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Anadarko Petroleum (NYSE:APC)

Q1 2010 Earnings Call

May 04, 2010 10:00 am ET

Executives

Chuck Meloy - Senior Vice President of Worldwide Exploration

Robert Daniels - Senior Vice President of Worldwide Exploration

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

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

Charles Meloy - Senior Vice President of Worldwide Operations

John Colglazier - Vice President of Investor Relations & Communications

Analysts

David Knott

Phil Corbett - RBS Equities Research

David Tameron - Wells Fargo Securities, LLC

Douglas Leggate - BofA Merrill Lynch

David Heikkinen - Tudor, Pickering, Holt

Doug Leggate - Citigroup

Brian Singer - Goldman Sachs Group Inc.

Robert Morris

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2010 Anadarko Petroleum Corporation Earnings Conference Call. My name is Jerry, and I will be your coordinator today. [Operator Instructions] I would now like to turn the conference over to your host for today, Mr. John Colglazier. Please proceed, sir.

John Colglazier

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

Before I turn the call over to Jim, I'll need to remind you that this presentation contains our best and most reasonable estimates and information. However, a number of factors could cause actual results to differ materially from what we discuss today. You should read our full disclosure on forward-looking statements on 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 today, so be sure to see the reconciliations in our 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. Before we get into results for the quarter, I want to first express the sadness we feel and extend our sincere condolences to the families of those who were lost in the Deepwater Horizon accident about two weeks ago. As a non-operating partner, we want to answer questions regarding the cause as much as anyone in resolution as quickly as possible. We understand this event is foremost in everyone's mind and we will discuss it in more detail with you later in the call. But before we do, I'll spend a few minute moments reviewing the results of our first quarter.

As you saw in the press release, our producing assets delivered a record quarter, with total volumes of 62 million barrels of oil equivalent. Our E&P organization accomplished this, while also continuing to reduce our lease operating expense per unit. With strong run rates and minimal work over us in the deepwater Gulf of Mexico, lease operating expense improved by about 19% sequentially over the fourth quarter of 2009 and by 32% year-over-year.

Through these efforts to reduce LOE, we are now among the lowest cost producers in our peer group. Other summary highlights during the quarter are that we made good progress in our shale plays, announced the new deepwater discovery in the frontier basin and drilled three successful appraisal wells that confirmed the resource potential and the ability of several emerging megaprojects. We also closed a $1.5 billion joint venture agreement with Mitsui in the Marcellus Shale and retired or refinanced near-term debt to further strengthen our balance sheet.

Our reported quarterly sales volume increased by about 15% relative to the first quarter of 2009. Of note, sales volumes for the quarter included about 1.9 million barrels of oil equivalent from a royalty price threshold adjustment related to our 2009 Gulf of Mexico natural gas sales. Adjusting volumes for these factors still leaves above the high-end of our volume metric guidance for the quarter and represents an 11% increase over the first quarter of 2009.

Due to the strong performance of our producing assets, we are increasing the midpoint of our full year sales volume guidance by 3.5 million barrels of oil equivalent. A major contributor to our production growth was a 35% increase in our total liquids production to almost 26 million barrels compared to 19 million barrels in the first quarter of 2009. This is a direct result of the actions we took at the beginning of 2009 to focus on liquids-rich areas within our U.S. onshore portfolio. Liquids for the quarter comprised 42% of our overall reported sales, directly contributing to our enhanced cash flow margin per barrel of oil equivalent.

As I mentioned to you moments ago, our E&P organization did an outstanding job in the quarter of managing our assets. As a result of these efforts, we're now reducing our annual guidance for LOE by $0.25 per barrel of oil equivalent. We are and have been focused on investing in areas of our portfolio that offer the strongest economics. Given the current market conditions for oil and natural gas prices, this involves focusing on areas with high liquids yields.

The Marcellus Shale, given its strong economics, is currently the only area of pure natural gas drilling, in which we are prudently increasing our activity levels. The increased investments are being carried by Mitsui through the joint venture agreement that we closed in the first quarter. Currently, we are producing approximately 120 million cubic feet of natural gas per day on a gross basis from the Marcellus from about 30 wells with about 80 wells in various stages of completion, as three folds to our 2009 exit rate of about 40 million cubic feet per day gross.

In another major shale play, the Eagleford in Southwest Texas, we continue to see strong results with very good liquids production, which compromises about 50% of the product stream and 75% of the production value. We expanded our position during the first quarter by acquiring more than 80,000 net acres from TXCO. This acquisition also increased our working interest to 75% across all of our Eagleford acreage.

The cost of this acquisition was approximately $1,100 per acre, which is a very competitive both to the higher or recent industry cost for acreage year. We ended the first quarter with four rigs running and have drilled more than 20 wells in this play and are driving down drilling times, reducing our cost per well and seeing good economics with EURs of over 300,000 barrels of oil equivalent per well. We've identified hundreds of potential well locations in this play, are in the process of adding two more rigs in the coming weeks and pursuing plans to significantly expand the midstream infrastructure to capture the value we see over our 300,000 net acreage position.

One of the new areas in which we are actively drilling is the Bone Spring play in the Delaware Basin of West Texas where we control 170,000 net acres. Like the Eagleford in Wattenberg areas, Bone Spring is a high-liquid composition. We are currently running four rigs in the play with one recent completion flowing at a maximum rate of almost 1,200 barrels per day. We also anticipate that our partner in this play will be increasing their rig count, thereby providing for an active program throughout the year.

In Iraqi's region, we expect to be drilling by the end of the quarter in the oil-focused horizontal Niobrara play, where we have 500,000 net acres. By virtue of several modest-sized firm ups that we completed over the last several years within our mineral interest, we have had access to industry information on the recent drilling in the shale, which allows us to better derisk the play with other people's money as we prepared for our own drilling program this year.

In addition to meaningful growth that we are demonstrating with our onshore assets, we can currently remain on track and on budget to deliver first oil from Jubilee Phase I in offshore Ghana beginning later this year. Caesar/Tonga in the Gulf of Mexico beginning in the first half of 2011 and El Merk in Algeria beginning in late 2011. The partnership has nearly completed the construction work on the 120 barrel per day FPSO for the Jubilee Phase I development, and we expect to mobilize the vessel to Ghana in the coming week. Tags to infrastructures are being installed and completions work has been initiated.

At the Caesar/Tonga complex in deepwater Gulf of Mexico, construction activities are progressing as planned. In Algeria at El Merk, the partnership has drilled almost half of the 140 planned wells and the facilities construction is on track.

Meanwhile, our global deepwater drilling programs continues to proves successful in advancing the next wave of megaprojects. During the quarter, we announced successful appraisal wells of Lucius and Vito in the Gulf of Mexico and at Tweneboa offshore Ghana. We announce that the Lucius appraisal on the Gulf encountered almost 600 net feet of high-quality oil pay in the subsalt Pliocene and Miocene sands.

The appraisal well was an up-dip sidetrack approximately 3,200 feet south of discovery well in Keathley Canyon Block 875. The reservoirs of Lucius have excellent porosity and permeability based on the core and log data recovered. We recently spud our second appraisal well and plans to drill a third immediately thereafter as we evaluate development options for this discovery. We operate Lucius with a 50% working interest.

In the first quarter, we also announced the successful appraisal well at Vito in Mississippi Canyon Block 940 in the Gulf of Mexico. The appraisal well, which is more than a mile from the Vito discovery well encountered more than 600 feet of high-quality oil in thick subsalt Miocene sands. We are currently drilling our second appraisal well at Vito as we work with our partners to transition this large discovery to development.

We hold a 20% working interest in Vito which is operated by Shell. Also in the Gulf, we are currently appraising our Heidelberg discovery. The original well encountered mechanical issues about 10,000 feet above the reservoir section and will now be redrilled with a projected total depth of 31,500 feet to test middle to lower Miocene objectives, similar to the Heidelberg discovery well in Green Canyon Block 903.

Moving to Ghana at Tweneboa in #2 well located about four miles southeast to the original discovery well confirmed our expectations of finding a down-dip oil accumulation and thicker sand section. The well encountered about 105 net feet of pay, which is over half of the pay count being oil in the remainder of gas condensate. The partnership expects to drill two additional appraisal wells in Tweneboa later this year as well as an exploration well at the neighboring El Wol [ph](38:50) prospect.

In Brazil, another of our emerging megaprojects, we announced last month the successful drillstem test at the pre-salt Wahoo#1 well. It voted an unstimulated and equipment limited rate of about 7,500 barrels of oil per day. Test results indicate this well will be able to produce in a sustained rate of more than 15,000 barrels per day of high-quality crude oil.

We've already moved the rigs to the Wahoo#2 well location to conduct the drillstem test there and expect to have results later this month. Once the drillstem test is competed at Wahoo#2, we expect to move the rig to drill the Wahoo South exploration prospect, approximately five miles south of the original Wahoo discovery. We operate this BMC 30 block why would discovery. We operate this BMC-30 block with a 30% working interest.

Shifting to exploration, we announced the first deepwater discovery in Rovuma Basin offshore of Mozambique in the first quarter. The Windjammer exploration well encountered more than 555 net feet of natural gas pay, and most importantly established the presence of an active hydrocarbon system. We operate Windjammer with a paying interest of about 43%. Our second deepwater exploration well in the basin was located approximately 50 miles south of the Windjammer discovery at the Collier prospects.

Drilling was stopped and the well abandoned because we reached the rigs designed framers at the top of the reservoir objective. We will continue to evaluate this and the numerous process in play types across our 2.6 million acres in this offshore block and had move the rig to another location called the Ironclad prospect, which will be followed by another exploration well in our Barquentine prospect.

In the Gulf of Mexico, as everyone is most certainly aware of the events involving the Deepwater Horizon drilling rig and the BP-operated Macondo prospect resulted in the loss of life, a release of oil into the Gulf and a large-scale response effort. As a 25% non-operating partner in the well, we have offered assistance to BP in our support of the unified commands role and coordinating the necessary resources to address the situation.

As we outlined in last night's news release, we maintained insurance policies that are designed to protect against the portion of potential financial losses occurring as a result of such events. Our share of cost recovered up to an aggregate level of approximately $710 million less deductibles. This insurance is designed to cover costs associated with stopping the hydrocarbon release, drilling relief wells, cleanup and other liabilities and associated costs. Based on our 25% non-operated interest, we estimate our deductibles will total about $15 million and our insurance will cover net cost to APC's working interest 25%, up to approximately $178 million.

It is still early in the response, back to gathering and investigation process. As a non-operator, we are in a position today to speculate on the ultimately outcomes of the root cause of the accident. We remain focused on managing through this event and based on what we know today, we are not currently making any major changes or interruptions to our capital spending programs or strategic objectives. However, we will not hesitate to take actions if necessary to protect the company and its financial health. We will, of course, continue to communicate with you as greater clarity is obtained throughout the year.

Turning to our financial results for the first quarter, we reported net income of $1.43 per diluted share. As with previous quarters, we've included the items affecting comparability in the tables attached to last night's earnings release. In total, these items increased our reported net income by $0.62 per diluted share.

We generated more than $1.5 billion of discretionary cash flow during the first three months of the year and ended the quarter with approximately $3.7 billion of cash on hand. Free cash flow totaled almost $300 million, with capital expenditures of about $1.2 billion for the quarter. At current strip prices, our projected discretionary cash flow for the year should be sufficient to cover our announced 2010 capital program.

During the quarter, we further strenghtened the balance sheet by issuing $750 million of 30-year bonds to fund a substantial portion of the tender offers for our 2011 and 2012 maturing debt. We retired a total of $0.25 billion during the first and early second quarters, approximately $920 million of which was scheduled to mature in 2011. To further support our ability to deliver upon our exploration programs and megaprojects developments, we've augmented our 2011 hedge positions from the schedules we provided in March. A full description of these are available in the attachments to last night's news release.

As I mentioned earlier on the call, we are raising our sales volume guidance for the full year to a range of 230 to 234 million barrels of oil equivalent from the previous range of 226 to 231 million barrels of oil equivalent, for an increase of 3.5 million barrels of oil equivalent at the midpoint.

At our recent Investor Conference in March, we laid out bold long-term objectives for the future when we began delivering upon those expectations during the quarter. To recap, we enhanced our margins by continuing to focus capital on areas with higher liquids production, managing costs and improving efficiencies. We confirmed the market value of our Marcellus Shale position of approximately $4.5 billion gross via a joint venture agreement.

We maintained time and cost schedules for bringing our sanctioned megaprojects online, and so far this year, five of the seven deepwater wells drilled have either been discoveries or successful appraisals. We expect to be active during the remainder of 2010 with approximately 20 deepwater well as planned.

As a result, we can reaffirm our expectation to deliver approximately 400 million barrels of oil equivalent of net discovered resource of this year from our exploration programs. We also remain committed to allocating our capital dollars towards the most value-accretive projects within our portfolio going forward, and to make adjustments as necessary based on further developments in the Gulf.

At this time, I'm joined by our executive team and we welcome your questions. So Jerry, I might ask you to open up the lines.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of David Heikkinen with Tudor Pickering Holt.

David Heikkinen - Tudor, Pickering, Holt

Just thinking about 2010, 2011 plans and beyond. As you think about any risks associated with regulation or costs for the Gulf of Mexico? Can you talked about how you would change your capital allocation or any thoughts at least what this bill could actually mean for Anadarko longer-term?

James Hackett

David, I think it's early to try to speculate on that, but I will say given the portfolio we have what we find is the -- that we need for economic reasons to do something in other part of the world. We certainly can do that and we have the prospectivity to go and do that as well.

David Heikkinen - Tudor, Pickering, Holt

And as you think about -- just shifting to -- I realize you can't answer a whole lot of questions as far as the hydrocarbon release and relief wells. Right now, all your interests are aligned with BP. I mean when you think about the past forward, how can we assess what that environmental cleanup risk would be? I mean, what's the range of outcomes and how long does the $710 million cover you?

James Hackett

Again, I think, David, we can all sit here and presume what it might be but the real key is how long the well keeps flowing. If the well is shut in, the cost escalation actually starts to go down as opposed to up. And so I think we've got to be careful not to try to speculate as to number ranges. Bob can speak to the insurance here on one second relative to how we view the world out there in terms of coverage. And we feel good that we got in place, we feel that if things happen and we're blessed in this process, there might be plenty there. So Bob, I don't if you want to walk through any of that?

Robert Gwin

Sure, I'll address that, David. If you think in terms of the rate of spend that we hear coming out in the unified command at this stage of about $68 million per day, then obviously our coverage in the $178 million range would represent about two to three months. However, I think it's important to keep in mind that as we start drilling the relief well, the rate of change certainly will change and the timing of that expenditure will be somewhat variable. So we're looking at it as based on what we see today in insurance to cover the next few months. And as Jim mentioned, there's a lot of uncertainty around how far this will go into the future and what the ultimate remediation cause will be. But the insurance piece, I think, cover a couple of the three months worth of that time.

James Hackett

And David, just one other thing that I'm sure early in the phone as to where -- if there are other considerations here to. As Bob discussion really assumes that there's no liability anywhere along the chain or any source of the insurance outside of our own proprietary insurance. And that isn't necessarily going to be the case.

David Heikkinen - Tudor, Pickering, Holt

Specifically just on Bone Spring, you mentioned a high liquid content. And we've talked then heard about the Avalon Shale being a contributor there. Can you talk it all about just kind of the operations onshore? And as you think about West Texas, is there a shale play that's emerging in the Bone Spring's area or how you do think about that?

Robert Daniels

David, this is Bob Daniels. On the Avalon, what we've done so far is in the Bone Spring itself. And we have looked at now at the Avalon which does seem to have some characteristics that would make it attractive to test. And so we do have some plans to go out and test the Avalon shale and see what sort of producibility it may have, what kind of recoveries we would get, what type of hydrocarbon. We do plan to drill two wells in there right now. We have 170,000 acres out in the West Texas area that would be prospective for the Bone Spring and the Avalon Shale. So we would be testing it and see what we get out of it.

Operator

And your next question comes from the line of Scott Panel [ph](49:23) with RBC Capital Markets.

Unidentified Analyst

When you look at the Macondo well, are you guys, from a financial perspective, going to start making some accruals for some of these future costs? When would that start to flow through the income statements?

Robert Gwin

Scott, this is Bob. We're going to look at that really hard in the second quarter obviously. It's difficult to make accruals when you don't have an estimate of the expense in there, a great number of variables currently. But it's something that we're going to spend a lot of time on during the second quarter process and make sure that we're as transparent and well accrued for any potential liabilities as it makes sense at the end of the second quarter.

Unidentified Analyst

Would you suspect that there's going to be one big accrual taken at that point in time and then smaller adjustments going forward? Or how do kind of think about doing that?

Robert Reeves

Scott, this is Bobby Reeves. Let me put a little perspective on this and kind of put a package around it for some of you. Remember that Anadarko is a non-operator here. The BP is the operator here -- is really focused appropriately all their attention on the response right now in initial investigation. Anybody that's been involved in a situation like this knows that it is extremely complicated. The investigation will hopefully give us some indication on what happened here, what the cause of the accident was, and then there are very complicated contracts involved here, indemnities, insurance coverage, the possible application of Oil Pollution Act of 1990 or other laws that really have a puzzle here that has to be figured out. And we're going to have to have some good legal minds to figure this out. We're on that process now. But it's not going to be immediate, it's going to take a little time. One comment I wanted to make about the Oil Pollution Act is that it was designed by Congress, in our opinion, to handle exactly the situation that has occurred now. The Congress imposed upon all the Gulf of Mexico oil producers to pay into the trust fund amount of every barrel that we produce. That protects Anadarko and its shareholders and we've done that. We believe it's going to be applicable. We don't know the ultimate potential outcome here. And it's not appropriate for us to speculate further. But I wanted you to know that it's not an immediate assessment that we'll be able to make. It will take some time.

Unidentified Analyst

One last question on Macondo, in terms of you being a non-operator, how passive typically are you when you are non-operator? I mean were you part of the well design on Macondo?

James Hackett

I can take a shot at that. In that, on traditionally, you actually do know what targets you're going after and remembering we had firmed into these after the well have already spud. So the well design and procedures, operating procedures, were all done before we actually firmed in. When you typically approve these as a non-operator, you basically approve just the capital spending level and the targeted zones from a geological perspective as opposed to looking at the detail, well design, or procedures. So we were not involved with that in that or all in this well.

Unidentified Analyst

In the Niobrara, you mentioned that you had 500,000 acres. Obviously industry really talked to play out? You did mentioned that you think that activity as derisk some of the play. When you look at the Niobrara, can you give us a sense of -- of that 500,000, is their a certain percentage of that you think is going to be really good or prospective?

Charles Meloy

We've been, this is Charles Meloy, by the way. We've been closely monitoring all the industry activity in Northern Colorado and Southern Wyoming. And as you're aware, we have the land grant that goes through that area. So we essentially have mineral interest in every other section in the play. And so as the play develops from north where we've seen industry activity to write down upon our Wattenberg acreage. Across that entire area, we've seen encouraging results. So all of the 500,000 acres looks perspective. We don't yet know where the sweet spot is because of the lack of activity. We're just starting to cleanup [ph](53:46) the activity in the area. And we've encouraged that activity through some modest farm outs to get the play moving. And so we're prepared and should toward the end of this year begin drilling in the play and reaping the benefits for that.

James Hackett

A thing I add is that, that mineral interest is held in perpetuity to -- so it's not -- we have a lot of time to work on other people's money and do some of our own drilling to make this thing really work well if it has the potential to.

Operator

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

Doug Leggate - Citigroup

I am afraid I want to keep on the issue of Macondo just for a little while if I may. Since this question, but just in light of Jim, of your comments about not being involved in the well. So it was part then. And also if I could bring in oil spill trust to this as well. Is there anything in the partnership agreement that you standard or non-standard that would relate to limiting your liability to any punitive damages beyond the immediate costs associated with the block? And if not rather, what is your understanding of how the trust will actually be deployed in terms of any limit that can be attributed to any specific incident or any color you can give that might limit your expenditure or your exposure would be helpful.

James Hackett

Doug, this is Bobby Reeves again. Let me first comment again, reiterate that until we know what the causes of this accident are, it's hard for us to give a legal opinion as to the applicability of the agreement, punitive damage or anything else. There's going to be a lot of fingers pointing a lot of different ways and it's just inappropriate for us to talk about how this is going to come out. It's going to take some time. As to the applicability of the Oil Spill Trust Fund [Oil Spill Liability Trust Fund] under the OPA '90 Act. That is something that will be sorted out but as we understand it, it allows for a third parties to make claim directed to that fund to be sorted out and then has a limitation of liability as to those who are considered responsible parties under the OPA '90 Act. And beyond that, there's some items to be sorted out. That would give you a brief understanding of how that works.

James Hackett

And Doug, as you know that, there are money that we've all put in on the crude oil we produced. So it's an interesting opportunity. The other thing I can tell you is that we are mostly focused on making sure that these cleanup occurs and assisting -- it is part of the full industry effort on this, assisting BP. But when all is said and done, we're going to be protecting the Anadarko shareholders.

Douglas Leggate - BofA Merrill Lynch

In relation to the same thing, Jim, you're quite averse to equity as we know. But I'm just curious if there's the thing that escalate, how do you see your ability to fund your share of the potential costs?

Robert Gwin

To begin with, we have substantial liquidity. As you saw, we ended the quarter with over $3 billion in cash, $3.7 billion and we've used some of that since the end of the quarter to pay down debt, which gives us additional borrowing capacity. We've got $1.3 billion all of a revolver that's committed through 2013. In addition, we generated a lot of discretionary cash flow over $1.5 billion in the first quarter. If it was necessary, we could chose in the future to redirect or reduce our spending, selectively sell our farm down assets. We obviously have a broad and a deep portfolio attractive assets and I think we'd be more inclined to look in that direction rather than to the capital markets. And as everyone saw in our investor conference in March, we have a five-year plan that delivers some very good results and a series of discoveries, recent discoveries, they're not a part of that five-year plan that start to kick in to provide accelerated growth well into the future. So we think we've got the types of flexibility with our investment opportunities in our existing assets to deal with the size of the costs, even if some of the very,very high levels of the media is tossing around out there.

Douglas Leggate - BofA Merrill Lynch

This one is maybe more business-oriented probably for Bob Daniels. The Collier well, Bob, could you maybe just speak a little bit about what happened there? I'm understanding that was maybe a little bit more of a liquids target. Could you just discuss what the prognosis is and where we go forward in Mozambique?

Robert Daniels

You're right, we did hope to see potential for liquids as a new dent of the south. Of course, it was 50 miles south of our Windjammer prospect, a little bit different play type, certainly a different seismic character which lead us to that. We designed the well to handle the anticipated pressures that we would see in our total depth. And we've reached those design parameters and we have to stop right at the very top of our objective. So what we're going to do is take all of the data that we have acquired from the wellbore, tied in to our seismic and make a decision is there another location either on this prospect or adjacent to it on a look-alike prospect that we may want to come back and test. But right now, we're just tying all that data into a regional understanding. Meanwhile, we're taking a big F and we topset the Barquentine prospect and then moved over to the Ironclad and we disbud the Ironclad prospect. They're very different plate types. They're both kind of big strap plays, similar to what we're seeing over in the West Africa side. Again, they do have particularly the ironclad one, has more potential for liquids as you move to the southeast [ph] (59:20). It's even further south than the Collier well. So I guess the overall result of Collier is that we recognize now that we've got from pressure regime that we got to design for. We also have a lot of data from it that we need to tie into our overall regional understanding and we need to continue to test these play concepts as we continue to evaluate the block there.

Douglas Leggate - BofA Merrill Lynch

Well, does Barquentine have an appraisal? I wanted to...

James Hackett

There's a little bit of an appraisal element that is primarily an exploratory well. I think that people have drawn that conclusion because of its proximity to Windjammer. Windjammer is a toe-trust, very tight hold and Barquentine is the outboard relatively undeformed component, same age sands that we're looking for but a very different tre stop [ph] (01:00:06).

Operator

And your next question comes from the line of David Knott with Knott Partners.

David Knott

Jim, you mentioned aggregate insurance of about $710 million and sort of direct insurance of $178 million. Could you give us some color on what both of those terms relate to?

James Hackett

I might ask Bob to do that. We were just try to gross it up for working interest is all. David, if you think in terms of our coverage, the lesser of those two numbers, the way the insurance works is it's designed around its gross level and then it gets adjusted by working interest. If our work interest and as well for instance was 50%, then that $178 million number would be doubled. And so it's really just a matter of trying to explain it so that the market could understand the coverage relative to the size of the event.

Operator

And your next question comes from the line of David Tameron with Wells Fargo.

David Tameron - Wells Fargo Securities, LLC

Jim, just stepping aside from I guess Macondo, I won't ask any more questions there. But can you talk about bigger picture kind of a regularity environment in DC? We've heard some chatter that perhaps we're going to finally get some type of energy bill and other bills [ph] (01:01:28) is going to come to the floor. Can you just talk about the latest grid is?

James Hackett

I wish I could give you better definition around that. I think this accident complicates a portion of that because I think a central feature of both this is going to be an offshore access. And I think in the current political environment, people would thread very lightly. As you know, that access was not something that was going to be provided overnight anyway. So in our view, it wasn't going to change our strategy or tactics for the next four or five years. And therefore, we see all of these as very long dated, and we weren't absolutely sure how helpful either piece of legislation would be for the natural gas toward the end of the day. We still are trying to press for that or we're going to press for that prior to Senator Graham walking away from the bill. We now hear that Senator Reid may put it back up for consideration. We think the politics of the re-election process and the politics around the current environment make both of those more just tougher to predict that something will happen there. We still need a good energy policy in this country. We don't seem to be able to get it together.

David Tameron - Wells Fargo Securities, LLC

I guess the implication imprints [ph] (01:02:48) from your comments are -- it sounds like we're talking 2011 before anything happens given we're five months away from?

James Hackett

Yes, or at least, a couple of months away. I think a lot depends on how quickly we get this situation under control in the Gulf. But at some point then if they're going to take up immigration it becomes more difficult to get KGL done potentially. But I'm guessing, because it depends on whether we could get Graham back in there and Senator Graham comes back in it, it changes the dynamic again. We still think, it's similar to what happened in Colorado. We still think that there are ways to get natural gas as a preferred fuel and we think it's just a matter of time. This is a short-term issue, I think more than a long-term issue. So I'm still very hopeful about even the direction that Kerry-Graham-Lieberman was taking was much more pro-natural gas for the first time. We saw a proposed Senate legislation at least our reading of it or understanding of it, that was going to be very positive about electric generation uses of natural gas.

David Tameron - Wells Fargo Securities, LLC

And just one more question, looking at the Rockies, you talked about that in Wattenberg hike and drill, NGLs and liquids-rich type of play. Do you have any of that ability in Greater Natural Buttes? And what are you guys doing out there currently?

James Hackett

Well, our liquid yield and Greater Natural Buttes, are generally associated with our NGLs coming out of our Chipeta Gas Plant. And the economics and Chipeta have become -- or this Greater Natural Buttes are in general have become really good unless and we focus on the core and began drilling just core wells. We're seeing EURs approaching two Bcf and for a $1.3 million to $1.4 million of investment. And that two Bcf, of course, has a liquid yield associated with it. So the economics have become stellar in that area.

Operator

And your next question comes from the line of Bob Morris with Citigroup.

Robert Morris

You know that the Marcellus Shale was the only area that you are prudentl increasing activity levels. How much of that is driven by the enhanced economics you receive now under the joint venture with Mitsui? Or in other words, would you still be increasing activity levels there without the benefits of that joint venture?

James Hackett

I think the quick answer is, what we're seeing basically is if we were on our own. But we have those benefit of the economics, obviously, from what you referred to in terms of the carry. A lot of the production uplift as you may imagine is not operated because of the activities of our partners. We would not necessarily be as aggressive as that is I think on our own but that's each company's choice to do what they need to do. Somewhat determined in some cases by lease exploration terms. In our case, we've got very favorable leases for the most part, but we are not using the carry as a reason to go crazy, if you will. We just think its things we need to do to get ready for when gas prices recover. And certainly with LNG enforced being with where they are at, and if we can continue to advance anything on the legislative front and if we keep working on, showing discipline in the industry, we can make this particular play highly attractive because we think the break even economics on the Marcellus are somewhere around $3 bond at the NYMEX.

Robert Morris

So you're saying your break even is at $3? Is that what you just said?

James Hackett

All in, below $30 all in, yes.

Robert Morris

Without the carry?

James Hackett

Right.

Operator

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

Brian Singer - Goldman Sachs Group Inc.

First, kind of going back to oil, a nice increase in oil production during the quarter. It looks like the trajectory though is for oil production in the U.S. to fall between now and the end of the year. And I wonder how much of that is conservatism for potential hurricane disruptions? Or how you think about your U.S. oil and NGLs trajectory going forward?

Chuck Meloy

Brian, this is Chuck. The trajectory is strong. We do take into account the hurricane season which, of course, would impact mostly Gulf of Mexico oil production, oil and gas production. And so that's the deep you see in the third and fourth quarter. Other than that, the activity we have going on in the Maverick Basin, the Bone Springs, the Wattenberg and in our other place like East Chalk for instance is all focused on those very robust economics, most of which are liquid rich. So we should see that trajectory continue through time.

Brian Singer - Goldman Sachs Group Inc.

Especially in the Rockies, we saw sharp increase quarter-on-quarter even versus most the rest of the quarters in 2009. Either there's nothing specific to say that, that should really fall off?

Chuck Meloy

No, we should continue to have strong results there particularly with the focus we have in Wattenberg. We're ramping up our rigs in Wattenberg and we have the White Cliffs pipeline available to us, which has allowed us to export with very low tourists and enhance the economics that will continue to increase our investment in Wattenberg.

Unidentified Analyst

And then secondly, going back to the Gulf of Mexico, when you think longer term, Anadarko has always been very upfront in trying to push the envelope in terms of using new technology and in terms of trying to reduce lead times. Do you see any of that either at risk or do you see any kind of longer-term cost increases that would make you any less aggressive either in the Gulf of Mexico or in the Deepwater broadly?

James Hackett

Brian, we put such strong emphasis on our environmental and safety records, they've been strong through time. We've won many SAFE awards. We're currently the winner of the District SAFE in in New Orleans. Our incident rate is one quarter of the industry rate despite our use of advancing technologies. We'll continue to do that. When we have a strong record of being able to employ those safely and effectively and quickly. I see us continuing to do that through time. It's still early two speculate what regulations may come our way with regard to further safeguards and further requirements of us with time, but we'll take those into account and use them to our best abilities to maximize our value in all of our investments.

Operator

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

Phil Corbett - RBS Equities Research

First of all, just on West Africa drilling campaign this year, I just wanted to assure the position there, if you give us a bit more detail in terms of the prospects that you might decide to drill in Sierra Leone or Liberia this year? So secondly, just going back to Mozambique, I think one of your partners has sort of indicated that there could be some upside for the number of wells above and beyond the four, I guess you were thinking about drilling this year. I noticed that they've sort of come up with other prospects like Galleon and Caravelle in some of their diagrams. So I'm just wondering if what you're feeling is right? Something extending your Mozambique-driven campaign this year. And finally, just on your previous comments about spending and potentially sort of containing spending, if you might need to bolster your financial position. Do you have sort of a preference with regards to exploration versus development and environment production spending, if you need to sort of look at airport level of CapEx this year?

James Hackett

Phil, I'll start with first and see if Al wants to take the last one. On Sierra Leone and Liberia, the West African campaign, there's a lot of information in the offshore but we publicly told folks that we would like to be back in the Sierra Leone and Liberia and are planning that. For the second half of the year, it will probably be October timeframe before we get over there. We're looking at one well in Liberia, an exploratory well and an exploratory well at Sierra Leone. We have to work up all of the data and make sure that we get the partner approvals for that. And while we do have a rig targeted at this point, we're also evaluating other rig options to make sure that this is the best rig to come over there. But all of that is coming together and we do have the prospects identified. Of course, the Liberia 3D that we acquired, we've got file product in. We've got multiple prospects that come out of that. And then the Sierra Leone 3D that we're reprocessing for the Venus appraisal is good enough to identify prospects for exploratory work and so we do anticipate that it will be drawn affected wells there. Additionally in Ghana, we have passes the appraisail and exploration work they're going to be this year. We have got the th code 702 coming in June, going slow with the oil well [ph] (01:12:04) exploratory prospect, which is a prospect just to the west of Tweneboa. It's a mirror image to Tweneboa back to maybe said from the same sound system. Then we'll move over to either Tweneboa appraisal or to the El Niño prospect. But overall, in Ghana, we're going to drill at least four more wells exploratory and appraisal wells that can be two Tweneboa well, oil well [ph] (01:12:27) and El Niña this year with the 702. Then you asked about Mozambique, the drilling campaign there, we publicly said about before we do have a drilling commitment that's beyond that and with, of course, the Windjammer success, we do plan to continue with that activity. Our partnership has been in discussion about which prospects we would drill. We took the rig over to the East Africa and we would like to keep it there to make sure that we get all of the play types evaluated, that we get any discoveries that we make appraised and that we learn as much as we can about that block. So we anticipate that rig will be busy in Mozambique for the rest of the year.

R. Walker

And Phil, this is Al Walker. On the capital allocation question, I don't think we would pass along any meaningful changes in the mix that we communicated in March, which if you recall on our investor conference, we talked about having an annual billion dollars or thereabout that we wanted to spend on exploration. I don't think there's any likelihood that we would materially change that, the mix that we were referring to earlier. I think that you may have heard from Bob Gwin is that, if we found ourselves needing to adjust capital spending, we might look at things across the board or in some areas where capital spending could be delayed and some of our development projects onshore. Most of it relates to our explorations and so much of that is focused on oil. In most cases, we really want to continue to allocate capital along a long-term perspective so that we can deliver on that five-year and beyond plan that we talked about in March.

Phil Corbett - RBS Equities Research

I just wanted to clarify some of the comments I've just made and maybe one possible quick follow-up question. So just to understand, you're thinking about drilling one exploration, one in Liberia, one exploration in Sierra Leone and appraising Venus, did I hear that correctly?

James Hackett

No, I'm sorry, at this point, we don't have a plan to appraise Venus. We're waiting on the reprocessing of the data set in Sierra Leone and that will be coming in mid-year to end of the summer timeframe. Then based on that, we'll tie the well, the Venus well into it and then decide do we need an appraisal well. If we do, it would then fit in logically to the end of that drilling campaign.

Phil Corbett - RBS Equities Research

And just one quick follow-up, given the I guess the relatively disappointing results of the Tahoma well, do you think the impacts on the prospectivity in the West Coast three-point license and I'm thinking maybe its the fact that the channels systems in the southern area of that block?

James Hackett

Yes, we've got a couple of prospects up to the east of Tahoma, we call southeast channel one or two I think. But the difference between them and Tahoma is that Tahoma was the down deep extent of the Jubilee van complex. And what we had been testing there was whether there were internal tin shops of those sands as you came up the depositional system. And what it looks like is that while we do have really good fan down there, there doesn't seem to be those internal tin shops or if they're there, they're probably further updip from the Tahoma prospect. As we move over to southeast channel, they're the same age fans but they're totally not tied into the Jubilee van complex. So we'll be more like testing Tweneboa or Jubilee originally before we go out and test either the Southeast Number one or two. We'll roll the Tahoma well into our risking. But overall, southeast corner ones are different than Tahoma was and more similar to Jubilee original and Tweneboa.

Operator

Your next question comes from Ellen Hannan with Weeden & Co.

Unidentified Analyst

I just had a question, follow-up on your Eagleford position if you would. Could you give us an idea of what you think in terms of your total resources that will be necessary to fully develop this both on the midstream and the upstream? And also, the timing that you're thinking about in terms of what you need to do just to hold your acreage position with the six wells that you're running there today?

Charles Meloy

Look, Ellen, this is Chuck. As we work through our average position we have about 400,000 gross acres in 280,000 net acres. We view the vast majority of that as perspective at this time, particularly as in the Eagleford section, particularly the east and 2/3 of that and we're pushing it west as we move along. So a good portion of that, if not all of it, will be perspective. We don't yet know what the appropriate well density is to develop the Eagleford so it's hard to make sort of a suggested idea on what the ultimate development cost would be at this point. But what we're seeing for the money we're investing, the wells are that's costing us about $4 million and $5 million and we're getting over 30,000 or 350,000 barrels of primarily liquid production with those wells. So the economics are really good. It's just too early to speculate on what the ultimate cost would be [indiscernible] (01:17:48). I can't help you there.

Unidentified Analyst

And what about in terms of the timing? If you're running six rigs, in terms of what you think about what your primary terms on your leases are or your secondary terms, are you running enough rigs to actually hold your 280,000 acres?

Chuck Meloy

Yes, we are. We're actually running more rigs than we need. These are huge leases, medium or 7-acres or 8-acre 10,000 type leases. And so we have sufficient redline to maintain all our lease position.

Unidentified Analyst

So it's not just one per 640 in other words.

Chuck Meloy

No, ma'am.

Unidentified Analyst

Do you expect any further adjustments on your royalty the price threshold that you had in the first quarter? Or are you essentially done with that?

John Colglazier

This is John Colglazier. What that applies to is certain lease is given back in the 2000 timeframe the MMS and the Department of Tourist to help increase [ph] price thresholds that if the price received is below that amount, you would not owe royalty on that and be able to recoup what you had paid in, which is what happened in this case. In 2009 in the very low gas price threshold, by the way this is all natural gas, it was about the prizes we received over the course of the year were about $0.01 lower than what the MMS publishes. It actually comes out in the February-March time period, so it's an after the fact that adjustments has to be done. And so we were able to record the 1.9 million BOEs, which was about a $125 million a day of if you put it back and ideally amount in the quarter. So that's a one-time event recently spiked it out. That wasn't an operational type event and not accounted in our compared our production guidance and it had very de minimis impact on the net income basis, like less than $0.01.

Operator

And your last question comes from the line of Dave Kiefer [ph] (01:19:54)with Simmons & Company.

Unidentified Analyst

Real quickly, kind of focusing on the macro picture for a second. You highlighted $3 gas prices in being able to play in the Marcellus reducing activity on the coalbed methane side of things. Can you walk through a little bit about where you think threshold prices are working out and then tying it potentially to what's happening in the Gulf of Mexico? Could you there be any fallout in terms of ongoing support for gas coming out of there?

James Hackett

Dave, I's start with this latter part on that. I'm not sure I don't see the connection in the Gulf of Mexico as clear as you might. So I would ask you to elaborate on that when you get the chance here. Regarding the macro, we still stay cautiously optimistic the inventory situation is shaping up to be a little bit like last year, which caused us to hedge a fair portion of 2010 but the difference is we did that last year thinking that we're going to be determined as inflows of an LNG into the U.S. and we haven't seen enough of that this year to date to be consistent with that view that we had last year. And I think there's some dynamics internationally that are helping us in that regard, but I think at the end of the day, all of us on the phone and elsewhere need to make sure that we're putting the right pressure to the industry to say that the next piece of growth is not as important as getting returns. There may be selected plays like Marcellus that work really well at low prices but that's also part of what causes the issue. So we want -- we're being very careful on any gas drillings just like we were last year and on pure gas drilling and we're pursuing liquids, which we're fortunate to have in our portfolio. And we just got to show the discipline and then it will correct itself from what would be in a good place.

Unidentified Analyst

And I guess elaborating on the Gulf of Mexico impact, as thinking about it in terms of, is there possibility that people are forced to shut in to do any kind of safety testing, et cetera? Just to make sure that going forward, we avoid kind of the tragedies that we've been discussing quite a bit on this call already.

James Hackett

I understand now and I don't -- our anticipation is that isn't the remedy at end of the day that will be used. And so I don't -- at accurately suggesting what I think is probable, it's not probable that has a big impact on natural gas supplies. Theoretically could it, yes but I don't want to quantify that today.

Unidentified Analyst

Just one last housekeeping issue, on Bone Springs, can you walk through kind of the base economics of the play for rigs running, you talked about adding a fifth. If we can just get a sense for what that looks like with 170,000 net acres looks like something that could be ratcheted up in activity pretty substantially?

Charles Meloy

What we have is for like you mention we also see our non-operating partner, other partners that has a portion of this area also ramping up and that's just a peek to listen to their call and they anticipate ramping up. So we should see a great deal of activity out in the Bone Springs. Our EURs had been in the order of 350,000 to 375,000 barrels per well. So again, really good economics. We mentioned, I think a thing Jim mentioned earlier that the last well had a maximum rate of over 1,200 barrels a day. So these are good wells. They have good economics. They have the revenue stream is primarily associated with oil and said you have good basic economics, 375,000 barrels for $5 million or thereabouts works all day.

Operator

And this concludes the time that we have for question-and-answer session today. I would now like to turn the presentation over to Mr. Hackett for closing remarks. Please go ahead, sir.

John Colglazier

Thanks, Cherry. I just want to thank everybody for participating today. I appreciate it. I know a lot is going on in your lives and our lives too. We appreciate all the support. Just be assure that we'll continue to pursue our stakeholder interest in both our strategy and tactics as we proceed through this year and next. Have a good day.

Operator

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

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Source: Anadarko Petroleum Q1 2010 Earnings Call Transcript
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