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Anadarko Petroleum (NYSE:APC)

Q3 2010 Earnings Call

November 02, 2010 10:00 am ET

Executives

Robert Daniels - Senior Vice President of Worldwide Exploration

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

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

R. Walker - President and Chief Operating Officer

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

John Colglazier - Vice President of Investor Relations & Communications

Charles Meloy - Senior Vice President of Worldwide Operations

Analysts

Brian Singer - Goldman Sachs Group Inc.

Joseph Magner - Macquarie Research

Mark Polak - Scotia Capital Inc.

David Tameron - Wells Fargo Securities, LLC

John Herrlin - Merrill Lynch

Douglas Leggate - BofA Merrill Lynch

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

Scott Hanold - RBC Capital Markets Corporation

Scott Wilmoth - Simmons

Operator

Good day, ladies and gentlemen, and welcome to the Q3 2010 Anadarko Petroleum Corporation Earnings Conference Call. My name is Veronica, and I will be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to your host for today's call, Mr. John Colglazier. Please proceed.

John Colglazier

Thank you, Veronica. Good morning, everyone, and welcome to Anadarko's Third Quarter 2010 Conference Call. Joining me on the call today are Jim Hackett, our Chairman and CEO; and other executives

who will be available to answer questions later on in the call.

As we've done in the past, we have posted additional supplemental information in our operations report that's posted on our website. In addition, last night, we also filed our third quarter 10-Q that we would encourage you to review.

Before I turn the call over to Jim, I need to remind you that this presentation contains our best and most reasonable estimates and information available at the time. However, a number of factors could cause actual results to differ materially from what we discussed today. You should read our full disclosure on forward-looking statements in our latest presentation, 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 review the reconciliation slides attached on our release as well as on our website. And we encourage you to read the cautionary notes to U.S. investors contained in the presentation slides for this call.

And with that, let me turn the call over to Jim Hackett.

James Hackett

Thanks, John. Good morning, everyone. In the third quarter, the company delivered strong reported sales volumes of approximately 58 million barrels of oil equivalent, marking the 15th consecutive quarter in our portfolio met or surpassed the guidance that we provide to the investment community. This third quarter sales number was at the high end of our guidance and included the effects of tanker scheduling in Algeria and both planned and unplanned downtime in certain onshore and offshore facilities.

There are several other highlights in the quarter to mention. First, positive results from our ongoing shale development activities in the U.S. and onshore enabled us to enhance the net risk captured resources in our Marcellus and Eagleford shale plays. Second, our exploration programs continued to deliver additional world-class discoveries. And third, the portfolio generated considerable cash flow during the quarter, while we saw a success in significantly strengthening our balance sheet.

Now I'll walk through some of the more significant operational accomplishments during the quarter. Our U.S. onshore drilling activities remain focused on liquid-rich opportunities. As a result, liquids comprise about 41% of our total third quarter sales volumes. We also continue to drive down operating costs, with a 17% improvement in lease-operating expenses for BOE year-to-date relative to 2009.

In the Rockies, sales volumes for the quarter increased by about 10% over the third quarter 2009, primarily from liquids-focused production growth in Wattenberg and Greater Natural Buttes. The Wattenberg and Greater Natural Buttes teams set new production records during the quarter. In the liquids-rich Wattenberg field, we achieved record oil delivery of nearly 3,000 barrels in a 24-hour period. On the Greater Natural Buttes area, the teams set a daily gross production record of more than 412 million cubic feet equivalent per day during the quarter.

In Laramie County, Wyoming, we spud our first operated horizontal well in the oil-focused portion of the Niobrara play. The completion activity is expected to commence in the next couple of weeks. We've also drilled four vertical test wells in the play. We drilled about 500,000 gross acres, and enjoy very attractive economics due to our ownership of the minerals in perpetuity by virtue of our land grant position.

We also completed the acquisition of 160 square miles of 3D seismic here, and we expect to increase our activity in the play by adding additional rigs in 2011. In the Southern and Appalachia region, our teams increased third quarter sales volumes by about 9% over the third quarter of 2009, led by the Eagleford and Marcellus Shale plays. For EMP development in these two shale plays, we have better plans to substantial net risk capture resource potential for each asset.

We'll talk about the Marcellus first, where we've now identified estimated net risk captured resources of more than 6 trillion cubic feet. We're consistently seeing wells of IPs of better than 7 million cubic feet per day across our entire core position, encompassed within 750,000 gross acres in North-Central Pennsylvania.

During the last week of September, the Marcellus team also achieved an all-time weekly production high of 174 million cubic feet per day gross from 46 producing wells. We're expecting a significant increase in the number of producing wells and overall production as we continue to build infrastructure in the field.

With recent start of our 200 million cubic feet a day Grugan gathering system and pipeline and other expansions, we are expecting to increase takeaway capacities of just under 600 million cubic feet per day in the third quarter and more than 1.15 Bcf per day by the end of the fourth quarter.

Shifting to the Maverick Basin in South Texas, our development activities and positive results from the liquids-rich Eagleford shale indicates that this asset holds more than 450 million barrels of oil equivalent of net risk captured resources. Additionally, in the Eagleford, we have everything in place from gathering to takeaway to processing capacity in water management system. This provides efficient running room and addresses the infrastructure needs to enable us to continue growing our production for years to come.

We're now producing on an ADS basis of more than 15,000 barrels of oil equivalent per day, with seven rigs running on our 400,000 acres. They're primarily located in Dimmitt and Webb counties. We plan to increase to nine rigs in the first quarter of 2011. With average EURs of 400,000 barrels of oil equivalent combined with today's commodity price environment, we're currently realizing robust rates of returns of approximately 65%.

In the Delaware Basin of West Texas, where we began to see two more oil-focused opportunities in the Bone Spring and Avalon Shale, where we hold about 550,000 gross acres. We, along with our partners, are now running seven rigs in the area. In the Bone Spring, we continue to see IPs of more than 1,000 barrels of oil per day, with natural gas that has 10:10 PM a high Btu content and good market access. We're also seeing encouraging results from our first two operated Avalon Shale wells. They're each approaching 700 barrels of oil equivalent per day. By the end of the year, we expect to have completed about eight exploration test wells in the Avalon Shale.

The substantial net risk resources in our shale plays and the performance of these assets bolsters our confidence in the capability of these onshore U.S. fields, generate a significant value and contribute material volumes and reserve growth to our overall portfolio.

Switching to geography. We're getting closer to achieving first oil from the Jubilee field in Ghana, the first of our three sanctioned mega projects. Once this project and the others in Caesar/Tonga and El Merk are complete, we expect these three mega projects to add about 60,000 barrels of oil equivalent per day net to Anadarko in 2012.

At the Jubilee project during the third quarter, the partnership was in the final steps of commissioning the FPSO and also finished about 90% of the subsea work. This project remains on schedule and on budget, and we look forward to first production prior to the end of the year.

We've surpassed the halfway point in the construction of the El Merk in Algeria, which remains on schedule and on budget as well. In the Gulf of Mexico, our project team has proven nimble in keeping the Caesar/Tonga mega project moving forward during the government-mandated deepwater moratorium.

During the quarter, topside modifications continued in the first riser and flow lines were successfully installed. We expect to advance subsea work, including the installation of jumpers and umbilicals in the fourth quarter and to achieve first production on schedule by the middle of next year. Also, while the moratorium was in place, we continue to advance development planning for both our operated Lucius project and the Shell-operated Vito project in the Gulf of Mexico. We also advanced projects in the Gulf for which we have permits. This includes the Callisto tieback at the Independence Hub where the pipeline permit was approved, and where we expect to achieve first production in the fourth quarter.

In addition, during the quarter, we also received a workover permit at the K2 field. Lifting of the moratorium last month was a positive step for the industry in the Gulf Coast region. And though we are ready to safely resume our deepwater exploration and appraisal activity, we, along with other deepwater operators, must have greater clarity around the regulatory process. We're hopeful the government will soon begin to process and issue the permits that will allow the industry to put people back to work.

While activity in the Gulf remains limited, we maintained a very active international exploration program throughout the quarter. In West Africa, our partnership announced the third major discovery offshore Ghana at the Owo prospect in the Deepwater Tano block, where we hold an 18% working interest. This discovery is adjacent to the Tweneboa discovery, both of which lie in the west of the Jubilee field. The Owo discovery well and subsequent sidetrack encountered a total of more than 225 net feet of high-quality oil play and stacked Turonian-age reservoir sands. We're excited about the Owo and Tweneboa discoveries and plan to return adjures to see an active exploration, seeking out an active appraisal program once we complete drilling the Mercury well offshore Sierra Leone. Mercury, which spud in early October, is our second deepwater test in the Liberian Basin.

In Mozambique, we recently announced a world-class natural gas discovery at the Barquentine prospect. The discovery well, located about 2 miles southeast of our previously announced Windjammer discovery, encountered more than 416 net feet of natural gas pay. These two successful wells confirm to the presence of a large accumulation in this frontier basin. We're currently designing an appraisal program that will enable us to determine the areal extent of this new field. And we've begun preliminary evaluation of the potential natural gas commercialization options.

We've mobilized the drillship approximately 16 miles to the south of the Rovuma Basin. The drill will address the prospect, which would be followed by an exploration well at Tubarão. Based on the success of Mozambique to-date, we anticipate keeping a rig in the basin with an active exploration and appraisal program for the foreseeable future. As operator of the Rovuma base in Offshore Area 1, we hold a 36.5% working interest and approximately 2.6 million acres, with more than 50 identified prospects and leads.

As we announced in the yesterday's news release, we encountered 133 net feet of oil and natural gas pay at the Badik prospect in offshore Indonesia. The well is located in 230 feet of water and was drilled to a total depth just under 13,000 feet. And it's the first significant discovery on the shelf in the Tarakan Basin. We operate Badik with a 35% working interest and are evaluating appraisal programs and obtaining 3D seismic data on the block.

In Brazil, drilling is ongoing at the Itauna prospect where we encountered oil with accompanying logs, indicating hydrocarbons and the buildup wasn't one of our primary targets. We are encouraged by what we've seen so far. We're continuing to drill towards both post- and pre-salt objectives and expect to have results in coming weeks. We are operating Itauna with a 50% working interest. With the positive results for our worldwide exploration program, we remain on track to deliver the 400 million barrels of oil equivalent of net discovered resources that we have committed to during our March investor conference.

Turning to financial results for the quarter. We reported a net loss of $0.05 per diluted share with certain items affecting comparability that increased net income by $0.26 per share. Absent these items, which are typically excluded by the investment community, our net income would have been $0.21 per diluted share as reconciled on Page 7 of last night's earnings release. We ended the quarter with approximately $4.2 billion of cash on hand and also completed a number of actions that have significantly enhanced liquidity.

First, we entered into a five-year $5 billion undrawn secured revolving credit facility that replaced and upsized our previous $1.3 billion revolving credit agreement. This is due to mature in 2013. Second, we completed the issuance of $2 billion of 6.375% seven-year senior notes and used a portion of the net proceeds from this offering to retire $1.3 billion of debt maturing in 2012.

Subsequent to quarter end, we used a portion of the drawn proceeds to retire an additional $422 million of 2011 debt maturities. As a result of these actions, we have significantly increased our access to capital, while reducing our near-term debt maturity. And we've extended our average debt tenure to more than 14 years. These actions strengthen the company and further protects the interest of all of our stakeholders by providing ample access to capital and liquidity to deliver upon our strategy.

In an update to our previous comments regarding the Macondo well, we remain confident in our publicly stated position. And therefore, in applying accounting guidelines to the facts that they are known today, we have not recorded a contingent liability associated with this event. As we did in last quarter, we began including expanded disclosures in our third quarter 10-Q filed yesterday, and we encourage you to review that document for more information.

Related to Macondo, early in the past quarter, we implemented a one-time supplemental retention program for all nonexecutive employees, for which we recorded a charge of $30 million during the quarter. This program is linked directly to our performance goal for this year and was implemented to keep our teams focused on delivering results during the perceived uncertainty surrounding the Macondo event. We're pleased that this has been effective, as turnover is lower than now than before the event. And we continue to deliver the results we had targeted. Again, this is performance-based and retentive.

Now to summarize my remarks, the performance of our teams and our portfolio was solid. It enabled us to, again, raise our full year guidance. As detailed in the attachments to last night's earnings release, we are increasing our full year sales volume guidance to a range of 233 to 236 million barrels of oil equivalent. This equates to year-over-year volume growth of 7%. We have also reduced our capital guidance, as we now expect capital expenditures including expense G&G [geology and geophysics] to be in the range of $5.3 billion to $5.5 billion for the year.

Beyond these updates to guidance, as I mentioned earlier, we continue to improve our status as one of the lowest cost operators in our peer group, with a 17% year-to-date improvement in LOE per unit. And we are well positioned to achieve our reserve replacement targets at a competitive cost of less than $17 per barrel of oil equivalent. The recent the success of our exploration teams will allow us to meet our commitment to discover more than 400 million barrels of oil equivalent of net resources during 2010 despite the Gulf moratorium.

Our balance sheet is in good shape. And as we discussed today, we've taken a number of steps to enhance liquidity and reduce near-term debt maturities. These actions plus the continued performance of the portfolio provides for the financial strength and flexibility to continue delivery of our strategic plans and expectations this year and well into the future.

In the new year, we plan to update you on our full year results and then at a later date, to provide details on our 2011 capital and operating program. At this point, I can tell you that we expect our 2011 volumes to be well within the estimated range we provided in our March 2010 investor conference. And importantly, we expect to keep the capital expenditures in line with cash flow based on the current strip.

Now we'll happy to take your questions. So Veronica, if I could turn it back over to you.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Scott Wilmoth from Simmons and Company.

Scott Wilmoth - Simmons

Directionally speaking, what level of drilling activity are you guys planning for 2011 versus 2010 on the U.S. onshore? And can you quantify any mix-shift changes in terms of oil versus gas-directed rigs?

James Hackett

Scott, it looks like we'll be up probably in the order of 10 to 15 rigs year-over-year, mostly in association with the Maverick, Bone Springs and Wattenberg programs. All liquid-oriented.

Scott Wilmoth - Simmons

And so do you have subsequent decreases on the gas side, or is that all just incremental rigs?

James Hackett

Those are the incremental rigs. There are decreases associated with the gas side, but fairly small because we're not drilling many gas prospects right now.

Scott Wilmoth - Simmons

And then can you give us an update on your joint venture process in the Eagleford? And if you guys are considering any JVs maybe in the Bone Springs or Niobrara?

Robert Gwin

This is Bob Gwin. I'll speak to the Eagleford. And we still expect to do something there, but the terms are more important to us than the timing. So we'd probably looking for something late this year or more likely early next year to be able to announce. On the other fields, I mean, we're a little earlier on the science on those fields. And certainly, it's a little too early to tell.

Scott Wilmoth - Simmons

And then lastly, can you just briefly talk about maybe the service cost environment, pressure pumping in the different regions, maybe Marcellus, Eagleford, Permian, Rockies?

James Hackett

In the very active basins like those you just mentioned, there is pressure, inflation pressure, on particularly pumping services. Most other services are flat to slightly positive on the cost side. It's hard to say whether that will continue as you look forward. What we see is a number of better new equipment coming into the market as well as a realignment between the gas basins and the oil basins. So how all that equalizes, we're uncertain at this point.

Robert Gwin

And the other thing that's working in our favor, Scott, is a fair amount of extra capital being put to the stimulation side which will have a beneficial effect at some point.

Operator

Your next question comes from the line of Joe Magner. [Macquarie Research]

Joseph Magner - Macquarie Research

Can you provide any more color on the process you've experienced for getting completion permits on Caesar/Tonga, and then maybe remind us of the timeline that will need to be maintained in order to deliver on those first production expectations?

James Hackett

Yes, Joe. We're working with the BOEMRE to get our permits. We've gone through all the certification requirements that are stated now through NTL -05 and -06. We also completed our BOP certification and final bits of completing our BOP certification for that work. We're hopeful that we'll see those permits toward the end of this year, if not in the next couple of weeks. And will be put to work, and we'll put the rig back to work early next year or late this year. And have that build online as we anticipate prior to midyear '11.

Joseph Magner - Macquarie Research

And sticking in the Gulf of Mexico, any updates on progress around insurance consortiums or industry spill funds or any of those types of tools that might be put in place to offset some of the financial liability exposure?

James Hackett

Yes, it's an active effort underway with particularly the API and other associations to do just that. And all of those issues are being addressed, containment, spill response and mutual insurance. And I have every confidence, we'll get to good answers on that front.

Joseph Magner - Macquarie Research

There was a comment that Wahoo South well had been drilled in the ops update. Can you provide any additional information on what was found or what might still be done out of Wahoo?

Robert Daniels

Yes Joe, Bob Daniels. We did drill the Wahoo South well. It was an independent feature south of the Wahoo discovery. You come across the same climb back up on the high. We were kind of on the north flank of a high that then runs off our block. The well was drilled to the pre-salt objective. We found a reservoir, but we did not find the hydrocarbons that we have been expecting. And we're trying to incorporate that into our thinking as to is there water contact, or are we down the plank of this structure. But it is independent of Wahoo itself and does not impact the overall Wahoo assessment. This was a stand-alone exploratory test, and it just didn't work.

Joseph Magner - Macquarie Research

And then any read-through on the other offsetting structures that could be drilled around Wahoo?

Robert Daniels

We're working on that now. There is one off to the west that we may want to go test. And then, of course the Itaipu structure feeds down into BMC-30, the northwest corner of that. And we may need an appraisal well up there at some point. We will be drilling, of course, an appraisal well to Itaipu probably starting in January or February of 2011. The rig had to go into shipyard for some mandatory inspections so that put a delay in it.

Operator

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

Douglas Leggate - BofA Merrill Lynch

First of all, going back to be Brazil. If you look at the, I guess, the fact that you've taken your big rig to West Africa, you're drilling at Tano, and I guess at some point, Itaipu will be done. How are you thinking about Brazil now in terms of the drilling backlog and ultimately its place as a long-standing asset, a long-term asset in the portfolio? And if you could you maybe layer in some commentary around Indonesia also. I understand this was an obligation where you had the discovery but longer term, is that an area where you expect to be active? Or are these trading chips basically to fund the other parts of the portfolio?

Robert Daniels

This is Bob Daniels. I'll give you some assessment on the activities and maybe my view on what we're going to do there. But in Brazil, we did move the rig after Wahoo South over to West Africa to drill the Mercury prospect and then to move on down to Ghana to take care of some activities there. And we have appraisal on exploration work. As I mentioned, the Itaipu appraisal will be done early 2011. That will be a Devon-operated rig that they have bringing in, to bring in. And we'll learn a lot from that. Of course, we've tested Wahoo#1. That was very successful. Wahoo#2 was not as successful. We had a lot of mechanical issues. And really right now, we're trying to incorporate all the information that we've got from the Wahoo#1 and #2 wells. We're waiting on the Itaipu appraisal so that we can get a sense for how big that is and meanwhile, working conceptual development planning. Itauna is kind of an independent entity. It's up on the shelf. And while it does have a pre-salt and post-salt objectives, it does not roll into the thinking there on the Wahoo Itaipu complex. So right now, it's acquire the data, incorporate it all into our planning, see what it means to us. And then the way we typically do it is how it stacks up in our portfolio and what it means to Anadarko going forward versus what the market for it may be. And we constantly do that, and we feel like having the information and a good assessment of what that information tells us that allows us to make the best decision. The Indonesia well, while you mentioned it was an obligation well, this was a well we've been wanting to drill for a long time. So it was not something that we are forced into. We do have two blocks there. The shallow water block, which is the Nunukan block where the discovery was made. And then we have the deepwater block immediately adjacent to it to the east, the Bokep block. We operate the shallow water and Eni operates the deepwater one. We've got the discovery. We'll be shooting 3D on that block because we see a lot more like it, a lot more features like it on the block. So we like to again understand what this means to the overall assessment of the block. And meanwhile, we'll be drilling, or ENI as the operator, will be drilling the Borago prospect, which will be outward on the Bokep block, and that should happen at the end of the year or very early 2011. So a lot of information to be gathered, then we'll put it into our portfolio and decide how it fits with us or perhaps somebody else.

Douglas Leggate - BofA Merrill Lynch

What proportion of your capital right now would say is being spent on your liquids as opposed to gas? And my final one, if I may, just for Jim is, Jim, as the calendar rolls here to 2011, I guess, we're expecting some news on Algeria in terms of the tax arbitration that's going on right now. If you could give us some color as to what we may expect there, that would be great.

R. Walker

Doug, this is Al. I'm not sure we actually look at it quite the way you've asked the question. So I'll probably stumble through the answer a little bit. When you consider the fact that we've got three mega projects that are all oil and they are by themselves about $1 billion of CapEx. And you look at the fact that we historically talk about our onshore or development program being around $2 billion to replace production, I think if you look at just those two in isolation and you exclude exploration from the equation, which is a longer-cycle investment opportunity for us, and we're well above 50% with our capital spend related to oil and liquids-related projects. So as you can see as we move from where we were a year ago, well, most of 40% on our liquids plants to being above 40%, we see that trend in the overall mix continue to go up over the next few years, primarily because of these mega projects coming online and coupled with the redirection that we've had over the last couple of years has brought the industry towards gas with liquids components. I hope that's helpful. I can't give you a whole lot more specificity than that. I just not quite looked at it the way you asked the question.

Douglas Leggate - BofA Merrill Lynch

I guess I should have asked the question a little better. I guess, I was really thinking about the onshore U.S. CapEx, to be honest.

Charles Meloy

Doug, this is Chuck. My sense is it's in the order of 70% or thereabouts. That's going to directly to oil investments. The remainder going to a combination of midstream and gas infrastructure-type investments in and around our developed fields. We're also invested heavily in the Marcellus through the JV, but that's not out of pocket CapEx.

James Hackett

In Algeria, Doug, we've got to be limited in what we say there. As you know, the arbitration is underway. We just have to see what comes up between now and then.

Douglas Leggate - BofA Merrill Lynch

Timing, Jim?

James Hackett

For arbitration?

Douglas Leggate - BofA Merrill Lynch

Yes.

James Hackett

Bobby Reeves is shaking his head. I think, we have said it publicly before that it's somewhere in late 2011 that we're expecting a decision.

Operator

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

David Tameron - Wells Fargo Securities, LLC

Jim, let me start with Algeria. The number in the 10-K from last year was $2 billion. Assuming you could say it, what number should we think of at the end of 2010?

James Hackett

It's roughly $2.4 billion, David.

David Tameron - Wells Fargo Securities, LLC

Moving to Niobrara, can you talk a little bit about -- can you give us a little more color what you've seen? And I know in the ops update, it said you're going to add more rigs next year. But can you give us a little more color there or more detail?

James Hackett

Yes, David. What we've done is we've drilled four vertical wells, test wells, just evaluating our acreage, getting a good idea of the petrophysics around the area. And we drilled one horizontal well. It's really early, but what we've seen so far looks very encouraging to us. And we'll be completing that well and then going into sort of a one- to two-rig program through the balance of 2011 to fill out our data set and make an assessment of the play.

David Tameron - Wells Fargo Securities, LLC

And how many non-op wells have been -- or wells that you have a formed out interest in? Have you seen data from as far as horizontal wells?

James Hackett

Well, I don't know the exact number. It's in the order of 10.

David Tameron - Wells Fargo Securities, LLC

I mean whoever wants to take the last question, I'm just thinking about the Eagleford JV. Most of the other companies seem to do JVs because they have to for capital funding reasons. I look at your balance sheet, it doesn't look like you have to do the Eagleford JV. So can you walk me through if this play is really good as some people think why would you sell it? I'm still struggling with that.

R. Walker

David, this is Al. It's an understandable question, and you're right. Within our portfolio today, it's probably one of the more attractive users of capital. And probably for that reason and also while it gives us very good rates of return, our ability to take what we we'll say is well-above average rates to return within our portfolio and turn then into exceptional rates of return is the motivator. Because of the portfolio, we had the ability to look for production growth, reserve replacement without being dependent about any particular play and being able to capital efficient. And so as a result, if we can get the terms, as Bob made reference to, if we get terms that are acceptable to us, we can take and significantly improve what we believe is the rate of return for the capital deployed into that play. And that's the motivator. It's just almost as singular as that.

David Tameron - Wells Fargo Securities, LLC

But implied in that is that there's somebody taking the other side of that, that's getting, in theory, a lower rate of return, right?

James Hackett

Well, yes. I mean relative to ourselves?

David Tameron - Wells Fargo Securities, LLC

Yes. I mean just by definition. Somebody else is on the other side of that trade.

James Hackett

True. Their alternative is where else could they make that investment on and for the risk associated to get that type of return. We'd like to think that the investor has a very good risk return calculation and balance. Whereas, we take from our perspective and get a much better rate of return without having to use the capital on our case to deploy for development. If you use Marcellus as a bit of a footprint for how we might consider additional joint ventures, whether it be Eagleford or maybe at some point Niobrara or other places, it's just really strictly not being able or having the ability rather not to have to fund that development. We're not really looking to take capital off the table to your point about the balance sheet. This is really not about balance sheet preservation or balance sheet improvement, but rather about improving the capital and its deployment and then its rate of return.

David Tameron - Wells Fargo Securities, LLC

And if I think about total number of wells drilled in the field before you JV it, you mentioned -- I don't know if you mentioned this or this is in my head, but first quarter next year is kind of the target for the JV. I think you drilled 30 wells. You said you've spud 30 wells this quarter. You spud another 30, I think, in the first half so you're at 60. How many more wells do you need to get down before you would JV this?

James Hackett

Actually, if somebody were to hit our terms today, it's not really a timing thing. As Bob made reference, we're really looking for the terms. I think the field's probably got enough history and if the plays got enough. It's not a uniform shale development as we all know at this point. It's a pretty complicated play. Ours has extremely attractive EURs relative to our drilling and completion costs. As a result, we have from our perspective a very attractive, from an investment perspective, case for why somebody would want to come in. So I would say, today, if someone were to meet our terms, we'd probably by anyone's estimation would have enough data to be able to support that. So we're not really looking get to our critical mass of drilling activity to be able to do it and turn to promote it. And so it's really a function when the market decides that if we see terms that we'd like and if we don't, for the reasons I've started with, it's one of the most attractive plays we can put capital in our portfolio, we're not looking to give it away.

David Tameron - Wells Fargo Securities, LLC

One nitpick or one detailed question, Independence Hub, growth volumes have fallen off a cliff, net looks like it's staying flat. Can you just walk me through what's happening there?

Robert Daniels

Yes, David, as you know, our Independence Hub has well outperformed our expectations through the years. Now, it's pushing almost 800 Bcf of cumulative production. We've had a great run. When we started with it, we thought the resource opportunity was around a Tcf, so you would expect by now it we'd be on the decline as we stated. We thought early on it would see a production plateau in the order of 18 months. We extended that quite a bit based upon the work that we've done. What you're seeing now is many of the smaller fields that make up Independence Hub have begun a very steep decline or watered out. In the bigger fields and those fields that typically Anadarko has as a larger working interest in, have been the ones that have maintained their production through time. And so that's gives you that dynamic of gross volumes falling, net volumes essentially falling some, but not near to the degree that the others have.

David Tameron - Wells Fargo Securities, LLC

And just a gross anatomy, you're just supplementing with your own wells as opposed to taking third-party operating wells?

Robert Daniels

Well, the fields, the large deals we have like Cheyenne and those that have essentially 100% Anadarko working interest or the higher working interest fields, are the ones that are still sustaining themselves.

Operator

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

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

Bob, first probably on Sierra Leone, can you compare in contrast the Mercury prospect to the Venus prospect?

Robert Daniels

Yes. David, the Mercury prospect probably has a little better image than what we had at Venus. And the primary objective is the Turonian, which is where we found the hydrocarbons at Venus, even though the Venus objective primarily was a shallower fan. So we're trying to take what we learned at Venus, incorporate that into our exploration efforts at Mercury and beyond over into Liberia, and then meanwhile bring all the things that we're learning from Ghana up into this area. So it's been complex. It's a little bit different to Venus, but we certainly had a better image on the seismic data here and we just need to see what we find.

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

Any hydrocarbon indicators and any thoughts on probability of success?

Robert Daniels

You know, it's an explanatory well, and a basin that's got one other test. So it's obviously got some risk associated with it.

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

And then on the South China Sea update, any details on securing a rig or a timing there?

Robert Daniels

Yes, the timing looks like we're going to spud early December to mid-December. The rig has been secured. They're just in the final stages of getting that rig assignment taking care of, but it's all been done. And so we do anticipate spudding in December, and we're really looking forward to that. Obviously, that's been on our books for a long time and it has been a long drawn out process to get to where we actually get to test the prospect. So we're really looking forward to it.

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

And then, in Indonesia, part of a rig consortium was several deepwater wells. It was in my notes. I mean, the first prospect Eni will drill, is there a follow-up of additional prospects in 2011 in Indonesia as well? Or are they contingent upon each other? Or can you give any thoughts there?

James Hackett

Well, you're right about the rig consortium. It's the Transocean Explorer. And we have the first slot on that. We used it to drill our Padan well done on our Nunuka block. And then it's been with different groups and is coming back to Eni. They'll be using it on the Bokep block for this Baroga prospect. So that rig consortium is -- everybody has different slots on it. We've pretty much used our slots. We don't have a whole lot of obligations left on it. Eni has a couple of other slots. Whether or not they come back on to the Bokep block or go somewhere else, we'll have to see what we find there at Baroga.

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

And then just going onto the onshore program, thinking about the Eagleford, and you talked about rates return. Not trying to read too much in between the lines, but it seems like, are there any concerns over getting the terms you want? Is there some degree of uncertainty around that potential joint venture? Or am I just reading too much into the comments?

James Hackett

David, I'm not trying to send you a signal, that sort of between the lines there. If I was implying that, I apologize. Really, what I was trying to say was that most likely, we're early on with the Marcellus as we went out and looked at it. We had terms by which we were willing to take what we thought was a very attractive asset and find a joint venture partner. I think that same discipline you can expect will be maintained as we look at the Eagleford and potentially Niobrara down the road. Because they have, on their own, very good rates of return at the wellhead. Our ability to be patient because we aren't under balance sheet pressure is one of the reasons why I'm just saying the terms, and what Bob was commenting on, that the terms are more important to us than the timing.

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

And then just one detail on the Marcellus, remaining carry that is left. Can you just update us on that?

James Hackett

Well, we're into a modest spend in '11. We'll give you an update after the first of the year and come back to you with our capital plan. But you can expect that we will be spending at the pace we're on, most of the carry between here and the end of '11.

Robert Daniels

I think in the Q, David, it has a fifth of that being spend so far.

Operator

Your next question comes from the line of Scott Hanold. [RBC Capital]

Scott Hanold - RBC Capital Markets Corporation

So when you are all looking at sort of moving some more activity onshore and obviously with some of the uncertainty with the offshore Gulf of Mexico right now, when you looking forward to I guess 2011 and even through 2015, how does moving a little bit more onshore at this point in time sort of impact your growth and return targets that you've kind of all laid out?

R. Walker

This is Al. I think what you can take from that is that -- and we're generally look at taking things that would have been longer-cycle investing for us and in reinvesting that same capital into shorter cycle, largely liquids, to in some cases very liquids-rich opportunities. So you have very good rates of return with better cycle time. One of the things that we always have to manage because Bob Daniels has so much exploration success that he's had now for several years, is that we have to be mindful of how that longer-cycle stuff can be brought forward is through monetizations, which we've done a lot of since 2006, about $18 billion worth after-tax. We're not really looking at clearly to sell because that's not particularly tax efficient. So as you think about how we're looking onshore, we always like to improve cycle times even when they're short. So again, that promoted aspect of being able to do something that's tax efficient is very important to us. So as we move onshore from an offshore spend, if you think about it moving around that way, we're both enhancing the short-term cycle of the investment as well as moving in into things that we believe onshore gives extremely good wellhead rates of return.

Scott Hanold - RBC Capital Markets Corporation

So if you've got better certainty that you can get active in the Gulf to maybe to the extent you were hoping to be in the 2010, which was I think initially around $1 billion, what would happen with that take from onshore activity? Or that'd just be incremental spend over cash flow potentially?

R. Walker

Yes, I think today, that would be a really difficult question to answer and primarily because we just don't know what the rules of engagement are yet in the Gulf of Mexico and what that's going to mean from a timing standpoint. Yes, the moratorium has lifted, but it'd be well-oiled comment, the de facto moratorium has been placed. How long it takes us to get drilling permits, and how long it takes to actually got exploration permits is a real unknown. So as it relates to 2011 capital spending, we'll talk more about that after the first year. And hope between here and there, we'll have a little more clarity around it.

Scott Hanold - RBC Capital Markets Corporation

Shifting to Niobrara. I think clearly, a lot of variability in the reservoir characteristics and even from the well performance. Is it too early for you guys to indicate what sort of things you're looking for there? Or what you're trying to avoid in some of the drilling?

Charles Meloy

Well, what we're trying to encounter, of course, is an oil-saturated reservoir, and that's the play generally north of Wattenberg. It's in the oil window. We're looking for very good petrophysical properties like permeability and porosity. That's why we drilled the four vertical wells to evaluate a greater area where we didn't have a density data that we felt was sufficient. The kinds of things that have worked when we've seen reasonable, although, that's an undefined term at this point, but reasonable permeability that will deliver the tops of rate that we need to make any good rate of return. There is some indication in parts of the play that there is natural fracturing or fracturing induced by basement movement. We will evaluate each and every one of those geological settings as we move forward through 2011 and determine in our mind, anyway, what the best part of the play is.

R. Walker

And Chuck, let me add that we're using 3D there because we can access 3D at a pretty reasonable cost to help us with those issues.

Charles Meloy

And the other thing I think we have going for in the play, of course, is our land grant. It goes right through the middle of the play. And that gives us an opportunity to play essentially anywhere in the greater play because of our ownership in essentially every other section. And today, we're getting a lot of information in from other operators because of our formats. I think we have around 400 barrels of royalty oil coming out of the Niobrara today. So we're getting good information. We can assimilate that maybe, at least as good as anybody else because of our position. And I think through 2011, you'll see the play mature much like you saw in Marcellus back a few years ago and the Maverick in the last couple of years. And from that, we'll make an assessment on where we want to go and go get it.

Scott Hanold - RBC Capital Markets Corporation

And what do all expect the 3D to show you? I mean, you can't really see fracturing or permeability in that. Is it more of the basement movements you're looking for?

Robert Daniels

Yes, it's the structural texture of the play. Where there's a lot of faulting, there is oftentimes a lot of fracturing. And we're also looking for the different geological settings that may set up an advantaged permeability and porosity relationship that we can work with.

Scott Hanold - RBC Capital Markets Corporation

And one last quick one in the Bone Springs and Avalon, I think you, all said 550,000 gross acre. Do you have sort of an estimate in that number there?

Robert Daniels

It's around 40% or so of that is net acreage depending on what area you're in. We have a JV with Chesapeake in much of the area. And as you go south, we have roughly 40%. You go north, we have roughly 60%. So the average is in the 40% to 50% range.

Operator

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

Brian Singer - Goldman Sachs Group Inc.

Can you talk to how many wells you have in backlog in the Eagleford, Haynesville and Marcellus shales? And how you see that inventory changing over the next year as you both increase drilling activity and bring on new infrastructure?

Robert Daniels

Brian, could you help me out with what your definition of backlog is?

Brian Singer - Goldman Sachs Group Inc.

Wells that would be drilled but either are not completed or not tied in?

Robert Daniels

Today, we currently have about 50 wells in the Maverick that we're in the process of drilling or completing or tying in. So we have -- and roughly 50 that are online. So about 50% of our wells are now in that condition. With regard to the Bone Springs, we have about 20 wells that are in some state of either drilling, completing or tying in. And in the Marcellus, I would venture to say we have roughly 100 wells, maybe a few more than that, that are also in that same condition. And essentially, it's just a matter of getting the -- most of that is getting the infrastructure built to the wells so we can tie them in. We're not holding back on the completions for price or anything like that. It's just that these plays are in sort of a startup mode. And it just take some time to get all the equipment to the well to get it in the sales process.

Brian Singer - Goldman Sachs Group Inc.

And I guess if we fast forward 12 months, where you brought on new infrastructure but you've also drove a lot more wells, do you think that the inventory in those three plays will be meaningfully down, the same or up from here?

Robert Daniels

My sense in the Maverick and Bone Springs, it should be similar even though -- and the reason is because we'll be increasing the number of rigs that we're using. And that will keep an inventory along those lines. In the Marcellus, I think our inventory will come down pretty sharply as you go through the course of the next six months, as we commission and put online a number of different systems, gas gathering and gas systems in the Marcellus.

Brian Singer - Goldman Sachs Group Inc.

And maybe that partially answers my next question, which is given that you're not drilling that many gas prospects right now. How should we expect the trajectory of your gas production from here over the next year or two years, especially if you do see the Independence Hub starting to fall off at some point.

Robert Daniels

You know what, I think it's going to be flat to slightly up. But again, we'll give you guidance for '11 onwards, starting early next year.

Operator

Your next question comes from the line of John Herrlin from Societe General.

John Herrlin - Merrill Lynch

With Mozambique, what would the threshold be for commerciality for an LNG play?

Robert Daniels

John, Bob Daniels. We've down some initial work on that, and we think that you need be over 3 to 4 Tcf to have a minimum commercial development. And of course, we think the potential to be well over that. We've got to drill much more wells and see what everything works out there. But there's a lot of gas up in the northwest, further northeast corner of that block particularly. And we think we've got a lot more activity to prove that up. But we're pretty confident that we will have commercial volumes there, or at least that minimum threshold net. So that's our starting point, and now we're out there trying to either prove up new wells or plays we've already found while maintaining some exploratory wells in between.

John Herrlin - Merrill Lynch

With Badik in Indonesia, you said you found gas and oil. Any sense of how gassy or how oily that prospect was?

Robert Daniels

I'd say it was probably a little more gas than oil, but we don't have the final numbers on it and then how rich the gas is. We're going to have to get our analysis back.

John Herrlin - Merrill Lynch

With the Niobrara, say you don't have great fracture porosities, is matrix porosity enough to give it a go?

Robert Daniels

John, what the early data suggest is that you can make some pretty decent rates out of reasonable perm and porosity, matrix perm and porosity. And we have quite a few Niobrara wells in Wattenberg proper that are in the oil window or in the high condensate-rich window. And they have very little fractured permeability. And so our sense is that, yes, we can make some decent rates as long as the matrix is good.

John Herrlin - Merrill Lynch

Some accounting-type questions. You accelerated DD&A in the Gulf of Mexico. Any particular projects?

John Colglazier

Yes, John. This is John Colglazier. We had a well water out, one of the Atlas wells going into Independence Hub. So it was an acceleration of DD&A on it. So basically, just a change in estimate that we accelerated DD&A on.

John Herrlin - Merrill Lynch

You reversed your Tronax accrual. Are you done with that lawsuit? Is that it?

Robert Reeves

John, this is Bobby Reeves. No, we're not done with that. We're still in the middle of an adversarial proceeding there. That just relates to a cancellation or rejection of a master separation agreement that was part of the bankruptcy proceeding there. I think we've explained that in the 10-Q filed last night. It should give you the details on that.

Operator

Your next question comes from the line of Mark Polak. [Scotia Capital]

Mark Polak - Scotia Capital Inc.

First on Mozambique and the discoveries there, as you look at commercialization options early days but does it look like LNG is a viable option there? Or would you be looking more at a local market or maybe pipeline down to South Africa?

Robert Reeves

Bob again. Of course, we've looked at all the different options and tried to assess what local market there may be. But LNG is certainly is the one that we're focused on because that's something we understand. Our partnership was actually kind of set up strategically because of the potential for finding gas out here. We have Mitsui as a partner, of course, who is a big LNG player. Bahrat, out of India, is part owner of the regas facilities on the West Coast of India. So we do have a good partnership there that has access to markets and understands the LNG business. And of course, our experience with the Bear Head terminal gave us good experience. The key thing about the LNG is that it is indexed oil prices. And so you've got to think of it differently than North American gas pricing and look at where you think oil is going to go and then run your economics based on what percentage of oil price you'll get for the gas.

Mark Polak - Scotia Capital Inc.

In Ghana, with the success at Owa and Tweneboa and looks moving fairly quickly to sanctioning next year, does that have any implications for next phase Jubilee? Could you do both projects concurrently, or would that sort of push out the next phase of Jubilee a bit?

James Hackett

Well, we are hoping to sanction both Owa and Tweneboa next year and with our operator, Tello. And with regard to Jubilee, what we're hoping to do there is, of course, we're going to get the facility online later this year. And then get the data that we need to make a determination what and when do we do a Jubilee Phase 2. The initial sense is that we'll see some really good results and that the timing of that Phase 2 will be within a year or two of first production.

John Colglazier

I really appreciate all the questions that everybody has asked. We might end the call now and just ask anybody that still has questions to please call into John Colglazier and our Investor Relations staff, if you wouldn't mind, just to get people on to other business. We obviously look forward to talking to you all in the new year. We appreciate very much your support and attention today and hope you have a great day. Thank you.

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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