drill additional wells in the block in the latter half of 2011 contingent upon rig availability.

I've summarized just some of the highlights of our exploration and appraisal drilling programs and encourage you to look through the quarterly operations report on our website for more information.

Turning to the financial results for the fourth quarter of 2010, we reported earnings of about $0.22 per diluted share. As with previous quarters, we provided a breakout in the earnings release with certain items affecting comparability, without which, fourth quarter net income would have been about $0.07 higher or $0.29 per share.

Discretionary cash flow totaled approximately $1.3 billion for the quarter and almost $5.4 billion for the full year. We generated more than $200 million of free cash flow in 2010. As for the BP oil spill, we remain confident in our publicly-stated position. Consistent with the past two quarters, we've continued to apply accounting for guidelines to the facts as they are known to us today, and accordingly, we have not recorded a contingent liability associated with this event. We will, of course, include expanded disclosures in our 10-K when it is filed with the SEC later this month.

As mentioned in last night's earnings release, we ended the quarter with about $3.7 billion of cash on hand, after retiring more than $400 million of additional debt during the fourth quarter. Also in 2010, we took a number of steps to further strengthen the balance sheet and enhance liquidity, such as extending and upsizing our revolving credit facility from $1.3 billion to $5 billion. This facility remains undrawn. Our capital expenditures, including expense G&G [geology and geophysics], were approximately $5.3 billion for the year. As I mentioned earlier, this is nearly $200 million lower than the midpoint of original guidance.

Turning to reserves. We added 330 million barrels of oil equivalent of organic proved reserves during 2010 before the effective price revisions. This equates to a reserve replacement ratio of approximately 140%, which exceeded our target as I mentioned earlier. We accomplished this while incurring cost of just over $5 billion associated with our oil and natural gas exploration and development activities.

As of our year end 2010, about 69% of our proved reserves were developed and only 31% undeveloped. An estimated 44% of our proved reserves were liquids. Consistent with the previous year, put up meaningly from 2008 levels, when liquids only comprised about 40% of our of product mix. In March of last year, we detailed our five-year goals and with the results in 2010, we are firmly on track to deliver upon those metrics.

As I stated in last night's release, we are very proud of the dedication and focus of our employees who delivered very strong results in the face of significant challenges that we experienced last summer. The reference resulted in record production, better net tax, high liquids volumes, improved LOE, important fractionation agreements and infrastructure expansions and significant exploration success.

We look forward to updating you on our longer-term plans and providing our 2011 guidance and capital program later this month. As I mentioned earlier on the call, we anticipate full year production to be well within the guidance we provided last March. We also expect our total capital spending program to be in line with cash flows. With that, Michael, if you would, we'd like to open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Peter Kissel of Howard Weil.

Peter Kissel - Howard Weil Incorporated

First of all in Ghana, I was just wondering to hear your initial thoughts for development of Tweneboa. And in particular, I know you previously talked about lumping Tweneboa and Owo together and I was just curious to see as both of those have gotten bigger and better, what's your updated thoughts are? I know it's a little preliminary.

Charles Meloy

Peter, this is Chuck. It is preliminary. We are undergoing studies to evaluate the full development of both of those fields. There's a lot of synergy between them, particularly on the early time. And so that's the direction we're heading. But those studies are ongoing. We hope to have a decision later this year or early next year.

Peter Kissel - Howard Weil Incorporated

I know the JV progress in Eagleford is ongoing, and I was just curious to hear what your targeted structure is for the JV? And then also, are there any other areas where you're looking at a JV structure in particular, possibly the Niobrara?

Robert Daniels

This is Bob. I'll speak to your question on the Maverick first. We're looking at a structure similar to that, which we did in the Marcellus. I think that's the best guidance we could give you on that front. The progress is continuing. We've seen strong interest and our expectations around execution haven't changed there. And as we speak to the Niobrara, we aren't looking at the Niobrara yet for a JV. Certainly down the road, it might be something we would consider but as you know, we're in the very early stages. We like to get our science done. It's worked well in the Marcellus and now in the Maverick to get the science done to show some really good performance and then to go to the market to sell the project as it's been a little bit more developed.

James Hackett

We're obviously happy that there's interest showing in Niobrara from the outside world.

Operator

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

Douglas Leggate - BofA Merrill Lynch

First of all, I know you don't want to speak to the production guidance, given that you have your call later this month, but when you put out the release yesterday on Caesar/Tonga, and you confirmed that you will be within your March guidance, can you just reiterate what your maintenance capital is or your stay flat capital is? And what the underlying decline looks like now, Jim? You said that it was getting a little bit better.

R. Walker

Well, Doug, this is Al. Let me try and see if I can help you with that as best I can recognizing, as you say, we're going to be probably only answer in part today. The capital intensity around our ability to replace reserves year-over-year really hasn't changed. If you recall, that was about a $2 billion spend in prior years, and that will probably be about the same as we go forward. As we look at what we're going to be able to hopefully achieve in 2011, we do believe that despite the delays with Caesar/Tonga, the guidance we gave you in March is going to continue to be something that we can deliver on. And I think as we move forward here in a couple of weeks, we'll be able to give you a little more information around that, hopefully, in a way that we'll continue to kind of give you kind of development activity in our shales that is probably going to be the largest growth engine for that.

Douglas Leggate - BofA Merrill Lynch

Al, does that guidance assume that you completed joint venture in the Eagleford or not?

R. Walker

When we look at that guidance, we don't really assume a joint venture. It's certainly today one of the better areas in our portfolio in terms of return on capital. So as we look at it, if we can improve the return on capital through a joint venture, then certainly we would pursue it but as we think about guidance, it is not a net number.

Douglas Leggate - BofA Merrill Lynch

My follow-ups are just relating to a couple of the assets, if I may, just to get an update. Obviously, Mozambique, you're continuing to drill there. Obviously, it was like predominantly gas at the time being. What's a realistic timeline? I mean, what do you need to see there in order to get comfortable that there's actually a viable project? And if you could talk maybe to the liquids opportunity perhaps further for the South? And the only other one I have really is on Sierra Leone and similar kind of question. You've got a lot of well control, I guess, a lot of calibration logs and so on that you can basically look from all the wells you've drilled in that region. Can you maybe speak a little bit more as to the prospectivity of Mercury, given what you found, given the scale of the structure and perhaps, including the 65% working interest is something you would want to hold onto as you move forward with that one. I'll leave it there.

Robert Daniels

Doug, it's Bob. We'll start with the Mozambique question. We are continuing to drill out there, and we have said, we'll keep the rig there at least through 2011, and we may even be bringing a second rig in towards the end of the year. We're in the process of looking at that right now. We're presently on Tuburão, that's almost done and we're getting all our data out of it. Like what we're seeing there, it's just a further extension of the -- called LaBarquen Jammer Complex [ph] to the south, about 19 miles and we should have results on that here very shortly. The rig then is going to go and really focus on defining the LaBarquen Jammer Complex [ph] better. And what we're hoping to do this year is to find the resource where we're going to get enough data from the wellbores, from DFTs, from interference testing, to look at overall volumes, deliverability, wellbore efficiencies, so what's the drainage area, what's the ultimate recovery per well so that we can start designing the development with real detail and also give the data to an outside reserve group to certify the reserves, which we're going to move forward with an LNG project. We do think that the LaBarquen Jammer Complex [ph] has already exceeded the minimum threshold for LNG, we've said that, which we thought was about 40 CF. What we're really trying to do is get those numbers pinned down to where they can be certified outside. As we move to the liquid side of it, we did find liquids down to the south of the block in our Ironclad prospect in tight reservoir. We're shooting 3D down to the south. It should start first week of February. We'll extend the existing 3D all the way in the block boundary. Then we're going to move to the north and extend the 3D all the way to the northern boundary. The south will be focused on the oil potential. The north will be more of the gas up in that same complex. The second rig that we would bring in would be for the further exploration work because most of the year is going to be tied up with all the work to get to the reserve certification for LaBarquen Jammer [ph].

And then going over into Sierra Leone, we do like what we're seeing over there. Mercury was a nice discovery. We think that we have a good appraisal location. We said that we're going to drill three to five wells in the margin outside of Ghana. If it's three, they'll all be up in the Sierra Leone, Liberia area. The five would be, if we can clarify the situation at Cote d'Ivoire and get down there and drill the prospects that we like there. So one of those wells will be a Mercury appraisal well. We've got a good location that we think will help really prove out the volumes down there. But from a petroleum system standpoint, everything we've seen on our two wells in Sierra Leone tells us that, that basin has the same sort of potential as what we're seeing in Ghana and hopefully our Côte d'Ivoire.

Douglas Leggate - BofA Merrill Lynch

So you'll keep the 65% working interest?

Robert Daniels

We're looking at that right now. There's a lot of interest, of course, in coming in to those plays. And 65%'s typically a little bit higher than we like but we also have the issue of when the rig shows up. We can't bring a partner in at the middle of a drilling campaign. So it would have to happen here in the next couple of months if we do lay off some. It's not going to be a lot if we lay off any but we do have a lot of interest in it.

Operator

Your next question comes from the line of Dave Tameron of Wells Fargo.

David Tameron - Wells Fargo Securities, LLC

I'm not sure who wants to answer this but if I think about -- I'm just trying to recap what [indiscernible] speak to yesterday. Can you guys recap your position in the Powder? And then, the Niobrara and in the Powder, do you have any of the deeper frontier rights or any generalization you can make about that?

Charles Meloy

Dave, this is Chuck Meloy. Our acreage position at Powder Rivers is about 750,000 acres, give or take a few. Mostly, what we're focused on, of course, is the CBM [coalbed methane] assets. We're producing about 800 million cubic feet gross. So it's been a very good piece of business for us. We've, of course, through the course of time, have collected the deep rights under many of those acreages and expanded our acreage position outside the CBM in hopes that we can put together a deeper play in the oil sands and title sands and shales and that's what we're evaluating currently today.

David Tameron - Wells Fargo Securities, LLC

And then maybe a question for Al, if the Eagleford JV doesn't get done, is there -- I know you have cash on the balance sheet. How do you think about reallocation of capitals? Is there something that perhaps, one gets done and what's that marginal project that would be added if the Eagleford JV does get done?

R. Walker

David, I think you'll see in the next couple of weeks, our current plan as we roll out our capital for 2011 would not assume a joint venture. So therefore, the operating rig count that we continue to make reference to in the play and taking that up to 10 rigs, that is today without the benefit of a joint venture. So we're not really contingent on the joint venture to fund the activity level that we see in that play in 2011.

David Tameron - Wells Fargo Securities, LLC

And if it does get done, can you give us an indication of where that additional capital would go or...

R. Walker

Actually today, I suspect our answer is more likely than not we would reallocate it to some other onshore liquid-rich plays, particularly in the one to the north of that area.

David Tameron - Wells Fargo Securities, LLC

And then one final question for whomever. As we forecast it, it looks like on a quarterly basis, production should be maybe some lumpiness but production should be on uptick here like throughout 2011. Can you give me confirmation or denial of that, anything along those lines as far as -- does that trend sound right as far as quarterly sequential upticks from here on out at least for the next few quarters?

Charles Meloy

Dave, this is Chuck again. I think what we'll see through the course of 2011, as you know, we've produced around 235 million barrels for 2010. We told you it's going to be between 240 million and 250 million, and we're keeping on that guidance today. It looks like we'll be well within that. On a quarter-to-quarter basis, there's a bit of a lumpiness just because of the timing of liftings, et cetera, in Algeria and China, so it's hard to project on a quarter-by-quarter basis, it would be an absolute straight-growth rate but what you're seeing is a continuous and constant growth in our shales that's driving our production upwards. We're seeing Jubilee, of course, come up on its ramp up which should drive it up. So you should see a steady upward trends with a few ups and downs associated with liftings.

David Tameron - Wells Fargo Securities, LLC

And you guys have some pretty chirks last March, about what shales look like going forward. Is that still a fair projection for us to use in modeling as we think about '11 and '12 for the shale component of that?

James Hackett

What we're seeing is just tremendous growth in the shales, David. If you take a look back in the start of 2010, our entry rates for like the Maverick was around 3,400 barrels a day gross. And today, it's a 27,000 barrels a day gross or a little better than that. If you look at the Marcellus, it was about 40 million gross. Today, it's about 330 million gross. So those are on a tremendous growth path. We intend to adjust that and show you what we're forecasting for the remainder of the next few years in our February 24 call but I think it's fair to say that they're certainly matching it, if not exceeding our expectations.

Operator

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

David Kistler - Simmons & Company

As you guys highlighted, looking at the efficiency gains that you're experiencing in the kind of the U.S. plays, specifically Eagleford, Marcellus, Rockies, obviously had some huge strides there from spud to rig release. Can you guys talk about kind of maybe what inning we're in with respect to the efficiency gains that are taking place there? And maybe if I could push it a step further, quantify kind of expectations of once you move from held by production in some of those areas to pad drilling, what you think will happen from an efficiency basis?

Charles Meloy

Dave, this is Chuck again. We are extremely proud of our drilling group and the many accomplishments they have made. The efficiency gains have frankly stunned me. They've just done a spectacular job, working every element of the drilling process. I would hesitate to call what inning we're in because these guys continue to surprise each and every one of us. What we do feel like is once we get into a manufacturing process, that we will drain even more cost out of the system. If you take a look at the Maverick, we're getting near that. We're probably in the order of 70% or 80% into the manufacturing process. You take a look at the Marcellus, it's further behind, it's maybe 50%. Those are just rough estimates. We're starting to do more and more pad drilling in the Marcellus. You've seen the improvements. I think another thing in both of these areas, as we learn more about these reservoirs and how to drill them and how to make the curves and that type of thing, we continue to find those efficiency opportunities and I will never proclaim we're in the ninth inning.

James Hackett

And I just might add to that, too, we don't talk about the completion side of it, if there's continuous improvement occurring in the completion side either in terms of yield or in terms of efficiency there, too, so there's more room to move along the whole chain.

David Kistler - Simmons & Company

And just kind of maybe following on, on that a little bit. Two questions: One, as you guys continue to drive down costs on both sides of that equation, can you talk about what you think that means more from a macro gas outlook? And then two, as you guys are experiencing efficiency gains, is this leading to an increase in kind of drilled maybe uncompleted wells or drilled wells that you're not able to rapidly tie in? In other words, do we have an inventory of production that's waiting to come to market?

James Hackett

Let me try the first part and I might turn it back over to Chuck on the inventory issue. Obviously, this helps lower the cost structure for the industry, but I still think that you've got to be in the right places until we see a little more structural change in the gas demand side. The good news is I think that's going to happen even without federal legislation, which is something I didn't believe a year and a half ago, and I think we're four to five years away from that starting to happen in a much bigger way, particularly in the power generation sector, and we try to help make some of that come true up in places like Colorado. But from our perspective, we do have in the place, the one place where we're drilling for dry gas actively in Marcellus has some notable advantages from a cost and market standpoint. So I think everybody still needs to be cautious about what they do here even with lowering costs. And obviously, you have to be in the right places in the country. But I think gas continues to surprise us even in the short term. I mean, we had a bearish view on gas for a couple of years, and frankly, it continues to stay a little higher than we thought due to a variety of factors we couldn't have anticipated. So we're generally consensus on gas directionally in the short term but we're continually mindful that we might get surprised in the upside. I'll have Chuck answer the second part.

Charles Meloy

The question was how we're dealing with the growing inventory of wells that are not flowing the line -- if we look across our portfolio and I'll focus on the Marcellus because it's probably the example with the largest non-producing inventory. It's now approaching 200 wells. There's really three reasons why they're in that condition. The first is those that are actually in completion progress or progress is being made on the completion. We have roughly 50 wells that are now under some stage of completion. And that is just associated with the complexity of the process of completing a horizontal well. There's several different steps in that process. There's many stages of fracturing and because we're on pads, by and large today, it takes longer to actually take a well from the start of completion to first production just because other wells on the same pad are being completed and all of the activity going on. We did have about 75 wells that are waiting on the completions, waiting for them to get in line on the completions. And finally, though we have several wells in the order of 70 wells that have actually been completed that are waiting on the pipeline connections. And that's a matter again of the process of laying lines and getting the hook ups and permits, et cetera, in that area. So it's just a steady progression of wells going through the process. And I guess I would say that we are -- that's more than I would have anticipated at this stage in the process. But after you really look into it, it's not surprising, given the terrain and the challenges associated with the completions and just the durations of the completions.

Operator

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

Brian Singer - Goldman Sachs Group Inc.

First, sticking with the Marcellus, can you just talk about well performance there and well performance in terms of IP rates from your newer wells? And how that may be different in the different parts of your acreage blocks? And then separately, decline rates that you're seeing from some of your older wells and whether those decline rates are in line or lower than the tight curves that you put out in the past?

Charles Meloy

Brian, this is Chuck. We have about, I'd say close to 80 wells online now. And as we mentioned, they're producing about 330 million feet a day combined. So you have a very nice rate, over 4 million a day per well on average. What we've seen from the new wells is, if you brought IPs versus time, if they continue to grow as we improve the completions and hone in on the exact target lines and that kind of thing, so we're seeing continuous improvement. In fact, our most recent wells have, we've put in two pads recently and both those pads has averaged over 7 million cubic feet per well on the initial completions. The decline rates are in line with our expectations on our tight curves that we've provided in the past. That drove after a period where the pressure drops and -- the rates were flat but the pressure drops, and then they go on to decline. And what you're seeing is at least in our early times, we're still early in this play, the expected recoveries from these wells are well north of four Bcf and some in the six Bcf-plus range.

Brian Singer - Goldman Sachs Group Inc.

And then on Lucius, can you just update us on the key milestones for Lucius? And then, what your latest thoughts are on both sizing, combining with other discoveries locally and the timing?

James Hackett

Well, as you're aware, we drilled a number of wells at Lucius, have great-looking results, tremendous pay. These are oil pays, good oil. We have requested permits to drill additional wells in the Lucius area. The milestone is we need to get an oil spill recovery plan approved by BOEMRE and then we'll go out. We also intend to do a DST in the field. We're working with our neighbors on the Hadrian area to do a complete development for the area, that would be the most cost-effective alternative for development along with a field development down south.

Brian Singer - Goldman Sachs Group Inc.

And lastly, you touched on this a little bit earlier with regards to Niobrara but what is your view on the extent to which the Niobrara play or the Frontier play extends to your PRB acreage, and then if you look overall between Wattenberg up to the PRB, the repeatability of the play?

R. Walker

Let me see if I can take it. This is Al. The play is probably, at times a little misunderstood and Niobrara has been a big part of the production out of the DJ Basin for a long time. As we move north, it moves from being more of a gas with oil condensate to less gas and more oil. And we see that as we move into Wyoming in particular. The area that you're making reference to in the Powder River there, that's really not a Niobrara Shale. That's different producing horizons that people are targeting, then the plays are very different. So when people talk about the Niobrara, you're talking about the Colorado-Wyoming portion of where that shale is present. As we get into the Powder River Basin, the deep Powder River opportunities there, that's an entirely different play and I might, with that, let Bob Daniels take that just a little bit further.

Robert Daniels

In the deep Powder River Basin, there's multiple plays up there. We're looking a lot of them at very, very early up in that area. I don't think that the extrapolation, as Al said, from the Denver Basin, up to the Powder River Basin is going to be a blanket comparison that you could say, it's all going to be the same. So we're trying to, as we typically do, work the science out of it, look at the rocks, look at the phases changes as we go up into there but we do have a great position in the deep Powder, and we've been working at it for quite some time, just trying to understand what the true prospectivity is up there.

Operator

Your next question comes from the line of Phil Corbett of RBS.

Phil Corbett - RBS Research

Just a quick question on your West African drilling campaign. I just want to follow up in the earlier comments about the Teak prospect and what you said you see is encouraging signs. I wonder if you can give us any more detail on that. And secondly, just on the Sierra Leone, Liberia, Cote d'Ivoire plan. So just so I understand, are you saying that you may not drill a well in Liberia this year? And if you do defy your preferred operation will be to drill three in Sierra Leone and two in Côte d'Ivoire?

Robert Daniels

Phil, this is Bob Daniels again. Sorry for the misunderstandings there. I'll clarify it. Let's start with Teak. In Teak, we're not done with the well yet, and so all we have is MWD information still early stages. But we have dual objectives in there, and we're encouraged by what we're seeing so far. Until we get the final data out, know what we actually have, we're really not going to say a whole lot more about that but it shouldn't be very long before that data is in our hands and then we could talk about it. As to the rest of West Africa, we have two blocks in Côte d'Ivoire, four blocks in Liberia and two in Sierra Leone. Our plan is to drill three to five wells in Côte d'Ivoire, Sierra Leone and Liberia. The three wells, if we come at the low end of that, would be one in Liberia, two in Sierra Leone, of which one would be a Mercury appraisal well. So that will be the three-well scenario. If it goes to the five well, it's because we can get on to our Cote d'Ivoire blocks. Of course, the political situation there has kind of thrown a wrench into our plans at this point. So how that develops as to whether or not we can, in that same rig line, get down and drill the prospects we see in Côte d'Ivoire.

Phil Corbett - RBS Research

And just so one set of question on that. You don't have a rig yet or drillship for that campaign and that's what you're in the process of finalizing at the moment?

R. Walker

That's exactly what we're in the market for right now, and we anticipate having that frontline here shortly.

Operator

Your next question comes from the line of Philip Dodge of Tuohy Brothers Investments.

Philip Dodge - Stanford Group Company

Two things. First, could you elaborate on the application for drilling permits in the Deep Gulf other than Lucius? Is anything in process now? And how do you see that evolving?

Charles Meloy

Philip, this is Chuck. We've applied for a number of permits in the Deepwater. Primarily, the thing that we have to deal with is getting approval on our oil spill response plan, that's ongoing. What we want to do is drill a few more Lucius delineation wells, drill a Heidelberg delineation well and we'll also do some exploratory work in and around the Gulf. And each one of those really sits behind getting that oil spill response plan approved. And as soon as we get that done, we'll give you further details about which one we'll do and what order.

Philip Dodge - Stanford Group Company

Just aside, is a Helix response plan move you forward on that?

Charles Meloy

Yes, sir. What we've done is us, along with about 20 other operators, who have signed up to what we call the Helix solution. And it's what, as you're aware I'm sure, it was what was used with regard to actually killing the Macondo well. So a lot of good technology was developed. That's the first step. Subsequent to that will be the MWCC type of solution.

Philip Dodge - Stanford Group Company

Could you bring us up to date on service rates out there in the field, particularly pressure pumping?

Charles Meloy

Pressure pumping has been -- we've seen some increases in pressure pumping recently. There's a lot of pressure, particularly where the industry is really busy like the major shale plays. We're seeing it trying to level off some. We hope that's the case. What we're trying to do as company is offset that inflation with efficiency, getting our job done faster and more efficiently and decreasing the amount of time we have on location, so our absolute cost of doing business is reduced and that's what we're pushing.

Operator

Your next question comes from the line of Dean Barber of Barclays Capital.

Dean Barber - Deutsche Asset Management

Quick question, this is for Jim or Bob. Just wanted to follow up on Brazil. You guys talked about it before, potentially looking at that asset further post the Itauna well and also Itaipu. I just wanted to find out what the status was and what the strategy is there going forward?

Robert Daniels

This is Bob. I'll talk about the status right now. In Itauna, we have a post-salt discovery we announced, I think, back in December. We went down to pre-salt in the same wellbore, encountered some hydrocarbons, it's not really good reservoir. We've come back up into the post-salt section, and we are now taking a bypass core of the lower of the two reservoir intervals and then get full log evaluation of it to see exactly what we have there, how good the rock could be, what kind of fluids we have. So we're in the process of doing that right now and once we have all that data out, we'll talk some more about it. Additionally, we're going to be appraising Wahoo and Itaipu later this year. Itaipu now looks like it's going to be about May timeframe spud, maybe even a little bit later. We're just waiting on when the rig comes out of the shipyard. Wahoo, we're in the process of lining up a rig. And then Itauna, we expect to be back, drilling an appraisal well later in the year, and we do have a rig lined up on that already.

James Hackett

You can just imagine we have running room. We're obviously very aware too that it's an area that's very desirable. So we'll keep that in mind. I might just mention that we've got time for one more question, if you don't mind, operator, and we'll finish the call after that.

Operator

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

Joseph Allman - JP Morgan Chase & Co

Just a couple of questions. One, I noticed that for the fourth quarter, the U.S. oil production was below guidance and below the third quarter. Could you talk about that?

Charles Meloy

Sure, Joseph, this is Chuck. The primary issue in the fourth quarter was a Deepwater royalty relief adjustment that we received. It was about 700,000 barrels. Our production actually is doing very well. That was associated with adjustment, all this stuff that we settled back a bit ago. And right now, our exit rate was right at 200,000 barrels. So we're actually right in the middle of the guidance on an exit rate basis.

Joseph Allman - JP Morgan Chase & Co

And in terms of the reserves, talk about the big reserve edge you had in 2010. And especially Jubilee, I'm just curious at this point what did you book in 2010 at Jubilee? What have you got in total booked? And what's your estimate of Jubilee on an a-to-a basis based on what you've seen so far?

Charles Meloy

Joe, we don't break it out on a field-by-field basis what our reserves are. But generally, what we've seen is where we drilled wells, particularly in the Rockies and in the shales, we started booking again. And we've had just tremendous performance on our base that we've been able to add incremental barrels to our expected PUDs that are offsetting those bases and base wells. So it's just across-the-board. We've done, I think, a fair job of not increasing our PUDs. So when we drill, we're adding PDP reserves. The quality of those reserves is outstanding. In my view, it's better than it's ever been from a go-forward basis and the quality of the economics associated with the PUDs, particularly given the shales. And I think we're real proud of the fact that today, we've been very conservative with regard to our shale, and bookings in about 2% to 3% of our company is shale reserves while we have tremendous upside in those as we drill out our program.

Joseph Allman - JP Morgan Chase & Co

And then with the Gulf of Mexico, the permitting process, could you guys just talk about what really is the issue at this point that you think you just need to kind of get over to really start making progress with the permits?

Charles Meloy

Those were mentioned earlier, and it's primarily the oil spill response document that we have to file. That's in with the BOEMRE right now. We saw news earlier that, that shale was actually achieved, their response plan approval. So we're hopeful that we're quickly behind that.

James Hackett

And I think Joe, in our planning, we have not actually anticipated any drilling until the second half of this year.

Joseph Allman - JP Morgan Chase & Co

Just a follow up with the oil production, so for the fourth quarter, was the onshore oil up or down from third quarter?

R. Walker

Joe, this is Al. I think most of this definitely, we're going to be waiting a couple of weeks, and we'll talk a little bit more about how '11 and '12 are going to play out. But generally, what we're seeing from all of our onshore production is an upward trend. I know you're looking specifically at wanting to get some field performance information, and we just don't feel like from our perspective getting into field level performance is constructive but rather talking about it from a portfolio perspective.

James Hackett

If anybody has any questions obviously, please call Investor Relations group and we'd be happy to work with you on that. I just want to thank everybody on the phone, first of all. And also, I want to thank our shareholders and employees for a great year in 2010. We're obviously looking forward to another good year in 2011, and we will talk to you as we've mentioned several times in several weeks about more detail for the coming year. With that, have a great day. Thank you.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a good day.

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