Good day, everyone, and welcome to the Apache Corp. First Quarter 2010 Earnings Conference Call. [Operator Instructions] Today's presentation will be hosted by Mr. Tom Chambers, Vice President of Corporate Planning and Investor Relations. Mr. Chambers, please go ahead.

Thank you. Good afternoon, everyone, and thanks for joining us for the Apache Corp. First Quarter 2010 Earnings Conference Call. On today's call, we'll have four speakers making prepared remarks prior to taking questions. Steve Farris, our Chairman and Chief Executive Officer, will lead off; followed by John Crum, our Co-Chief Operating Officer and President North America; Rod Eichler, our Co-Chief Operating Officer and President International; and Roger Plank, our President. We have again prepared a detailed supplemental data package for your use, which also includes the reconciliation of any non-GAAP numbers that we discussed such as adjusted earnings, cash flow from operations or costs incurred. This data package can be found on our website at www.apachecorp.com/financialdata. Today's discussion may contain forward-looking estimates and assumptions, and no assurance can be given that those expectations will be realized. A full disclaimer is located with the supplemental data package on our website. With that, I'll turn the call over to Steve.

Thank you, Tom, and good afternoon, everyone, and thank you for joining us today. Apache took important steps forward during the first quarter on three fronts, operationally, financially and strategically. And I'd first like to go over on the operations front and mention two highlights. Our Van Gogh and Pyrenees oil development projects in Australia have now achieved maximum production ahead of what we forecasted for the year. This is an important step forward in the delivery of the large and visible pipeline of organic growth projects in our international region. In the North America, we ramped up the development of two large resource plays, the Horn River and the Granite Wash. We're going to drill over 60 gross wells this year in these two plays and expect to exit the year with net production of around 175 million a day. The Granite Wash is a liquid rich relative to most other large resource plays in North America, which gives big impact on economics. It's also differentiated by the acreage position we hold because it is primarily held by production. In the Horn River, the quality of the rock and the development efficiencies certainly differentiates it. We can achieve those through large drilling pads on continuous ground acreage. In addition, as we progress our Kitimat LNG project, our goal is to give Horn River access to international LNG markets. These are just a couple of the highlights on the operations side, and Rod and John will go over more on this as we go, which is really shows that organic growth engine is stronger than it's ever been. Going into 2010, we truly expected first quarter to be slow relative to the sequence of being of the quarters and production growth to accelerate from there and that's exactly what you…

Thank you, Steve. North American production averaged 276,000 barrels a day in the first quarter, down 4% from the fourth quarter 2009. Downtime associated with extreme weather in Canada and third-party held platform and pipeline downtime issues in the Gulf Coast and Central regions were the primary factors. The ramp up of drilling operation, started in the first quarter after very low activity level in 2009, will arrest that drop for the second quarter. The Gulf Coast region production for the first quarter averaged just under 119,000 barrels of oil equivalent per day, down 4% from the fourth quarter of 2009. Production gains of almost 6,000 barrels equivalent were experienced from additional hurricane repairs and resumption of the service of the Sea Robin Pipeline. However, these gains were offset by natural declines and again, the third-party host platform and pipeline issues during the quarter. The first quarter drilling program in the Gulf Coast has given us a nice start for 2010. We drilled 19 gross wells, of which 14 were successful. Four of those successful wells were exploratory and are now in evaluation and developmental planning stages. Two LLOG-operated Mississippi Canyon 199 wells successfully tested two adjacent fault blocks at our Mandy prospect, and penetrated net oil pay of 161 feet and 109 feet respectively at approximately 6,500-foot PVD. We are now evaluating subsea development plans for these wells and would expect production by mid 2011 with initial rates of around 6,000 barrels per day from each well. Apache has working interest of 15% in this field and Mariner Energy has 35% working interest in the discovery. In addition, we were successful with two tests of the N6 M [ph] at our Boomerang Prospect that main pass 308, where we identified 12 feet and 30 feet of net oil pay…

Thank you, John. During the first quarter, production from Apache's international operations was 310,000 barrels of oil equivalent per day, a 2% increase over fourth quarter 2009. The production increase can be attributed to drilling successes in Egypt and successful commission of oil developments in Australia. In Egypt, net production was 151,000 barrels of oil equivalent per day, down 5% from fourth quarter due to higher oil prices and lower recoverable costs resulting in lower cost recovery barrels. By contrast, gross fuel per day increased 3,000 barrels a day or 1% from 300,000 barrels of oil equivalent per day to 303,000 barrels of oil equivalent per day. Exploration activity continued stronger in the quarter with operations being conducted on five free seismic surveys representing nearly 3,000 square kilometers average. Oil activity increased during the quarter with a total of 48 wells, reaching total debt including 10 exploration wells. The region heads for the quarter with 20 after drilling rigs operating and the success rate for Apache-operated exploration wells was 67%. Exploration appraisal drilling was largely focused in our expanding Faghur Basin oil play, where four plays tested in a combined rate of 12,000 barrels of oil per day and 10 billion cubic feet of gas per day from AEB reservoir. 18 well remain to drilled in the basin this year including non-exploration wells. Development of the Phiops field of the east end of Faghur Basin continued with Phiops-8 well, which encountered 124 net feet of pay and multiple AEB sands. The initial completion, AEB 3E sand tested at 4,500 barrels of oil per day and no water. Construction is during completion on the West Kalansha facility project, which will increase the export capacity of our Faghur Basin facilities from the current 11,000 barrels of oil per day to 20,000 barrels…

Thanks, Rod. Good afternoon, everyone. I'm going to finish up with a few quick notes from a financial perspective. Apache turned in a standout first quarter setting, the stage for what is the makings of a truly exceptional year. Earnings of $705 million or $2.08 per share were 21% higher than the prior quarter and our highest since third quarter of '08. Adjusted for the impact of FX on our deferred tax balances, earnings totaled $712 million or $2.10 a share. Cash flow from operations for us $1.5 billion also for the first time since third quarter of '08. Apache's substantial oil and liquid production base was the primary driver behind our results. Highland liquids represented half of our equivalent production but generated nearly 3/4 of revenue, and are principally responsible for our revenue rising $118 million sequentially to $2.7 billion. Long before the current industries stampede began oil exposure, Apache took deliberate steps to achieve a balanced production mix. As a result, we're already benefiting from a current 20 to 1 multiple in the price of oil versus gas. And we are ramping up activity on the oil side of our portfolio. In the first quarter, for example, Van Gogh and Pyrenees enabled Apache's lower production to rise 3% sequentially, nearly offsetting a 4% temporary decline in gas production. I would note that absent the impact of higher prices had on both price-sensitive volumes in Egypt and to a lesser extent in Canada, on a production volumes, would've been up slightly and pretty much spot on our first quarter plan. A few quick comments on costs, cash costs excluding taxes other than income, came in at $11.89 per barrel of oil equivalent, impacted by slightly lower production. Rising future productions should drive us toward our goals to match 2009's…

Thank you, Roger. I'd like to sum up what I think were the three main messages from all the information that we shared with you on this call. First, we had a very good quarter operationally. As you heard mentioned few times Van Gogh and Pyrenees have ramped up. Our organic growth engine as strong as ever and our organic growth production's expectations for the year remain at 5% to 10%. Secondly, we have had a very good quarter from a financial perspective, with the highest earnings and cash flow since 2008. We achieved this in spite of a weak price environment from North American gas and it's because of our portfolio, which is really a central part of our strategy and a key differentiating factor for most of our peers. And third, we certainly took very important strategic steps during the quarter. You got further omissions that are a little, profitable long-term growth our shareholders. We picked our own timing and direction. And we're very excited about the growth and value creation potential by the Mariner merger, the Devon offshore acquisition and our Kitimat LNG project. And with that, we're ready to take your questions.

[Operator Instructions] And our first question today comes from Philip Dodge with Tuohy Brothers Investment Research. Philip Dodge: On the Horn River, you mentioned some metrics growth that are rig release average cost per oil. I didn't hear fracturing stages or EURs but you said you a lot of the cash but I didn't hear?

No, I probably -- I didn't give you the map on it. We did 274 fracs on 16 wells, so that comes up to just over 17 fracs per well. We did as many as 22 stages on individual wells. And the length of the horizontals that we're typically targeting now are somewhere in the range of 2,200 meters or 7,200 feet. Philip Dodge: Anything on EURs as you see is the most recently in decline rates?

We're still early to tell you anything about the decline rates here because we're still unloading water. We couldn't really bring these things on. We're just flowing through test separator equipment on location. We've got -- we're still running with a number that we believe we're going to be able to drain an excess of 10 bcf per well on all of these.

Your second question today comes from Leo Mariani with RBC Capital.

Just a quick follow up on the Horn River here, I think you guys give a well cost there, but I don't think I heard it right? What was your average well cost up there now?

We just gave you the drilling costs, Leo. The drilling costs were now at $3.7 million per well but that's on considerably extended lateral length to. You've heard me talk and pass about spending $10 million per well. We averaged around $11 million per well in this program. We were not able to get our new water plant on production in time to do these wells and that's why I believe it will add another million to our total costs. The real key here and I mentioned over tons of paper for here is we continued to that stages as we go forward and of course instead of using up some of our ability to reduce the costs.

You talked about experimenting with the horizontals in the Permian Basin here. Just trying to get a sense of how long you guys been doing that? And how much your acreage do you think is prospective and what types of improvements are you seeing and economics versus critical drilling for this play.

I'd say we really just getting started in the Permian Basin. There a number of players who have been doing some horizontal drilling certainly in the Southeast, New Mexico and in far West Texas for the past year, year and a half. And we really good guy getting started. These two wells I talked about were especially important because for drilling needs to wield of water that you do so that to get those kinds of results and those kind of reservoirs is pretty impressive. We would've expected to have so much water coming back in a typical well there that will create some new problems for us but that's going to lead us to try a lot of different things across the nation over the rest of this year.

Any further estimates as opposed to how much of benefit you're seeing here? Do you think you're getting to through funds back for the boss and verticals in some of these fields or?

Well again, a little early on, I only got two of them completed. We would be getting more than twice as much from these wells if our estimates hold up.

You guys also talked a little bit about East Texas doing some closure wells, some kind of a hot topic in the industry layaway. So the serious how much acreage this you think this is expected other.

We have a fairly modest position in these assets where we continue in that in areas that we're comfortable with. So again that's not our hottest area but we're getting pretty worked up about it because we got some great results out of our recent programs and knowledge and hope.

It sounds like you got five completion spirit you talked about some kids with all five wells took any kind of sense of kind of what these average rates are on these wells when you drill.

I have to give you average rates but I would say we we're averaging somewhere around $10 million.

And we'll go next to Judy Delgado with Alpine Associates.

Wanted to know whether companies have that the situation going on in the Gulf of Mexico and the newly announced administration's plans to be a little more stringent in their efforts to help. Do you have any thoughts on that?

I think it's tragic that we have the loss of lives in the Gulf and I think its a little early to try to figure out what the problem was. Certainly, it's going to be an area of a lot of attention and I hope we come up with something that is workable and safe and environmentally friendly.

Is the company experiencing any shutdowns now? Are you planning for any shutdowns in the future?

Well we don't have any shutdowns right now and it's going to depend on the direction that I assume you are speaking to this scale it's up for direction, we're not in danger to those amounts any of the spills reaching any of our existing production facilities. That's a wait-and-see.

And we'll go next to Brian Singer with Goldman Sachs.

I want to see if you can touch on that more on the cost inflation or lack of it as you go through your major areas and maybe on short-term site in terms of is some be on shore drilling and completion activities and also anything your seeing on the steel pricing processing when you think about the costs of LNG extensions in Australia and in Canada?

I'll let John talk about North America and then I might talk a little bit about overall what we're seeing on costs. I would start off from a generalization. I think personally, I think it's premature to extrapolate cost increases that we've seen in the first quarter throughout the year. Winter is difficult for us in Canada and unfortunately, it's difficult for us in the central region because we've got one of the more severe freezes that we've had through that part of our portfolio in the first quarter. So a lot of costs with respect to activities to start production again is part of those costs and the other thing is to be honest with you, our production was down a little bit and one of the major culprits was because we are in a CS3 a production sharing agreement in Egypt and the bedside of is all prices go up come in the downside of it is we see less production which cost us about 5000 barrels a day in Egypt. And gross operated was actually up. But overall, I don't think the cost side of it is going to get out of line. On the steel prices, that's certainly going to have an impact and I'm sure everyone's over the steel prices are going up. And we'll just have too wait and see what the impact of it is on those budget.

I don on that steel costs, I guess I'd like to think there's a positive tied to that but all in only indicates increased demand so hopefully, we can get some strength in prices to support some of that activity but obviously, that's something we do have to watch break also because it has a big impact on virtually all of our business.

On the Granite Wash going forward basis, for the next batch of gross, what are your expectations for percent gas versus percent NDLs versus?

I have to do the math call Brian. Can I just call you back would that?

Are you concentrating more on the Atoka relative to some of the where the oil comes on?

We're concentrating on higher liquid yields as we at testing a lot of different zones year but obviously, we're looking at the highest liquid yields the hardest.

And we'll go next to Doug Leggett with Bank of America.

Can you give us any better feel for where your CapEx may go this year, partly obviously the increase but also when you take a cut of the additional assets are going to have in the portfolio? Any guidance would be appreciated.

Could you first about that way maybe?

Your capital expenditure guidance for the current year, how is that likely to change going how do you expect your capital expenditure to trend over the balance of this year and can you give a details?

In terms of our overall capital budget, we've indicated before dividend, before the Mariner acquisition or merger, that we would be a little north of $6 million. And I think what you're going to see is from an activity level, our acquisition forecast for Devon, we had about $100 million of capital we're 10. Depending on what kind of opportunities we see them increase but we can generate about $285 million worth of cash out of that acquisition. With respect to Mariner, they have probably won't close that until September issue or later. They have a capital budget of about $550 million internally, which they're going to spend. So from our standpoint, which you'll see out of Apache, is not a significant increase from the acquisitions. Now depending on what prices do, reallocate capital quarters and we put a few more rigs to work starting in the second quarter than we've had running so you might see a little upward movement on our overall capital program.

So in materials.

Not in the present time to.

It that could jump over to Egypt, can you give us some sense as to how you see your production play through the balance of this year? Obviously call there's a lot of moving parts but it all pretty it was we're right now, how would the trajectory play out as you move through 2010?

Gross production gross gas production will soon about of the year because we are facilities limited with existing gas processing facilities although if you remedy debt by 2012 with additional pipeline construction. On the oil side combines to pay the continued growth in the quarter to quarter because we can't handle more oil as you so we have substantial interest forecast oil on gross oil beginning later this quarter from our opposite is project and by year end, we expect that to double again.

And from the price standpoint, if we stay static, that's where we're today. I think our March numbers were about 9,000 barrels per day net so when we broke for gross the number you saw average for March, you're going to grow from there.

Typically you guys tend to spend your cash flow just on a regional basis. I'm trying to think where that capital expenditure program in Egypt can take you if I heard you correctly, it sounded like you're going to drill about 19 exploration wells. I thought you were going to go this year if you could just give us.

That's 19 exploration wells in the area. The total exploration was about 33 wells.

[Operator Instructions] And our next question comes from Eric Marzucco with Dominick and Dominick.

As far as what you commented before about the recent developments in the Gulf having no frac on the deal comedy think it will affect timing any way, shape, or form?

Now, I wouldn't expect it to. I have no reason to believe that we'd expect it to.

That changes nothing as far as commitment common desire commenting on your end I assume?

No, none, whatsoever.

And our next question comes from Brian Lively with Tudor, Pickering, Holt.

In the Permian Basin, your horizontal drilling is pretty interesting but I was just interested in sort of a concept of approaching old water flood units with horizontal wells. The cost of their try to find lower permeable decisions that have been swept, or verticals or is there something else to it?

That's the primary answer. A lot of those reservoirs out there even under secondary recovery somewhere in the range of 35% to 40% so that's you're exactly right. That's what we're trying to get done has access reserves have never been touched.

We have a huge position with respect to specially water flows and the PUCO twos is done more that we have 26 different projects that we're looking at for CO2 so it's really at the present time, it's a somewhat of an experiment but if it works, you have a tremendous acreage position and full water potential to really ramp up production.

Switching gears to Australia, Pyrenees and Van Gogh, what are your volume limitations? I'm interested in as an oil volume water to total fluids and is there any upside as perhaps the water cut is lower than you expect?

There's a specific limitation on both the vessels, the thirties vessels come of the larger than what we have at Van Gogh. I think we're capped out at about, the Van Gogh little over about 65,000 barrels of oil per day capability. I forgot the number over 30 some it's a 100,000 barrels of oil per day is their capacity. In the second part of your question was what?

I was really just looking forward from the standpoint of total fluid handling versus oil volumes, I think you answered it.

It also has of a water and to date, we've seen no water in the first two months of production, which is really good news.

And we have no more questions at this time.

Okay, thank you. For other questions, I'll be in my office after the call.

This concludes today's call. We thank you for your participation.