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Anadarko Petroleum (NYSE:APC)

Q1 2011 Earnings Call

May 03, 2011 10:00 am ET

Executives

A. Moore - Vice President of Marketing

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

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

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

John Colglazier - Vice President of Investor Relations & Communications

Charles Meloy - Senior Vice President of Worldwide Operations

Analysts

Philip Dodge - Stanford Group Company

Brian Singer - Goldman Sachs Group Inc.

John Malone - Ticonderoga Securities LLC

David Kistler - Simmons & Company International

Raymond Deacon - Pritchard Capital Partners, LLC

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

Subash Chandra - Jefferies & Company, Inc.

S. Ross Payne - Wells Fargo Securities, LLC

Douglas Leggate - BofA Merrill Lynch

Phil Corbett - RBS Research

Operator

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

John Colglazier

Thanks, Tom. Good morning, everyone, and I'm really glad you could join us today for Anadarko's First Quarter Conference Call. 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 and 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 have included additional information in our quarterly operations report that is available on our website.

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

James Hackett

Thanks, John, and good morning, everyone. The operational performance of our assets and teams in the first quarter 2011 was excellent. They continued to demonstrate the quality and depth of the portfolio that's been assembled. The first quarter set yet another record for sales volumes with the average sales of 690,000 barrels of oil equivalent per day. We also announced a $1.6 billion joint venture with Korea National Oil company in the Eagleford, highlighting the tremendous embedded value of our position in this shale play.

The deepwater exploration progress continued, with 3 discoveries and 3 successful appraisal wells announced during the quarter. We also achieved meaningful improvement in quarter-over-quarter lease operating expenses. And we announced the acquisition of the Wattenberg Processing Plant, the significant benefits of which will be discussed in more detail in a few moments.

Focusing first upon the operational performance for the quarter, the record sales volume of 62 million barrels of oil equivalent were at the high end of guidance, and liquids made up an increasing portion of these sales volumes at about 42% for the quarter. Lease Operating Expense also improved by about 13% per BOE compared to the fourth quarter of 2010. These achievements contributed to a 12% sequential improvement in adjusted EBITDAX per BOE. The record sales volumes included significant increases in production from our shales, specifically the Marcellus and liquids-rich Eagleford plays, and from our First Oil lifting at the Jubilee field offshore Ghana.

Regarding the Eagleford Shale, where sales volumes increased by 30% quarter-over-quarter, we secured additional takeaway capacity for both crude oil and natural gas through multiple long-term pipeline and handling agreements. Capitalizing on the greater than 100% current rates of return in this play, we ramped up activity to 10 operated rigs, have expanded our infrastructure and service agreements and are well positioned to continue delivering strong growth.

We are also very pleased to welcome KNOC as a partner in the Eagleford Shale after recently closing our joint venture. Through the partnership, KNOC will fund up to 100% of capital costs for the remainder of this year and up to 90% thereafter until the carrier is exhausted, which will likely be year-end 2013. As they do this, they warrant 1/3 of Anadarko's interest in the play.

Included in last night's earnings release was news that KNOC also exercised its option to acquire an approximate 25% interest in the associated midstream assets in the Eagleford. We are eager to work alongside our new partner in our hope to expand this relationship in the future.

Turning to Marcellus Shale. We've currently operated 8 rigs and continue to expand infrastructure on pace with our development activities. Sales volumes increased by about 82% over the previous quarter, and we recently established record growth sales volumes of almost 450 million cubic feet per day from approximately 95 producing wells.

Our emerging growth plays in the Permian Basin of West Texas also demonstrated significant sales volume due to increases during the quarter. In the Bone Spring, gross sales volumes nearly doubled over the fourth quarter 2010 to almost 16,000 barrels of oil equivalent per day comprised of more than 75% liquids. In the shallower Avalon Shale, some of our recent wells have tested at rates of between 800 and 1,000 barrels of oil equivalent per day, also with a high liquid cut. Evaluation of the Avalon Shale and the Wolf Camp opportunity is ongoing.

Moving to the Rockies. The Wattenberg field and greater Denver Julesburg Basin quarter area continues to expand. The Wattenberg team achieved another new sales volume record during the quarter as it continued to maximize the robust economics of the field and capitalize on its important liquids yield, which represents about 75% of the value stream. Also in the region, we continue to test the vast potential of the horizontal Niobrara opportunity, where we hold about 1.3 million net acres, much of it in economically advantaged by our land-grant ownership.

We're seeing strong results in our operated program in the play, and we added an additional horizontal rig during the quarter in order to accelerate these activities. Given our premier position in the emerging Niobrara opportunity and the continued growth in the Wattenberg field, we recently acquired full ownership of the Wattenberg Processing Plant by purchasing BP's 93% stake. This purchase further aligns our midstream and upstream assets in this core area. We expect to extract additional value from the plant through modifications and future expansions that will improve run times and significantly increase capacity and liquid recoveries. We also plan to optimize our fields in order to improve margins, increase estimated ultimate recoveries and enhance efficiencies.

The plant, combined with our facility at Fort Lupton and Western Gas Partners' recently purchased Platte Valley plant, provides us with a significant portion of the processing capacity in the greater DJ Basin. The Wattenberg plant should also be an excellent candidate for a future acquisition by Western Gas Partners.

Further west in the Greater Natural Buttes area, sales volumes increased by about 7% over the fourth quarter. The field set a new single-day gross production record of 456 million cubic feet equivalent per day, with an approximate 30% liquids content. During the quarter, the Greater Natural Buttes team drilled 11 Mesa Verde wells that also were deepened to the Blackhawk interval. The early results from this program are encouraging as the Blackhawk program provides additional running room and incremental recoveries of more than 700 million cubic feet equivalent per well at an estimated development cost of less than $0.42 per Mcfe.

Also worth noting in Wyoming's Wamsutter field is that we set a weekly gross production record of approximately 13,000 barrels of oil equivalent per day during the quarter. We provided additional detail on these and other assets in our first quarter operations report that is available on our website.

In the Deepwater Gulf of Mexico, we have continued to keep both of our contracted rigs active as we move projects forward, while working to acquire drilling permits that will allow us to resume exploration and appraisal activities. At Caesar/Tonga, the project team continues to pursue parallel paths toward a riser solution, advancing the development towards First Oil in 2012. During the quarter, we successfully float tested 2 wells, and each demonstrated very strong rates of more than 15,000 barrels of oil per day, with completion activities underway on the third well. As we previously announced, once the completion is finished, we plan to move the rig to West Africa late in the second quarter, begin our 2011 exploration and appraisal program in Sierra Leone and Liberia.

At the Lucius field in the Gulf of Mexico, we have a rig on location to conduct an extended well tester in the second quarter. We expect the test to provide us with valuable insight into the reservoir's permeability, lateral extent, communication and acquifer support that will assist in the design of the facility and top size. In the meantime, our project teams continue to advance development planning and front-end engineering studies at Lucius.

Tuning to our international mega projects. As you know, we achieved a major milestone at quarter one with our first lifting from the Jubilee Field offshore Ghana. Current production from this world-class field is more than 70,000 barrels of oil per day, and the partnership continues to ramp up production towards 120,000 barrels per day of capacity by the third quarter of this year.

Additionally, we have experienced no disruptions in Algeria, and construction is progressing well at the El Merk project. The overall project is about 75% complete, and we anticipate major facilities completion and significant production rates around the end of 2012.

As you've seen in our press releases, our exploration teams delivered another strong quarter, with 3 significant deepwater discoveries and 3 successful offshore appraisal wells.

Turning in Ghana and the West Cape Three Points Block, where we hold a 31% interest, we announced both the Teak-1 and Teak-2 discoveries during the quarter. Teak-1 encountered more than 240 net feet of oil condensate natural gas pay in Cretaceous-age reservoirs. The Teak-2 discovery well was drilled between the Teak-1 well location and the Jubilee Unit boundary and encountered 90 feet of oil condensate natural gas pay. The partnership is evaluating plans to appraise both discoveries later this year.

Also in the West Cape Three Points Block, the partnership is currently drilling the Banda prospect to the east of the previously announced Odum discovery. Once Banda is complete, the partnership plans to mobilize the rig to drill to the nearby Macquarie prospect, southeast of the Jubilee Unit.

On the adjacent Deepwater Tano Block, where we hold an 18% working interest, we participated in 3 successful appraisal wells during the quarter in the Tweneboa/Enyenra complex, and a 4 successful Tweneboa-4 was announced by the operator subsequent to quarter's end. The rig is now on location at the Tweneboa-2 well to conduct a drill-stem test. The Tweneboa/Enyenra complex has the potential to be as large as Jubilee, and the partnership is continuing an active appraisal program to advance the complex toward an expected declaration of commerciality later this year.

In February, we announced another major discovery in Mozambique in the Rovuma Basin. Tubarao is the fourth significant natural gas accumulation discovered in this frontier deepwater basin where we hold approximately 2.6 million acres. Tubarao encountered more than 110 net feet of natural gas pay and opened a new play style, which further strengthened our confidence in our geological and geophysical models of the basin. Anadarko operates Tubarao with a 36.5% working interest.

Further north, in the Windjammer, Barquentine and Lagosta complex, we are continuing to evaluate commercial solutions and advance this future mega project. We are currently conducting quarrying operations. And in coming months, we expect to begin appraisal activities that include multiple drill-stem tests in the complex.

We are also acquiring new 3D seismic data in the basin and plan to bring in another rig to drill additional exploration wells beginning in the fourth quarter. As mentioned earlier in this call, we plan to mobilize a rig from the Gulf of Mexico to West Africa later this quarter to begin our exploration and appraisal drilling program offshore Sierra Leone and Liberia. Plans include drilling the Montserrado prospect in Block 15 Offshore Liberia, where we are the operator with a 57.5% working interest.

We also plan to utilize the rig to drill the Jupiter prospect offshore Sierra Leone and an appraisal well in our Mercury discovery. Both of these wells are located in Block 07B-10, which we operate with a 65% working interest.

In the Gulf of Mexico exploration program, we have been encouraged by some of the movement we've seen in recent weeks regarding well permits. We are one of the few companies that has joined both the Helix Well Containment Group and the Marine Well Containment Company, and we are optimistic that we will be able to receive the necessary permits to resume our exploration and appraisal drilling programs in the Gulf during the second half of this year as we budgeted.

With regard to BP oil spill of last year, we stand by our stated position, which continues to be supported by the findings of various independent investigations. Consistent with past quarters, we have again included disclosures regarding this event in our first quarter 10-Q filing with the SEC.

Turning to the financial results for the quarter, we reported earnings of $0.43 per diluted share. As with previous quarters, we provided a breakout in the earnings release of certain items affecting comparability, without which first quarter net income would have been about $0.29 per share higher, resulting in adjusted net income of $0.72 per diluted share.

As I mentioned previously, we generated strong discretionary cash flow of nearly $1.7 billion during the first quarter. This was about $90 million more than our total capital expenditures of $1.6 billion, which included consolidation of approximately $317 million in spending at Western Gas Partners, our publicly traded Midstream MLP.

We ended the first quarter with approximately $3.5 billion of cash on hand and maintained significant additional liquidity through our undrawn 5-year $5 billion credit facility. Our full year capital expenditures are expected to be in the range of $6.2 billion to $6.6 billion, not including the expenditures of Western Gas Partners. The $600 million increase in this number from February's estimate was discussed at the March Howard Weil investor conference and simply reflects the purchase of the Wattenberg Processing Plant that we discussed earlier in the call.

With the strong first quarter results, the company continues its positive momentum as we move closer to achieving the 5-year objectives that we presented in March of 2010. As we look ahead to the second quarter, we are expecting sales volumes to be in a range of 60 to 62 million barrels of oil equivalent. This will keep us on target to meet our full year goal of 244 to 248 million barrels of oil equivalent.

In summary, our shales and emerging liquid-rich growth plays are generating excellent results, returns and value. We have ample running room and continue to extract substantial value from the core operating areas throughout our phased assets. Jubilee is performing well, and our other sanctioned mega projects continue to advance toward first production. We expect to continue a very active offshore exploration and appraisal program providing significant value upside for our shareholders. And we are continuing to work to safely resume exploration and appraisal activities in the Gulf of Mexico during the second half of this year. With that, Tom, we'll open up the line for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of Subash Chandra with Jefferies.

Subash Chandra - Jefferies & Company, Inc.

A couple of questions, I guess, beginning with the Rockies and the liquids going on out there and the growth expected. Are there sort of any limiting factors in handling the NGL supply growth out of that base in this year or into 2012?

Charles Meloy

Subash, this is Chuck. What we're doing now is from Greater Natural Buttes and Wattenberg, which is our 2 large liquid production areas, we're selling condensate and oil in through the White Cliffs Pipeline in Wattenberg, and with trucks in Greater Natural Buttes, our natural gas liquids are headed to both Conway and Mt. Bellevue. We have contracts in place to make those movements and feel good about our expansion capacity out there.

Subash Chandra - Jefferies & Company, Inc.

Okay, and Marcellus, I guess this rate of growth both from Anadarko as well as industry, lots of, I think, something like 3 bs a day of new takeaway. How is this gas going to be absorbed in the next couple of years? And do you see sort of an export market in Canada developing?

A. Moore

This is Scott Moore, from Marketing. That gas will be consumed in local power generation as well as reduction in imports, because our guys [ph] come up from the Southeast and the Midwest.

Subash Chandra - Jefferies & Company, Inc.

So offsetting other U.S. gas? Okay.

A. Moore

Right.

Subash Chandra - Jefferies & Company, Inc.

And a final one. So this whole lizard issue in the Permian, any thoughts on how that plays out? Is this serious this go-around? Or is this a non-event?

A. Moore

Subash, can you repeat that question?

Subash Chandra - Jefferies & Company, Inc.

Yes, I'm sorry. The endangered species in -- I forget the name of the lizard out there that's making its way through U.S. Wildlife and Fish Commission (sic) [U.S. Fish & Wildlife Service]. And it looks like it overlaps Ward County, and so -- where you have 3 rigs active. So curious about that.

James Hackett

Subash, what we're doing, of course, we're monitoring the situation. And as always, we take all the regulation [indiscernible] environmental hazards into account and make our development plans. Going forward, we'll deal with it as we see it.

Subash Chandra - Jefferies & Company, Inc.

Yes, a final one if I could, sorry. The sweet spots in the Marcellus, how many rigs do you think you'll run throughout this year and going forward?

James Hackett

We'll run around 8 drilling rigs and 1 or 2 spudders, and then in the JV area, Chesapeake's running around 15. And so combined, 23 to 25 rigs or thereabouts

Operator

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

Douglas Leggate - BofA Merrill Lynch

I'm going to try a couple in West Africa. I'm not sure there are too many lizards out there, but we'll see how we get on. The Ghana, obviously, you mentioned the potential declaration of commerciality in West Tano. Can you talk about -- I believe Kosmos has talked about a potential submission of Mahogany. Can you just talk about what the current prognosis is for how many developments you ultimately see there? And if you could touch on perhaps the Tweneboa/Enyenra gas versus oil debate as to how that might impact the development concept? And I've got a couple of follow-ups, please.

Charles Meloy

Doug, this is Chuck. With regard to Ghana, on the Tweneboa side, we anticipate an FPSO. It's been mentioned in several of the newspapers and rags. Tullow is progressing now with really good speed. We hope to have a decision by year end as to the final development program. The oil and gas mix is still being evaluated with regard to our appraisal program. It looks like a very economic development in any regard. With regard to Mahogany East, that's a subsea development that we intend to tie back to Jubilee as space becomes available. Kosmos is the operator of that. We evaluated a number of different alternatives and landed on the subsea system. There's still an outside chance in the event additional development or something made it just substantially bigger that we could do something else. But right now, the partnership's pointed directly at a subsea system. With regard...

Douglas Leggate - BofA Merrill Lynch

Sorry, Chuck. Should we think then about extending the plateau of the Jubilee development? Is that how should we think about that?

Charles Meloy

That's the way we're seeing it right now. And then with regard to remainder of it, it'll -- we're having a lot of success, as you know, with our exploration and appraisal program north and east of the platform, the FPSO. At Teak and others, we have the oval discovery -- I'm sorry, the Odum discovery, east of there. So all that is being put together and evaluated for additional developments pending the result of the appraisal and exploration programs that are ongoing now.

James Hackett

Yes, Doug, just to remind you, we're presently on Banda. And we'll see what we have there. Then we're going to move down to Macquarie. And that looks to be an interesting prospect, particularly with the news that came out of the Hess block [ph] recently, to the south.

Douglas Leggate - BofA Merrill Lynch

Is Teak potentially a stand-alone development? And if you could maybe speak to the Teak-2 in terms of the implications for maybe slightly changing unitization of the Jubilee field?

James Hackett

Well, Teak could be a stand-alone development. We need to get out there and drill the appraisal wells. So we don't know at this point. But certainly, it has the implications that it could be. And of course, when you put Odum and some of the others that we anticipate coming into it, then you've got the makings of a stand-alone. But that's going to require a lot of drilling and that's what we're focused on this year. As to the Teak-2 and the unitization, I might ask Chuck to deal with that.

Charles Meloy

Well, the unit is put together and have taken expansion. We have some information that we're certainly in the same zones. And we're evaluating what the pressure information, that will tell us. But what I suspicion will happen is as we go along and start gas injection and production from Jubilee up in that quadrant will determine whether to put together or not.

Douglas Leggate - BofA Merrill Lynch

Great. So I've just got a couple of quick follow-ups, if I may. This thing with West Africa, very quickly, I guess my favorite question, the farm, the potential farm-down of your 65% working interest. Any thoughts there before you really start to get after some of those wells? And given that Cote d'Ivoire seems to have settled down a little bit, are you planning to get back there? And I'll leave it there.

James Hackett

On the farm down, we have concluded the farm-down of 10% of our working interest. That's all we wanted to lay off. We signed that last Friday, so that's in place and will help on the ongoing activity. That's specifically in Liberia and Sierra Leone. And then on Cote d'Ivoire, we do have prospects that we would like to get into and drill. Originally, we had planned a 5-well program in West Africa, including 2 in Cote d'Ivoire. We're paying close attention to how the situation's developing in Cote d'Ivoire. And as things stabilize, and we have confidence that our people can work safely in country, we'll be looking at when we can drill those wells. Right now, we do not have them at the end of the 3-well program in Sierra Leone and Liberia.

Operator

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

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

Just following on Ghana and West Cape Three Points. The exploration phase ends in July. Banda and Macquarie, Dahoma Updip, will they all be drilled before the exploration phase ends?

James Hackett

Yes, David, that's the plan, to get all those drilled and then to, based on whatever we find, roll those into an appraisal phase.

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

Okay, and then if you think about the undeveloped parts of the block, there's an ability to negotiate a new petroleum agreement. Is there any update on the status for that new petroleum agreement, and any idea of prospects or prospectivity on that block?

James Hackett

I think by the time we drill, finish Banda, finish drill Macquarie and up-dip Dahoma that we will pretty much have evaluated what we see is the good prospectivity of the Block. Then we'll be really focused on the appraisal phase. We've got Teak-2 appraised. We already have an appraisal in Odum. And then any other success that we have here at those 3 exploratory wells will require additional appraisal.

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

Okay, and then as you think about Deepwater Tano exploration, as you bring these projects into development, you have until 2013, half of the exploration phase there, can you talk about the number of prospects that you think you'll test on the exploratory side of -- at Deepwater Tano over that time frame? Just a rough number would be useful.

James Hackett

We probably have 2 to 3 more exploratory wells to drill over there. And then based on the appraisal drilling, we seem to be finding additional sands at different levels beyond what we're appraising, and those need to be further delineated. So that may drive some additional activity. But right now, we see 2 to 3.

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

Okay, and then in Mozambique, as you think about going to the south and testing potentially any oil concepts, can you kind of walk through the risk profile now that you've found an oil source but not reservoir? Just kind of what do you think about the prospectivity is for oil in Mozambique?

James Hackett

Yes, David, we're shooting at 3D. Or we just finished shooting at 3D in the southern portion of the Block. And if you have the maps that we put in our IR reports, it's extending the existing 3D to the block boundary. That's in the processing center now, and we should have that third quarter sometime. That's going to tell us a lot about the prospectivity and the risk. Right now, what we know is, there's a petroleum system down there that's generating the liquid hydrocarbons, but we did not find the liquid hydrocarbons in quality reservoirs. So we need to see on the 3D, or the quality reservoirs, which we do think we can utilize some of the techniques we've developed up north that are very good at identifying good sands and then try to match up the source kitchen and migration routes into those sands. So that'll give us a real good handle on the risk profile then. But until we get that 3D, and we're working from a very sparse grid of 2D beyond where our existing data set was, and so it'll be towards the end of this year before we really can answer that question with any confidence.

Operator

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

David Kistler - Simmons & Company International

Real quickly in the Niobrara. You guys added an extra rig there, heaps of acreage, great returns out of the play. What are kind of limiting factors from accelerating that? And I know you're moving to 4, but where could that ultimately go from a development standpoint?

Charles Meloy

Dave, this is Chuck. If you look at the Niobrara closely, what you see is the center of the Niobrara is sitting squarely over Wattenberg. And we're actively developing the Niobrara in both the horizontal and vertical sense in and around Wattenberg and expanding out to the north with the industry. And the industry's, along with us, are taking a lot of effort to evaluate and delineate the potential in Niobrara, and we're in the midst of that. 1 or 2 of the 3 rigs we currently have -- or is doing work north of the Wattenberg Field proper. And what we expect to see happening is based upon results, we could see that expanded quite considerably. But it's going to take great results before we make those decisions, and we're doing a lot of evaluation work. We have a very extensive land position. I think it's around 1.3 million acres combined. And so it's going to take us a while to really evaluate what we have. And it even can move up into the southern Powder River Basin area, which we have a nice land position as well. So it's going to be a while before we can really answer that question directly, but we certainly see the potential to grow extensively in the area.

David Kistler - Simmons & Company International

Okay, that's helpful. And then focusing on some stuff you shared with us back a bit, it was on efficiency gains, the Eagleford, Marcellus, Bone Springs, et cetera. Are efficiency gains baked into your forward production guidance? And I guess maybe even on top of that is, if we look at the increased EURs on a per well basis across most of your land plays, are those also baked into -- is there some of that baked into your forward production guidance?

Charles Meloy

Well, not really, I guess is the answer. What we do is make a reasonable estimate of what our position looks now. And then we put a bunch of engineers to work, trying find a way to improve that. And so, it's our best estimate. As we sit here today, we're doing -- we're constantly doing experimentation to evaluate the opportunity to gain efficiency, either speed or cost. And as we realize those, we put them into our guidance.

David Kistler - Simmons & Company International

Okay, and I guess then the follow-on to that would be what have you guys seen in the last quarter in terms of upticks? Or is that exceeding expectations? In the past, you've mentioned that you thought you were maybe in later innings in the Eagleford in terms of efficiency gains but early innings in the Marcellus. Any kind of color you can give us in terms of where we might see step shift changes going forward would be very helpful.

Charles Meloy

Well, I think that still holds true. We -- if you go back out to the Maverick Eagleford area, we've recently drilled a well in 8.4 days, which is improving substantially from a historical performance. In the Marcellus, we still have some room to work, we think. We've now got down to -- our average is in the order of 17 to 18 days in the most recent drilling. So we're very excited about that. And we think we can improve upon it, but we haven't -- we're just going to -- it's a hard row to hoe, and we're working on it every day to make it better.

David Kistler - Simmons & Company International

Okay, and then just last follow-on question to that. If efficiency gains are getting better, obviously, on a recovery, on a per well basis or returns on a per well basis, that insulates you from service cost increase. But if efficiencies are getting better, you're drilling more wells and aggregate service costs go higher. Is that something we should be thinking about with respect to CapEx going forward on the year? Could there be a bias higher?

James Hackett

We're not planning on that. Our goal is to at least offset the cost inflation we see with efficiency and then use our capital program for the most economical wells we have. And so we'll move it around to adjust where we need to.

Operator

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

Brian Singer - Goldman Sachs Group Inc.

Can you talk to what you're seeing on New Zealand and how the exploration opportunity there competes relative to other areas in the portfolio?

Robert Gwin

Yes, Brian, this is Bob. Yes, we really like what we're seeing in New Zealand. We've got a 3D in the Canterbury Basin over what we call our Carrack and Caravel prospects. That is have the 2D line that ties up onto the shelf. And that is important in that, that 2D line also ties into a well that was drilled, tested about 10 million a day of gas and 2,300 barrels of condensate. And when you come and look at these prospects, we're looking for the same reservoir intervals that were encountered on that shelf wall, come through a syncline and then back up on a big 4-way structure. And when I said big, it's like 90,000 acres of 4-way closure. So it's very significant. And then because it's about 7 million, 8 million acres out there, we think we've got tremendous amount of follow-on potential, so we shot some 2D. We're out there shooting now. I think we just finished the 2D, actually acquisition side of it, to help define that follow-on potential. So that's the Canterbury Basin. And then we have the block in the Deepwater Taranaki. Of course, the Taranaki Basin is an established petroleum system. Nobody's really tested the Deepwater in very methodical way. And again, our acreage position's very significant up there. So we acquired 2D last year. We defined, we've mapped that now. We've defined some prospects up there. And so our plans moving forward are to drill 2 wells, one in the Canterbury, one in the Taranaki Basin. We're out talking about getting rigs and discussing the availability. It does look like there are rigs available. The mob, of course, is going to be a big issue. And what we're trying to do is line up other operators in New Zealand to help share that mobilization. So we've got a lot of work to do before we actually sign the rig and get to drilling. But right now, we're targeting towards the end of the year, early 2012, if all that comes together. If not, it'd be a year later. And as to how they compete in our portfolio, they compete very well. The fiscal terms in New Zealand are extremely attractive. And then, as I described, the potential, we see very good potential there.

Brian Singer - Goldman Sachs Group Inc.

Great, thank you. That's very helpful. And then secondly, on West Africa, in Jubilee, with Phase 1 now on. Can you just talk about how you're thinking about future phases and costs relative to the first Jubilee set?

Charles Meloy

Well, we're actively completing all the Phase 1 wells, and the production's ramped up. We're now in excess of 70,000 barrels a day. So we feel we're doing extremely well. We still have 4 or 5 additional producers and injectors to complete. And once that's completed, we envision a Phase 1a, which is primarily infill wells to fill in this general area that we're developing. And then after that is done, which it should be sometime next year, we would potentially expand to the remainder of the field area. And it's just to knock it out as we see production results and allow the, in sort of reservoir speak, the production talk to us and lead us where we need to do further development.

James Hackett

On the cost side, Chuck, you'd expect that anything that's a subsea back is actually going to be as economical or better?

Charles Meloy

Yes, actually, it would probably be better because all of the infrastructure's in place. When we put in the subsea system, we allowed for additional drilling slots in the subsea manifolds. And so it's pretty much just not -- drill the wells and put them online. So there's no additional subsea or topsides hardware necessary.

Operator

Your next question comes from the line of Philip Dodge with Tuohy Brothers Investment Research.

Philip Dodge - Stanford Group Company

Just a detail on Jubilee. Is the price there indexed to Brent?

James Hackett

Yes, price there is indexed directly to Brent.

Philip Dodge - Stanford Group Company

Good. And then on Wattenberg, want to make sure the liquid situation -- am I correct, you said Wattenberg itself is about 30%, was what I heard?

James Hackett

I think that was Greater Natural Buttes.

Charles Meloy

Right. I think around Wattenberg it's around 40%, actually.

Philip Dodge - Stanford Group Company

40% Wattenberg. Okay, and then on the Wattenberg edge and the undeveloped acreage that you're going to work on, do you have any indication as to what the liquids content will be there?

Charles Meloy

We have some indication. What we're expecting, particularly as we go north, that it becomes actually more liquids prone as we move up toward the Wyoming border from Wattenberg proper. And that's just based on early results from the wells we drilled.

Operator

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

S. Ross Payne - Wells Fargo Securities, LLC

Jim, I was wondering if you could comment on the Macondo well, if you see this thing playing out more in the courts or if you see it going to arbitration as maybe BP has indicated.

James Hackett

I think it's, just to state what's fairly obvious, is we don't think that we owe anything. But we also realize that our investors would like us to consider some sort of approach that's perhaps a compromise from that. And so it's a very complicated process with multiple parties in the litigation. And while we may be interested in settling individual parties at various points on down the road here, it's indeterminate until we see some groupings get together to try to get this done. So I'd say that it's complicated. We understand where our shareholders are at. We feel very strongly about our position, but we're prepared to come to the table under the right circumstances.

S. Ross Payne - Wells Fargo Securities, LLC

And would you be required to go through arbitration as a part of this whole process, or what's your thought there?

James Hackett

I mean, that's the remedy in the contract. But Bobby Reeves is the one that...

Robert Reeves

Yes, this is Bobby. Ross, it's not totally clear. Certainly, there's a dispute resolution procedure in the joint operating agreement. BP, as disclosed in our 10-Q that we filed yesterday, have provided a Notice of Dispute. It has a period of time within which management representatives will get together, see if we can resolve the disputes amongst us. If after that time is expired and the cooling-off period we don't, then it's up to the parties whether or not to invoke arbitration. It's not a clear-cut deal. We feel good about where we are in the litigation, and we're committed to staying there until told otherwise by the court.

Operator

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

Phil Corbett - RBS Research

I just had a quick question. May have eluded me, but did you disclose who you farmed out your position in Liberia too? Have you disclosed that?

James Hackett

No, we haven't, but it was Mitsubishi.

Operator

Your next question comes from the line of Ray Deacon with Pritchard Capital Partners.

Raymond Deacon - Pritchard Capital Partners, LLC

[Technical Difficulty]

Operator

And your next question comes from the line of John Malone with Ticonderoga Security.

John Malone - Ticonderoga Securities LLC

Just one brief question. Overall, you saw a drop in the lease operating expenses. How does that play out geographically? Are you seeing any kind of upwards cost pressure in plays like the Permian or the Eagleford?

Charles Meloy

John, we see structural cost increases in all of the basins that are very hot, based on the shale plays. However, much like our drilling and completion programs, we're working very hard with our field organizations to find efficiencies in our operations and improve that lease operating structure. Effectively, we've been benefited by the fact that we have had very few, if any, significant deepwater workovers in this quarter. So that's helped the overall cost structure as well.

Operator

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

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

Just a follow-up, Chuck, on your Eagleford and Marcellus comments, that you're drilling wells in 8.4 and 17 to 18 days. How long is it taking you to actually drill to complete, to actually put on production?

Charles Meloy

David, we have -- it's varying, frankly, across the entire plays because of the infrastructure that's available to us. In the center of our Maverick development, we could put them on very quickly, and we've had production inside 40, 45 days from spud. If you're out on the remote areas of the field, it can take upwards of twice that. In the Marcellus, it's the same way. If you're able to drill -- when we drill wells in our developed area with pipeline connections or on pads, we can connect them very quickly. If we drill wells in new and expanding areas, it takes the time to get pipelines installed and it can be upwards of 6 months in some areas. So it varies across the field.

Operator

And since there are no further questions, I will now turn the call over to Mr. Hackett for any closing remarks.

James Hackett

We just want to thank everybody for joining us today, and we look forward to updating you on our second results this summer, and hope you have a great day. Bye.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a great day.

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