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Anadarko Petroleum (NYSE:APC)

Q2 2010 Earnings Call

August 04, 2010 9:00 am ET

Executives

Robert Daniels - Senior Vice President of Worldwide Exploration

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

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

R. Walker - President and Chief Operating Officer

John Colglazier - Vice President of Investor Relations & Communications

Charles Meloy - Senior Vice President of Worldwide Operations

Analysts

Philip Dodge - Stanford Group Company

Brian Singer - Goldman Sachs Group Inc.

Subash Chandra - Jefferies & Company, Inc.

David Tameron - Wells Fargo Securities, LLC

David Kistler - Simmons & Company

Diane Jaffee

Douglas Leggate - BofA Merrill Lynch

Joseph Allman - JP Morgan Chase & Co

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

Rehan Rashid - FBR Capital Markets & Co.

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter 2010 Anadarko Petroleum Corporation Earnings Conference Call. My name is Michael, 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 conference, Mr. John Colglazier. You may proceed.

John Colglazier

Thanks, Michael. Good morning, everyone, and welcome to Anadarko's Second Quarter 2010 Conference Call. Joining me on the call today are Jim Hackett, our Chairman and CEO; and other executives who will be able to answer questions later in the call. As we've done in the past, we have posted supplemental information in our operations report that is available on our website.

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 this time. However, a number of factors could cause actual results to differ materially from what we discuss. You should read our full disclosure on forward-looking statements in our presentation slides, our latest 10-K, other filings and press releases for the risk factors associated with our business. In addition, we'll reference certain non-GAAP measures, so be sure to see the reconciliations in our earnings release and on our website. We encourage you to read the Cautionary Note to U.S. Investors contained in the presentation slides for this call.

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

James Hackett

Thanks, John. Good morning, everyone. I'm pleased to share with you the second quarter operational achievements. And then later in the call, we'll provide an overview of our financial results. I'll also express our thoughts regarding the tragic Deepwater Horizon events in the Gulf of Mexico.

Anadarko delivered strong results consistent with its business objectives during the second quarter. We increased quarterly sales volumes by about 6% year-over-year, continued to focus on our margins and achieved significantly lower lease operating expenses, expanded the success of our onshore shales and unconventional assets, set production records in many of our major asset areas while increasing capital efficiencies, achieved further drilling success in deepwater with positive appraisals at Lucius and Vito in the Gulf of Mexico and a Jubilee area in Ghana, and reached significant milestones with our sanctioned mega projects with all three remaining on schedule and on budget.

As reported in last night's earnings release, our producing assets delivered total sales volumes of 59 million barrels of oil equivalent for the quarter, including a 16% increase in liquid volumes year-over-year. This growth was driven by our shales and unconventional place both in the Rockies and in the Southern and Appalachia regions. The Rockies delivered sales growth of about 10% relative to the second quarter of 2009, with NGL sales increasing about 70% and crude sales about 20%. The Greater Natural Buttes area, Wattenberg, Salt Creek, Monell and the Wamsutter field all reported operating production records during the quarter.

With a focus we have in liquids-rich plays, Anadarko is taking steps to ensure its ability to fractionate and transport NGLs by entering into a six-year 62,000 barrel a day agreement. This provides firm capacity for NGL production from the Rockies in Texas, as well as access to the Gulf Coast markets.

Focusing upon the shale plays they experienced significant growth in average daily net sales volumes from 7,600 barrels of oil equivalent per day in the first quarter of this year to 13,300 barrels of oil equivalent per day in the second quarter.

We continue to effectively manage the cost structure across the company as well. Lease operating expenses of $3.32 per BOE was a 15% improvement over the second quarter of 2009. As I mentioned in our last conference call, these efforts to reduce LOE have made us one of the most efficient producers in our peer group. On to our efforts to safely improve spud-to-spud cycle times have led to many field setting new drilling time records, including seven different asset areas just in the Southern and Appalachia region.

I want to especially highlight the tremendous progress the E&P teams have made in our shale plays. Starting in the Maverick Basin in South Texas, we've transitioned the Eagle Ford play from an exploration effort to a full scale development project. Our wells have a high liquids content, comprising about 75% of the revenue stream and due to the high capital returns it delivers, this has become an area for increased capital deployment. The cost to drill these wells is about $4.5 million per well, with estimated ultimate recoveries of more than 300,000 barrels.

In addition, we're starting to see drilling and completion costs trending downward, as we move to multi-well pad drilling and optimizing our completion configuration. Based on these results, we've ramped up our development program to six rigs. There is significant running room in this preferred portion of the play with a potential to drill more than 2,000 Eagle Ford wells on the 400,000 gross acres that we control in the Maverick Basin.

In the same acreage, we are also evaluating the deeper Pearsall Shale, which is a dry gas play and represents additional option value. Our Eagle Ford activity will allow us to hold these Pearsall opportunities and enable us to capitalize in the future when this natural gas investment option becomes more competitive within our portfolio. Given the tremendous value we see for the Eagle Ford/Pearsall play, Anadarko is evaluating another joint venture similar to the one we completed in the first quarter in the Marcellus. And we anticipate having something to announce before year end.

Our Marcellus pace continues to accelerate as well. We're currently running six operated rigs, and 15 non-operated rigs and the 760,000 gross acres in which we participate or have control of in this play. We're seeing significantly improved cycle time and excellent estimated ultimate recoveries consistently above four BCF per well.

Peak production during the quarter reached about 140 million cubic feet a day, gross from 35 wells, with another 100-plus wells awaiting either completion or connection to the gathering system. We expect to have taps in place for about 1.2 BCF per day and total gathering capacity of more than 700 million cubic feet per day within the next year.

With consistent results today across this large acreage position, we estimate the captured resource potential on our Marcellus acreage at well over 1 billion barrels of oil equivalent, on a risk basis net to our interests. We're continuing to pursue several other opportunities with a liquids focus, which have produced very encouraging results and are worth highlighting as well.

In the Bone Spring play of West Texas, we are now running four rigs and our 540,000 gross acre position in the area. We're early in this play and are already seeing some initial production rates of more than 1,000 barrels of oil per day, with natural gas that has a high BTU content as well as good market taxes. This play also offers significant running room when combined with the potential for the overlying Avalon Shale where we should have our first results by the end of this month.

Another emerging area for Anadarko is the Horizontal Niobrara, another oil-focused play in Northeastern Colorado and Southeastern Wyoming. We plan to drill six to 10 operated wells beginning in the third quarter, now that we have gleaned important information in our greater than 500,000 gross acreage position from prior farm-outs. Much of this acreage is in the land grant where we hold the mineral rights and perpetuity. We've been shooting seismic and acquiring leases that give us a commanding acreage position that is incremental to our 550,000 acre position in the Wattenberg field, where we have been producing in the Niobrara formation for many years.

Our sanctioned mega projects continue to progress on schedule and on budget. During the quarter, we reached some major milestone in Ghana where the FPSO arrived in late June. It was moored on location over the Jubilee field. Completions in subsea installations are underway, and we expect first production by the end of this year.

In the Gulf of Mexico, we expect to achieve first production at Caesar/Tonga by the middle of 2011, after completing all the heavy topside list during the quarter and continuing the subsea installations. We're hopeful to receive the necessary permits to perform completions on our three wells later this year.

In Algeria, the El Merk project is approximately 50% complete. During the quarter, we drilled five additional wells and construction continued to progress. The construction project is entering an important stage where on-site activity is accelerating. First production is scheduled around the end of 2011. In total, we expect these three projects to add approximately 60,000 barrels of oil equivalent per day, net to Anadarko by 2012.

In addition, these three sanctioned mega projects we are hard at work through exploration and appraisal drilling to bring the next generation of mega projects to development. This includes the Lucius field in the Gulf of Mexico where we announced that the appraisal well encountered more than 650 net feet of pay in the Pliocene. Drilling had to be stopped as a result of the deepwater drilling moratorium before penetrating the Miocene, which had between 125 and 215 net feet of oil pay in the two previous Lucius wells. With the information gathered to date, we have initiated preliminary front-end engineering and design work that will continue during the moratorium. We operate Lucius with a 50% working interest.

Also, in the Gulf at Vito, we were very encouraged by the interim results of a second appraisal well, which encountered approximately 250 net feet of pay and a shallower Miocene reservoir which was not hydrocarbon bearing in the previous wells. Operations to evaluate the main Miocene pay section of this location were also suspended as a result of the moratorium. The Vito appraisal program is operated by Shell, and we hold a 20% working interest.

During the quarter, we also completed two wells at the Independence Hub facility. The first, the Merganser #3 sidetrack, was brought online in July, and we expect to bring the second Callisto online toward the end of the year. We remain ready to resume an active and safe deepwater to Gulf of Mexico drilling program once we receive the necessary authorization and operational clarity from the federal government. In the meantime, we've continued our deepwater drilling program internationally and achieved appraisal success in Ghana where the M-5 well encountered about 75 net feet of pay and extended the Jubilee field further to the south and east.

Last week, we announced an additional exploration discovery in Ghana at the Owo prospect. The Owo-1 well is located approximately four miles west of the previous Tweneboa discovery and encountered approximately 174 net feet of high-quality oil pay. Preliminary data indicates that this is light oil with a gravity of between 33 and 36 API.

Now the partnership will expand its already active appraisal program at Tweneboa to include Owo as we work to mature both of these fields towards sanction early next year. Additionally, the Owo discovery provides even more validation of the quality of our geologic models and the prospectivity of Anadarko's 8 million acre position in the West African Cretaceous Fan play, where we've identified more than 30 prospects and leads with size and geological characteristics similar to Jubilee. As part of our ongoing program in Africa, we are planning to mobilize the deepwater millennium drill shift from Brazil to West Africa in order to drill our second test offshore, Sierra Leone, and then the rig will assist with the appraisal programs with Tweneboa and Owo.

During the quarter in Brazil, we successfully flow tested the Wahoo#1 well and based on the results of this test, we believe the well is capable of flowing in a sustained rate of more than 15,000 barrels per day. However, our efforts to flow test the Wahoo#2 well yielded inconclusive results. We elected to move the drill shift five miles to the south of the Wahoo#1 discovery well to drill the Wahoo South exploration well, which is our third test in the BM-C-30 block, where we operate with a 30% working interest.

Also, in Brazil, we recently spud a post- and pre-salt test at the Itauna prospect on BM-C-29. Anadarko operates this prospect with a 50% working interest. In addition, Devon has also notified us that the first appraisal well, the Itaipu, in BM-C-32 is expected to spud in the third quarter. We hold a 33% working interest in Itaipu.

In Mozambique, we are currently drilling the Ironclad prospect, which is approximately 70 miles of our Windjammer discovery in the Offshore Area 1 of the Rovuma Basin. Once the activity is concluded, Ironclad rig will move back to the Barquentine prospect for an Oligocene test as well as an appraisal of the Paleocene accumulation identified at the Windjammer discovery.

We also continue joint activities at the Badik prospect from the Tarakan Basin of Indonesia. The well is being drilled toward a proposed depth of approximately 17,400 feet in order to test a large three-way fault closure in the Miocene. Anadarko operates Badik with a 35% working interest.

As you can tell, we expect to continue the active exploration and appraisal program during the second half of the year and remain confident in reaching our stated goal of discovering more than 400 million barrels of net resources during the year from exploration activities.

Turning to our financial results for the quarter, we reported a net loss of $0.08 per diluted share with certain items affecting comparability to decrease net income by $0.57 per share. Absent these items which are typically excluded by the investment community, our net income would have been $0.49 per diluted share as reconciled on Page 7 of last night's earnings release. We have not recorded a contingent liability associated with the Deepwater Horizon event based on applying accounting guidelines to the facts as they are known today. We expanded the disclosures in our second quarter 10-Q release yesterday and encourage you to use this document for a detailed description.

I know that the Anadarko team feels a profound sense of sorrow over the Deepwater Horizon tragedy. We've all gained a measure of guarded hope this morning that last night's static kill operation is reported to have been successful. And we, along with others in the industry, continued to support the recovery efforts of Unified Area Command.

During the second quarter, we issued a news release clearly stating our position with regard to the liabilities for the Deepwater Horizon tragedy under our joint operating agreement. There are numerous ongoing inquiries and independent investigations that must be brought to conclusion. However, the information and findings that have been made public to date continue to reinforce our belief that serious errors in judgment occurred that have direct implications on the obligations of parties under the operating agreement.

As I told you at Senate subcommittee two weeks ago, any actions we have taken or may take under the joint operating agreement to protect our rights, shall in no way affect our commitment to meet our obligations under applicable laws. To its credit, BP has continued to make good at its commitment to pay all legitimate claims and we expect that to continue. It is in the best interest of all stakeholders in this tragic event. We also reassured the subcommittee that our balance sheet remains strong.

During the quarter, we generated approximately $1.3 billion of discretionary cash flow while spending a little less than $1.4 billion on our capital programs. The company ended the quarter with approximately $3.4 billion of cash on hand. Subsequent to quarter end, Anadarko sold its Wattenberg gathering system and related facilities to Western Gas Partners for approximately $500 million, providing net cash proceeds of approximately $450 million to Anadarko.

In an abundance of caution yesterday, we also announced that we've taken steps to further enhance our long-term liquidity position by obtaining firm commitments for a new secure $5 billion five-year committed credit facility and for a secured $1.5 billion six-year term loan. Upon closing, this will replace our shorter-term credit facility with a substantially larger and longer-dated facility and will refinance our existing midstream note that is currently scheduled to mature in 2012.

In closing, the strong results of the second quarter demonstrated that the moratorium does not impact at current production or near-term guidance. We have continued to redirect capital from the Gulf to other areas of the portfolio such as the Eagle Ford Shale and the Bone Spring areas in our onshore portfolio. Primarily as a result of the strong operational performance from these and other liquids-rich assets, we are increasing our full year sales volume guidance and now expect to produce between 232 million and 236 million barrels of oil equivalent. This represents a 5% to 7% increase over 2009 production without increasing the capital spending projections from our March Investor Meetings.

As in the past, we are providing a risk production profile and correspondingly our third and fourth quarter sales volumes guidance is reflective of historical weather and facility-related downtime. We also remain focused on achieving our longer-term objectives that we outlined for you at the March Investor Conference. I'm very proud of the results are employees delivered in the second quarter and pleased with the way this performance has set the stage for additional growth from our mega projects and continue the E&P success in the future.

And now I look forward to answering your questions. So Michael, if you could open up the phone lines.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

Can you talk a little about what you're seeing in West Africa on the cost front and in terms of rig rates and overall costs, and then to what extent the increased supply of rigs could have an impact on future well costs?

Charles Meloy

Brian, this is Chuck. Our costs to date have been fairly constant. We haven't seen much variability so far, although depending upon how long the moratorium lasts, I think you could see an increase in rig activity moving toward West Africa, which should have a downward slope on the price.

Brian Singer - Goldman Sachs Group Inc.

Do you expect to be able to capitalize on that? Or how are your contracts structured in terms of term? Or do you ultimately see this as a bit of a blip and costs will continue as they've been?

Charles Meloy

Well, with our activity today, I don't really see that it will impact as much. Depending upon how successful our program is along that margin, as we begin our appraisal phase, we may have more rig activity and at that point we could potentially capture some gains.

Brian Singer - Goldman Sachs Group Inc.

Shifting to the Marcellus, you talked about a 7.8 MMcf a day at 24-hour rate. Can you add a little bit more color on the lateral length, number of frac stages and any takeaways from that well and your expectations for future IPs and EURs?

Charles Meloy

Well, Brian, we continue to have great success in the Marcellus. We've had several wells that have IP-ed on flare [ph] in the range of 7 to 8 million cubic feet a day. That's just one in particular. What we've been doing generally is drilling wells with 4,500- to 5,000-foot laterals, been frac-ing them in the range of around 15 stages per well. We've continued to test how many stages and which lateral length we'd like to do, trying to optimize the economics. So we haven't settled in on any particular design and configuration at this point. If you look forward on the takeaway, I believe that was the second part of your question, if we look forward on the takeaway, we have a lot of construction going on in the field connecting to major pipelines. Most of that construction should start wrapping itself up in the fall of this year and then early next year. And so what you'll see with our production will be increasing it substantially toward the fourth quarter and into the first couple of quarters of 2011.

Brian Singer - Goldman Sachs Group Inc.

Any initial expectations for the Badik well? How significant in Indonesia is that well for the overall program?

Robert Daniels

Yes, Brian, Bob Daniels here. Badik is an exploratory well and in the international arena, we typically look for 100 million barrel plus, 125 million barrel plus targets so it is a big target. It's opening up a new play type or would open a new play type in that area, the Tarakan Basin, and of course, we're drilling it on the shelf. So this is a shallow water well, but we have the outboard portion under contract and that's where we'll be drilling our Baraga well later in the year. So there's a lot of potential out there. It's still too early to say, of course, about the well, but it's a significant exploratory well and it can set up some additional running room on that block and then prove up some things outboard.

Operator

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

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

Can you give us some update on your assessment post appraisal for the resource size at Vito and Lucius?

Robert Daniels

David, Bob Daniels again. I think we've put some numbers out there. There are over a couple of hundred million barrels for each of those. Of course, with most recent appraisal, the Vito appraisal, we found a fan that have been wet in the previous down dip wells with hydrocarbon in it. That's been added in. So those numbers are getting bigger as we go along. But we feel comfortable that we've got several hundred million barrels at least in each of those.

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

And even with the moratorium, do you think you could move those projects towards the sanction this year or next year?

Robert Daniels

I'll let Chuck handle that.

Charles Meloy

David, we're going through the pre-feed engineering for each of those two projects. And we're hopeful that with the moratorium, we can move them forward. Ideally, we'd like to go out and do additional appraisal on those, and so we'll just play it by ear for now.

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

And then just to make sure I have this right, around Jubilee, you have first production late this year. Liftings will be potentially late first quarter, early second quarter, as we think about where you all are in schedule. Is that correct?

Charles Meloy

That's correct, David.

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

And then just kind of South China Sea, and kind of the availability of CNOOC [China National Offshore Oil Corporation] acquiring a rig, any update on status there?

Robert Daniels

Bob again. CNOOC does have line on a rig and they're in negotiations on it, and I think they could actually sign it at any time. What we're trying to do is finalize the agreement we have in place with CNOOC and make sure that we have a wellbore design prior to locking themselves into a rig slot on that rig. So as we finished the work, they'll lock a slot in. We still look like -- the fourth quarter would be about the earliest, but we do think that we'll get a well spud this year.

Operator

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

Douglas Leggate - BofA Merrill Lynch

I guess the first one is a follow-up on David's question, I guess, regarding the Gulf of Mexico. In the event that you're not able to get back to drilling further appraisals, and I guess putting a development plan together for some of the Gulf of Mexico assets, what does that mean for your capital plan for 2011? How will you reallocate capital and ultimately if you have to delay sanction, what does that mean for your free cash flow as we look forward?

R. Walker

Doug, this is Al. I think what you could expect is this quarter -- now we've announced that we're moving about 100 million through the balance of the year onshore in two areas like the Maverick Basin, Bone Spring area and the Wattenberg field. So for '11, I mean for '10, you can kind of see where we're moving through the balance of this year. I think as we look into '11 and '12 at this point, until we understand what the sort of terms and rules of engagement are in Gulf of Mexico, it's a little early to start telegraphing where we may be, in fact, spending money. But if we do get into a situation where we're not allowed to go back to work in the Gulf of Mexico. The good news is, I think, we've got a lot of onshore plays to go invest that either have very good oil and/or liquids content to the gas stream that should allow us to get really good returns on the capital, Doug.

Douglas Leggate - BofA Merrill Lynch

I guess, a related question is, you've, I guess, declared Force Majeure on a bunch of your rigs in the Gulf. In the event the moratorium is lifted, how are you positioning or how do you expect to be positioned in terms of resecuring rigs, the rates you would expect? If you could just kind of update us to what you would think about there. And I guess a related question, why not move some of these rigs internationally to accelerate some of your exploration there?

Charles Meloy

Doug, this is Chuck. On the Force Majeure, as you are aware, we've declared the Force Majeure and as the moratorium is lifted and permits are issued and that's the key point, I believe, is we'd actually need to achieve permits from the BOEM [Bureau of Ocean Energy Management, Regulation and Enforcement]. And once we achieve those permits, we'll go back to work with the rigs we have under contract. I wouldn't speculate on what might be done with regard to those contracts at this point. And with regard to the international assignments, we have two rigs -- two floaters that are working internationally. And it's not a quick process, as you can imagine, with budgets and approvals and importation et cetera, to move any or all of those rigs internationally.

Douglas Leggate - BofA Merrill Lynch

Okay. Just jumping to Mozambique, Ironclad, can you give us a little bit more color as to where that prospect is right now in terms of progress? My understanding was you might be close to testing. Some updates and maybe a little more color as to whether that was confirmed as a liquids target would be great.

Robert Daniels

Yes, Doug, Bob Daniels again. The Ironclad's drilling and we haven't made a lot of progress here lately. We've got into a situation where we've got some current, some deep-sea currents, that are above the riser, and so we're just waiting until those currents dissipates so we can get back to drilling. So we're kind of on standby as we haven't made a lot of hole here recently. I would look for probably in the next month to be hearing something about that, but we do need the sea state conditions to calm down a little bit, so that we can actually get the drill pipe and hole and continue on drilling. But the prospect itself was 70 miles to the south. We're looking at a different, potentially different thermal regime, which would give us more potential for liquids, and we'll see what kind of results we have. Of course, this is through exploration out here, so everything we're doing is based on inferences and hypotheses. And we will get the data and roll that into our program going forward. But about a month on that, then we'll move up to Barquentine, which is just outboard of the Windjammer discovery.

Douglas Leggate - BofA Merrill Lynch

But if the appraisal on the Windjammer lower section works, from what you know right now, what would that mean for the potential commercial -- declaring that as a commercial discovery of Windjammer?

Robert Daniels

I think that what you got understand up there is, that we've got a seismic character that was proven up with the Windjammer discovery, that we can now go to the other prospects around us and kind of derisk those prospects. So we've got some fairly good confidence that we've got a lot of gas up in that area. Now the actual volumes of it and what the commercial terms would look like to get it out of there, that's going to take a lot of work. But it will certainly help, it will prove up additional volumes and give us the additional confidence in that seismic character. And then beyond that, we've got a couple of more wells, exploratory wells that we're going to be drilling after Barquentine. We expect that rig to stay in Mozambique probably through at least midyear next year, and that'll be on exploration and appraisal wells. Exploration all over the block, and appraisals particularly up in that Windjammer area to try to prove up those volumes.

Operator

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

Joseph Allman - JP Morgan Chase & Co

Could you describe the process to get approvals for doing the well completions in the Gulf and the developments in the Gulf? And how does that process, as it's going now, instruct you that how the process might go when you actually are permitted to start applying for drilling?

Charles Meloy

Joe, this is Chuck again. The process, of course, is, as has been in the past, we submit permits to the DOEM. They, of course, take under consideration those permits and issue them once we've met all the standards. The only difference that's been applied to date has been the certification of the BOPs [blowout preventers], which is underway on every rig in the Gulf of Mexico right now. And once that's achieved, we hopefully will get our permits. There have been several permits issued recently for completion, so the process is working. I'm sure there's a big stack of them in their offices right now as many rigs are idled, as you're aware.

Joseph Allman - JP Morgan Chase & Co

And Chuck, is that a much longer process than it was traditionally?

Charles Meloy

Joe, it's hard to say so far since -- we're just now getting started.

Joseph Allman - JP Morgan Chase & Co

Okay. And then just a separate question, in terms of this incremental Eagle Ford Shale JV, what was the thinking behind doing that incremental JV?

R. Walker

Joe, this is Al. I think what we see there is the same opportunity that we saw in the Marcellus where we could use what we had done early on through the very successful exploratory and early development drilling, take something that had very good rates of return and turn them into even better rates of return through the use of additional capital. I might let Bob Gwin amplify on that just a little bit because it's really his groups that are working on the joint venture.

Robert Gwin

The only thing I would add to it is, that it's obviously something that worked really well in the Marcellus. It enables us to drill a significantly greater number of wells in a shorter period of time given someone else bringing their capital to the table. And as Al mentioned, it takes your returns very, very far north and is a, we think, a really bright business decision as a way to manage our business in these high growth areas.

Operator

Your next question comes from the line of Diane Jaffee with TCW.

Diane Jaffee

I was wondering if you could just update us on your dividend policy. And it's been -- if you go to more production, would there be the possibility of increasing the dividend's payout ratio over time?

Robert Gwin

Well, obviously, that's a decision for the board to make and yesterday, they declared a dividend of $0.09 per share, which is consistent what they've done for the last several quarters, which equates to about $45 million a quarter. And I think we'd have to defer to them in the future. Obviously, things are going very, very well. Performance has been very strong. And we're cash flowing somewhere in the $5 billion a year range at strip prices. So it's something they would consider, but they have to look at the overall business model and decide what the best approach is.

Operator

Your next question comes from the line of John Herrlin [ph] of Société Générale.

Unidentified Analyst

What's the gravity of oil from the Wahoo#1 well?

James Hackett

Wahoo well was around 30 API.

Unidentified Analyst

Okay. What kind of gain are we looking at for on the sale of the gathering assets in Wattenberg?

John Colglazier

Yes, John, this is John Colglazier. It will recognize the gain, but bear in mind that we mark these to market in the Kerr-McGee acquisition back in 2006. So it'll be a fairly rational reasonable account on that.

Unidentified Analyst

Okay. With respect to Niobrara, why not horizontals in the field proper like on the old HS acreage or Kerr-McGee acreage that you have rather than your fee acreage?

Charles Meloy

John, we are evaluating actually doing that. We do have two wells already drilled and several years ago, that were horizontal wells inside the field proper. They performed fairly well, and they weren't done with today's technology. They were short laterals with few stages, but given the amount of horizontal and the stages they have, they did perform well and in line with much of what we're seeing in and around the area to date. So we're excited about that opportunity. Of course, you know it's densely drilled inside the field proper, so the placement of those horizontals take great care.

Unidentified Analyst

What about Codell, same thing?

Charles Meloy

Same thing.

Unidentified Analyst

Okay. With Indonesia, could you give us kind of a postmortem? It had been no successful as far as -- I'm wondering what you're thinking about the program there.

Robert Daniels

John, this is Bob Daniels. We've got, really, our program in the deepwater kicking off this year. Pancang was a dry hole that was in our quarterly ops report. We were drilling an exploratory, a truly exploratory play where we're testing some Miocene targets outboard of some existing gas production, and that play didn't work. And so we know that, that area doesn't work on the block. The inboard portion of it where we do have the gas prospects still looks to be prospective. And then up in the Tarakan Basin where we're drilling Badik, we'll be drilling Borago later. And the Borago exploratory test will be on the block that has the Aster and Tulip discoveries on it. And what we're trying to do there is get into more continuous sands. Both of the previous discoveries were in the slope deposits and so we had discontinuous sands. We can get downdip to get the continuous sands, probably Borago, and updip to get the shale full sands in Badik. And so we'll see how that all plays out.

Operator

[Operator Instructions] Your next question comes from the line of David Cameron (sic) [David Tameron] of Wells Fargo.

David Tameron - Wells Fargo Securities, LLC

Eagle Ford, you mentioned in the press release the infrastructure's keeping up with production. Can you -- obviously, the round's well ahead, others are struggling with infrastructure. Can you talk about what you see, like, over the next back half of this year and into 2011?

Charles Meloy

David, this is Chuck. We've had great success out in the Eagle Ford. Thanks to our exploration team for getting us moving on this project. We've scattered our wells from southwest to northeast in our position and had good success across our entire acreage position, which is approaching 400,000 acres. What we've done -- because this is just very big type of production, very little infrastructure area. From the beginning, we looked at a backbone type of infrastructure build where we installed gas, oil and water pipelines throughout the field to gather our production. We secured contracts to export our gas into the enterprise system and are now looking at various ways to export our oil. Because of the way we've put it together, we have some nice connection points for these midstream enterprises to come, midstream folks to come connect to us, and it should give us a great commercial position going forward.

David Tameron - Wells Fargo Securities, LLC

So am I hearing that you don't anticipate any infrastructure issues in the second half of the year?

Charles Meloy

I don't see any right now, Dave.

David Tameron - Wells Fargo Securities, LLC

And can you talk about current well costs? You mentioned their average spud in the release of, I think, 14 days. Can you talk about what that means as far as dollars?

Charles Meloy

Our average has been around 4.5 million drills complete, equip and connect, and that is dominated by the completion side. We are running 15 stages or thereabouts in many of these wells. Again, we're optimizing how many stages and how much sand to put in each well, but that's been the dominant cost in these wells is the completion in.

David Tameron - Wells Fargo Securities, LLC

Okay. And obviously, a lot of talk in the industry about frac costs, frac crews tightness, completion, tightness on that side. Can you just talk about what you're starting to see? I know you're a bigger player and I assume you're going to say you have more leverage than the smaller counterparts, which I assume is true, but can you just talk about what you're seeing?

Charles Meloy

We're seeing some pressure on prices, particularly in the areas that are really hot like the Maverick, the Haynesville and the Marcellus. However, because of our size of scale, we've been able to get good deals and longer-term deals, and we continue to develop additional vendors to help supply and make sure there's ample supply of equipment and sand, et cetera, to do our work.

David Tameron - Wells Fargo Securities, LLC

Permian, you gave us the high rate. Can you give us the range of what recent wells, what recent completions have done out there?

Charles Meloy

That's in the Bone Spring's out in West Texas, I believe you're referring to. Our average has been around 500 to 700 barrels a day from the beginning. What we're seeing is, that moving up with tying with recent wells, as mentioned in Jim's comments, of over 1,000 barrels a day. So again, this is an optimization effort where we're learning how to drill the laterals, which dimension, where in the section and the type of completions, configuration. As we learn all of that, our rates have been moving up.

David Tameron - Wells Fargo Securities, LLC

Okay. Maybe this is an Al question, but to get to the low end of your CapEx guidance, as you guys reiterated, it looks like you're ramping in 3Q, 4Q. And I know you're running a few more rigs you did it in the first part of the year. Is that fair or do you feel right now that the low end of your guidance is still too high?

R. Walker

Well, David, that's a hard one for me to give you a real good answer. I can give you a best guess and that is, we don't see any reason to think we're going to be outside of our range. And depending upon the timing of wells drilled and certain of these exploration wells when we actually spud, we see no reason to think that the range, as we know it today, anything better than a good guess and a good expectation. Yet for some reason, some of the exploration wells that Bob's talked about didn't get spud in late third quarter, early fourth, and that's probably the reason that expect that to go to the low end of the range. But we would prefer to have them spud and be inside the range of the spend.

David Tameron - Wells Fargo Securities, LLC

Okay. Let me take that one step further to 2011. I know you said there's a lot of uncertainty, but can you talk about, relative to cash flow, what you're looking out for the 2011, can you give us any broad parameters about any capital guidance next year?

James Hackett

No. Let me try that just for a second, Dave. We really haven't talked about capital guidance for next year to any great extent. And I think until we understand what's going on in the Gulf of Mexico, as I've said a little earlier, I think it would be kind of not really prudent on our part to telegraph that. I think the best news is, is that these things that we're talking about onshore, if we decide that the moratorium is going to get extended, where it's going to play out in a way that's just not fair and a good way for us to be able to use the resources we have currently in the Gulf of Mexico, you can expect the capital plan would look a little bit more like an onshore plan. And we'll go back and reassess the Gulf of Mexico once we know the rules of engagement. I wouldn't be a bit surprised if we had an early plan that didn't include much in the Gulf of Mexico and much as a lot of clarity that comes forward between here and the end of November. And then if we find clarity through the of course of 11, we might come back to the market with a further update once we understand the fact of how we can deploy the capital.

Operator

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

David Kistler - Simmons & Company

Just quickly following up on the services question in the Eagle Ford and the Marcellus, we've seen some of your counterparts out there actually getting in the business of vertical integration and I was curious kind of how you guys think about that from a completion standpoint where it seems like things are tightest, and as we watch you guys get more efficient drilling wells, is probably one of the harder portions of the equation to manage. If you could just kind of walk through your thoughts there, I'd appreciate it.

Charles Meloy

Dave, we are constantly evaluating that option to us and in certain areas, we've taken some vertical integration, particularly like in Wattenberg, we're on the lower end of the service chain, if you will, with the smaller rigs, et cetera, workover rigs, pumping equipment, water hauling equipment, et cetera. But we'll continue to evaluate it. It's a tough position to get into right now. It would give you some reliability of service, but in our view, we have great partners in the service industry, and we have a large program that's provided a lot of supply chain incentive for others to perform with us. And I would be hesitant to jump to big into that arena.

James Hackett

And I think particularly -- this is Jim -- on the stimulation side, is that you've seen some announcements from other players about the commitment to that area from a capital standpoint. Our view is, that while you may see short-term protovations on that, that we're going to overcome with drilling efficiencies and centralized purchasing and kind of the size and length of what we can do from a contracting standpoint, is you'll see availability increase, and therefore, that these things, they're not -- today is not tomorrow. And our view is, that the business is very cyclical. We saw what happened in '09. We think that there is a virtuous answer that is solved by capital on the service company side. They want to attack those margins because they're good. We were able to overcome some of that through our own efficiencies internally, so we don't view becoming a major simulation player as an answer in the long term to our business model. I think there are plenty of other answers, Dave.

David Kistler - Simmons & Company

And then maybe just jumping over to the $5 billion senior secured credit facility that you guys set up, can you talk a little bit about kind of number of counterparties, how much can be drawn? And if I'm not mistaken, I think it actually frees up some of the collateral you guys had to put up on hedges. If you could just kind of talk about that, that'd be great.

Robert Daniels

This is Bob, I'd be happy to. JPMorgan led the facility. There are a number of underwriters in the facility. We're not going into the details as to how many at this stage, but it is a substantial number that stepped up to share that $6.5 billion commitment. How much can be drawn, as much as we need to under the facility. There is not a restriction on our ability to draw up, absent default under the agreement, which is kind of standard affirmative and negative covenant package. We would expect to close here at the end of August, September. And it is firmly underwritten today, however, so there is no likelihood that, that goes in any other direction between now and the end of the month. We also expect it'll be undrawn at closing, with the exception of a couple of LCs that will move over from our current revolver to that revolver. And you are correct, the banks that we currently had ISDAs with, that participate in this facility, either the existing underwriters or those that joined during the syndication process, the collateral package would preclude the need for cash collateral to be posted relative to those ISDAs. And so it's a small, but ancillary benefit to the structure.

Operator

Your next question comes from the line of Rehan Rashid of FBR Capital Markets.

Rehan Rashid - FBR Capital Markets & Co.

Just real quickly on New Zealand, 17 million acres, pretty big position there. Two quick questions on that front. One, when could we see something drilled up in New Zealand? And second, industry historically has had some mixed results exploring there. What, in your minds, has changed to warrant a decent entry here?

Robert Daniels

Rehan, Bob Daniels. On the spud question, your first question, the earliest we would spud a well over there would be very, very late 2011. The drilling windows is usually from about December through April, and so you could see potentially, at the earliest, a 2011 December spud. The potential that we see out there -- well, you see, is mixed. The Taranaki Basin is an oil and gas-producing province and has been for many years, have got some very significant discoveries. And when we looked at it, actually, this is a far more mature than some of the areas we've been in, in West African and East Africa where we've had success. So what we try to do is, as explorers, is look at what we think the potential is with the data that's out there and not take any preconceived notions into it, but do take the learnings that we've had around the world. And particularly in the deepwater, when we look at what we see in New Zealand, we see a lot of potential, both in the Canterbury Basin off of the South Island where the well would be drilled, and then in the deepwater of the Taranaki Basin where the new acreage that we just acquired and we're shooting seismic on, we see quite a bit of potential. But we'll continue to do our evaluation, and then when the time is right, drill a well out there. The main prospect that we've seen, and it's under 3D and it's tied into a well that was drilled on the shelf, is 40,000-acre, four-way closure. And the well on the shelf tested 10 million a day and 2,000 barrels of condensate back in the late 70s or early 80s. So it's a real high quality prospect, and we'll get to it when the time is right.

Rehan Rashid - FBR Capital Markets & Co.

And for that well, 3D allows you to tie it together?

Robert Daniels

Exactly. There was a reasonable TD grid and then the operator at the time shot a 3D, we came in and the deal was, that we would operate the processing of the 3D to make sure that it was to the quality that we required. And that data was shot over the existing well and the four-way closure. And the previous operator and ourselves are the only people that have seen that data.

Operator

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

Philip Dodge - Stanford Group Company

Question on Ghana, now that you've closed the first oil on Jubilee Phase I, can you describe a little bit more how things are shaping up for Phase II, how Jubilee East might fit in there, and what the unit might look like?

Charles Meloy

Philip, this is Chuck. Our top priority today is to make sure we get the FPSO on line, on time and on budget. And as we do that, as the production comes on, we'll be learning more and more about the field and that will really dictate Phase II and the expansion. And ideally, we'll be working toward a development program that may include additional facilities like a second FPSO, but we won't know that until we really get production, understand exactly how this reservoir performs and what is necessary to optimize this production.

Philip Dodge - Stanford Group Company

Okay. Can you give us any indication of how the unit costs might compare with Phase I, first considering there's infrastructure in place, but might be offset by a smaller size?

Charles Meloy

Well, it's a little early to do that. My sense, though, would be that it would be fairly equivalent to our Phase I activity.

Operator

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

Subash Chandra - Jefferies & Company, Inc.

The first is, what are your latest thoughts on in the Marcellus with regards to both sourcing and disposing of water now that you've got very substantial business underway there? Second, on the Gulf, probably a bit of an unfair question, but based on what's visible or reasonable right now, is it a five-year discovery to production-type target? I think you guys probably did among the better, if not the best, jobs of bringing on discoveries very quickly. Is that still a conceivable target? And then I guess, finally, the Midstream sales, should we see that as sort of opportunistic one-off or might there be a broader program to recognize the value of your big Midstream business.

Charles Meloy

I'll start with the Marcellus water handing and sourcing. To date, we've had great success with sourcing water. We've put together a number of sourcing alternatives throughout the field there that we operate and includes sourcing from subsurface aquifers, as well as municipalities, and we don't see that being an ongoing issue of any consequence right now. With regard to disposal, we've done -- we've set up facilities in our operating area to dispose the water on-site and the deeper reservoirs where we're getting disposal permits and hauling it to accredited sites. So as we go today with the current activity that we have, we just do not see that being a significant issue on.

The down timing, we have had a great success and track record of putting these things on quickly, safely and at a lower cost. As Al mentioned earlier, until we really see the rules of engagement, it's hard to quantify what change there may be in that profile. We'll take them into account. We'll do the very best we can with them. My sense is, that there'll be some additional time, but it will not be significant. But we, again, we have to wait on the rules of engagement.

Robert Daniels

On the Midstream side, this is Bob, nothing's really changed there from the strategy that we outlined when we formed Western Gas Partners back in May of '08. We expect to continue to sell assets to Western Gas over time, Western has increasing access to capital, both debt and equity capital has grown. And as it's capable of buying Midstream assets from Anadarko to build it's business model and establish the right growth curve, we will be a willing seller to them. Obviously, as the owner of the GP, it is a great way for Anadarko to take sallow capital that's performing to support our E&P operations and sell those assets and redeploy that capital into the E&P business.

Subash Chandra - Jefferies & Company, Inc.

Okay. I have two follow-ups, if I could. On the Midstream side, any potential to monetize Midstream outside of Western? And second, in terms of sourcing water from the subsurface aquifers in Pennsylvania, any particular roadblocks in trying to get the permits to do so?

James Hackett

The first question, things we might do outside of sales to Western Gas, I think, periodically, we might do one or two. We did one earlier this year of small -- an asset that didn't really fit Western Gas' profile and was not central to our E&P operations, where being able to control the development timeline of the asset and the operation of the Midstream asset is important to us. As far as the water issue, I'll leave that to Chuck.

Charles Meloy

We haven't had any roadblocks. It's a formal process. We've gone through it in a number of different instances and had success. The regulatory environment in Pennsylvania's continuing to mature, and the processes are getting more defined. So I think in the future, there may be time involved, but I don't see roadblocks.

Operator

I would now like to turn the call over to Mr. Jim Hackett for closing remarks.

James Hackett

I appreciate it. Thank you all for being on the call, and I appreciate it. I know you've got other calls to go to, too. We're looking forward to the second half of the year and appreciate your support. Have a great day.

Operator

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

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Source: Anadarko Petroleum Q2 2010 Earnings Call Transcript
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