Good day everyone and welcome to the Apache Corporation fourth quarter and year end 2009 earnings conference call. Today's presentation will be hosted by Mr. Tom Chambers, Vice President Corporate Planning and Investor Relations. Mr. Chambers, please go ahead.

Good afternoon everyone and thanks for joining us for Apache Corporation's fourth quarter and year end 2009 earnings conference call. On today’s call we’ve taken a little bit different approach from previous calls and intend on using our remarks to provide additional context for the 2009 results and 2010 year ahead. Therefore in order to allow you to focus more on the comments, we’ve prepared a detailed supplemental data package and placed it on our website. This supplemental information plus the reconciliation of any non-GAAP numbers that we discuss such as adjusted earnings, cash flow from operations or costs incurred 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 included on our website at the same URL. On today's call we'll have four speakers making prepared remarks prior to taking questions. Steven Farris will kick off the session and he's our Chairman and Chief Executive Officer; followed by John Crum our Co-Chief Operating Officer and President of North America; then Rod Eichler our Co-Chief Operating Officer and President International; then concluding with Roger Plank our President. With that, I'll turn the call over to Steven.

Good afternoon everyone and thank you for joining us for Apache 2009 year end results earnings call. The year 2009 was obviously a difficult year for the industry due to the sharp drop in commodity prices, and the weakened economy. Going into the year Apache decided to reduce our investments to ensure that we lived within our means, without need to tap the capital markets or dilute our portfolio. So we ended the year with growing 53% fewer wells than we did the year before and investing 40% less capital. We have ramped up activity somewhat toward the end of the year but we really won’t start seeing the benefits of that until in 2010. So in that context we’re very satisfied that the Apache’s team managed to increase production by 9% for 2009. We came out of the year with more cash on our balance sheet than we had going into it. And we did this without diluting our shareholders’ ownership of our upstream portfolio. On the cost side our cost management efforts during the year were successful. We managed to reduce lifting costs for BOE by 20% during 2009. And overall we had strong cash flow from operations after a dismal first start. We generated over $5 billion and had adjusted earnings of about $1.9 billion. This performance is a testament to the strength of our team and the quality of our portfolio around the world. Every Apache employee is focused on maximizing value and growth on every property. And this is easy to claim but very difficult to actually do. It involves an awful lot of geoscience and optimization work but every location, pre-completion, work overs, all add to real value and real growth and you’ll see that in our 2009 performance. I’d also like to highlight…

Thank you Steven, at the onset of 2009 Apache adopted a cautious approach to North American expenditures in order to allow time for costs to adjust downward to levels reflecting the challenging commodity price environment. Overall we [kept] 2009 investment in North America by near 50% from the 2008 level. We are very proud of the fact that our regional teams were able to hold production essentially flat, down 1.3% while drilling 61% fewer wells in 2009 than in 2008. While I won’t suggest it will be available every year, our large base of HBC properties provided our teams with many opportunities to optimize production from existing wells. This production level was also achieved without any meaningful contribution from new growth plays such as the Horn River and the Granite Wash which we will be ramping up significantly in 2010 and beyond. You will note fourth quarter North American gas production was down 4.4% from third quarter. That’s mostly due to severe weather in Canada where we had widespread freeze up problems. Just a few of the more important 2009 highlights include the start up of [inaudible] in May. Eight months later the two well field is still producing 78 million a day gross, that’s 31 million net to Apache. The Horn River activity ramp up we drilled a total of 42 gross wells but only completed four. The four wells were completed last summer and continue to produce in excess of four million cubic feet per day each and they [inaudible] our reserves for awhile in excess of 10 BCF for each well. We hold a 50% working interest in that activity with partner in [Canada]. The horizontal Granite Wash activity, our first operated Granite Wash well the Hostetter 1-23H in Wheeler County, Texas, came on production in late…

Thank you John, Apache’s international regions reported excellent results in 2009 highlighted by outstanding exploration and development activity and by seeking out and entering into new markets to sell future production of natural gas in Australia and Argentina at more attractive prices. Production in our international regions grew by 21% in 2009 to a yearly average 300,000 barrels of oil equivalent per day driven by drilling successes and significant increases in Egyptian oil and gas production, as well as significant increases in Australian gas production. Our Egypt region had another outstanding year. Net production averaged 152,600 barrels of oil equivalent per day, an increase of 38% over 2008. For the year Apache drilled 164 wells in the western desert including 23 wildcats. Once again making Apache the most active and successful operator. Fourth quarter drilling successes in the AEB at Phiops and [inaudible] 2-X in the Faghur Basin along with successful completions in the [inaudible] concession in the Jade Field and at Falcon helped drive gross production to record high 316,000 barrels of oil equivalent a day at year end. Apache’s Australia region production in 2009 increased 40% to 40,400 barrels of oil equivalent per day driven by the restoration of our Varanus Island facility. Apache took a large step forward in 2009 towards securing new markets for its Australian natural gas by agreeing to produce our estimated 2.1 TCF of natural gas reserves at our [Julemar] discovery through the Wheatstone LNG facility operated by Chevron. We expect to complete the feed study and make final investment decisions in 2011. First production is scheduled for 2015. North Sea production averaged 61,400 barrels of oil per day in 2009, an increase of 2.5% over 2008 levels due to increased production from several wells drilled in early 2009 and higher production efficiency…

Thank you Rod and good afternoon everyone. What a year, a tale of two cycles, financial armageddon followed by a recovery that’s surprised virtually everyone in the spring. What started out as a downright scary year ended with $1.9 billion of adjusted earnings or $5.59 a share for the year. Fourth quarter adjusted earnings more than doubled the $664 million or $1.96 per share from the fourth quarter of 2008. And they were the strongest earnings of the year. Who would have thought it. Cash from operations were just shy of $5 million for the year and over $1.4 billion for the quarter. Compared to our initial plan the cash flow was 36% or $1.3 billion higher enabling us to increase drilling capital by $350 million and acquire $300 million of properties while still living within cash flow. Our 9% production growth despite 40% less capital speaks to the benefit of our long-term approach. Clearly this growth could not have been achieved if not for first production from a number of significant long-term development projects. Exploration success continues to add to our pipeline of development projects providing growth visibility that can really move the needle once brought online. Despite higher production and substantially reduced capital Apache added 215 million barrels of oil equivalents through drilling and acquisitions outpacing production of 213 million barrels of oil equivalent at a cost of $3.5 billion. These additions were added at $16 per barrel of oil equivalent and were quite economic as some 40% of our additions were oil. At $70 a barrel oil sells at 14 times the price of gas leaving plenty of profit margin. This growing disparity between the value of oil and gas underscores Apache’s advantageous product mix. Oil and NGL comprised half of our production with 72% of our…

Thank you Roger, I’d like to close by summarizing what I think are the three main messages of all the information that all the gentlemen have shared today, the first is 2009 was a good year for Apache. We had strong growth in a challenging environment with restricted capital and well count. We really owe this to the performance and hard work of our team and their focusing on generating growth and value. The second message Roger just mentioned is that we expect to have 5% to 10% net production growth in 2010 and I might add in addition our development drilling program will deliver 100,000 barrels of oil equivalent per day by the first full year of its contribution in 2011. And third we built a well balanced global portfolio of growth areas for the long-term. The diversity of our 2010 operating plans outlined by John and Rod I think reflect that. So 2010 is going to be a very busy year for Apache. And with the organization and opportunity set there’s much more in front of us in the years ahead. So before we go back to work, we’d be ready to take your questions.

(Operator Instructions) Your first question comes from the line of Bob Morris – Citigroup Bob Morris – Citigroup: I have a question looking at your findings about cost and reserve replacement by region, Canada was by far the best region in terms of both reserve replacement and finding costs even after revisions, and that’s been a challenging region for other companies out there. Was the strong extension and discoveries that you booked in Canada, the result of a lot of floods being booked at Horn River or what drove that.

I might open it up, Horn River is our big play. We had some flood drilling locations that we drilled this year and basically we have one year of drilling, a pad drilling program for 2010 started up. But we really didn’t change the way we looked at our business. If you looked at our overall portfolio our [pads] are up 3% year over year. Bob Morris – Citigroup: So most of the extensions in discoveries you booked in Canada were [pads] at Horn River.

Yes that would be correct. But the real point we’re making there is that we haven’t really got ahead of this year. We really just pudding up the next year’s drilling program. Basically an extra pad alongside the pads we’ve already drilled. Bob Morris – Citigroup: And the revisions that you recorded in Egypt, were those all associated with the PSC contracts essentially.

Yes, that was all price. Bob Morris – Citigroup: I know you had a great year in Egypt with all the exploratory and drilling success, the oil price that you did those adjustments on or the PSC contract was based, looks like about $63 a barrel, yet you’re finding development costs in Egypt was over $31 a barrel, and I just wanted to get you comments on the economics of that because I would have expected perhaps a lower finding and development cost, that oil price given the success that you had in Egypt.

I will tell you what happens, because of the oil price you get a real, when you say what we booked, what we booked is the same thing that’s happened to us on a revision side frankly because you have to run that through the PSC. If we had $40 a barrel your finding cost probably would have been a third of what they are today. And it really is a very economic place because what happens is is that you get all your costs back in four years. So you’ve got to be real careful whether we show really good finding costs or we show really high finding costs in Egypt that if you run it on one price or you look at it on a gross oil basis, it would be much better off if you understand what I’m saying. Bob Morris – Citigroup: Yes because I was looking at $63 per barrel was the price you had to base your bookings in the PSC on and the finding cost is running about a little over 50% of that oil price which is the basis for your bookings which I would have expected it, the finding costs to be maybe a third of what oil price basis was.

But you see the problem is your reserves and I’m sure Tom can answer this, you run your reserves through the total PSC to come up with what your extensions are. Just like the base, so it effects not only your reserve revision but it also effects the amount of reserves you book. It’s a timing difference.

The only thing I would add to that is that you have to take into account that you have a cost recovery mechanism of the PCS in that you have a large balance of costs are constantly growing forward and that’s a big difference on one quarter to the next on one year to the next depending on how much money is in that pool from your prior year spending. And additionally the cost recovery Steve mentioned was prior to capital expenses over 16 financial quarters, you’re operating expenses were recovered were [inaudible] over four financial quarters or one year. So it’s a complex mechanism because of the PSC. Basically when prices are up we lose revenue interest on our share. When prices are down we benefit in the opposite direction.

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

I wanted to get a little bit more color on the Permian basin especially since you’re now going to be designating it as a new unit, can you talk about the materiality of your program for this year and whether that’s an area that you expect to grow solely organically or whether that’s in your outlook for additional, maybe larger acquisitions.

I think that’s one of those places we’d like to do both in. We’ve got a number of interesting exploration ideas that we will be trying over the next year but its certainly an area we’d like to grow by acquisition as well. Its been good to us. We’ve got a good operating group responsible for it and we think we can grow that region for years to come.

And what do you expect to be your contribution from this year’s program and then similar to how you were presenting the contribution to year end or 2011 barrels a day.

I’d probably have to get back with you on, I didn’t break that out here but you can imagine the primary program out there that we outlined for you was in full development program so I would expect any activity we get out of exploration won’t be showing up really until 2011.

And then looking at your capital program which I think you mentioned was based on $70 oil and $5 gas, if oil prices do end up averaging $75, $80, $85, would you look to increase capital budget and where would be your priorities oil, gas regionally for incremental spending.

I think our mantra is we’d like to stay around our cash flow and if we see just like this year frankly, we spent more money that we started out. I think we started out at $3.5 billion and we ended up spending I think $4.1 billion or thereabouts. If we see higher oil prices and higher revenues, net cash flow we’ll spend more money. And that probably will come in several regions, Australia is pretty well set just because of the rig activity and but we certainly could spend more money in North America and in the central region. We could spend more money in the Gulf of Mexico. Actually we could spend more money in each one of those regions and then we could also spend more money in Egypt.

When should we expect or what timing are you looking at for selling any off take for Wheatstone gas contracts.

2015.

In terms of when you would actually sign a contract—

That would likely take place prior to final investment decision before mid year 2011. We’ve got to be real careful were not [inaudible] that back, so we probably know some things that we’re just going to have to defer to the operator.

Your next question comes from the line of Joe Allman - JPMorgan

Just a question on reserves again, in terms of your and again on revisions, on your total revision and I know its complicated somewhat by the Egypt production sharing contract but your total revisions, what was the percentage of prove developed revisions and the percentage of [pud] revisions.

Well we don’t have our Vice President, Executive Vice President of Corporate or Engineering here we’re going to have to get back to you on that. All of the revisions were priced and I would imagine a big chunk of them were proved developed. But I, that’s a guess.

In terms of the reserves acquisitions, you made in 2009 you bought some reserves, I think it was mostly in the US, was it mostly prove developed or [puds].

Well actually that’s the only one we really made of any size was Marathon and that’s probably 70% or 75% proved develop producing.

And on New Brunswick, are there any results in New Brunswick to speak of either by you or any other operators.

Well the operator has come out with a little bit of information on a test they did last year, but we really feel like we need to get in there and they did a vertical test last year and we were pleased enough with the results there that it made us go ahead and take this opportunity. But we’re going to draw horizontal wells this year and actually test the concept.

And then you made a comment about the acquisition environment and I missed what you said, what is the acquisition environment look like these days.

Well I basically said two things, we’re not in hot pursuit of anything in particular at the moment, we’re just hearing of more things and so its our sense that the pipeline of acquisitions is beginning to thaw now that the world isn’t coming to an end.

Your next question comes from the line of Doug Leggate – BofA Merrill Lynch Doug Leggate – BofA Merrill Lynch: I have a couple of things I wanted to go through, jumping right to Egypt your production obviously is bumping up pretty close to your target that you set a few years back, can you talk a little bit about was the ramp up in exploration drilling with the Salam 5 plant, just generally in terms of the overall prospectivity of the western desert particularly on the oil side, what exactly do you see the production potential moving over the next few years.

As you know the numbers we put out for 2010 we’re looking at a program drilling wildcat drilling program that’s kind of back to our “normal” levels which runs around 30 wells a year. So its about 30% increase over, or 50% increase what we had in 2009. We have a even though we completed our Salam gas rigs 3 and 4, last summer, we have continued drilling successes through 2009, we still again find ourselves in a situation with the need to add more processing capacity to the western desert by building this fifth Salam gas train which we intend to initiate construction by year end as I indicated. We have a lot of gas behind pipe as well as oil and these are condensate rich gas zones that have yet to be produced so it’s a matter of when you want to get it out and if you could live with the current facilities and stretch it out over many many years but we have a lot of near-term opportunities to increase net present value of that gas by producing it sooner as opposed to later. Of course the government of Egypt is very interested in adding more processing capacity to accommodate the additional production because of the almost insatiable gas demand in the country of Egypt which continues to grow about 11% or 12% annually. So we have a very robust inventory of prospects, drilling about 175 to 200 wells a year and the exploration prospects continue to spawn additional development drilling year by year. There’s been kind of a consistent pattern for the last decade, we’ve been drilling now some 16 or 1700 wells in the country and are successful on exploration development is very consistent year on year. Doug Leggate – BofA Merrill Lynch: What I’m really kind of working out here is you’re going to drill 30 plus exploration wells this year what is the, if you could talk to the backlog of what have you actually got in Egypt in terms of longer term potential. There seems to be a lot more oil as you have talked about and I think has a lot of geological [inaudible] in the western side of the desert, so it looks like you’ve got a lot of oil prospectivity there and I guess if you could overlay on that, what is the horizontal potential in that region and also I guess you’re going to have to reset your target at some point because you’re getting pretty close. I’m really trying to get a feel for is that incremental production going to be oil and if so what are you really see as the potential of this area let’s say in another three to five year target.

The first part of your question with regard to the oil prospectivity, what we’ve observed is our recent drilling programs moving westward toward Libyan border and the Faghur Basin area west of our main properties base, is that things appear to be more oily there. Perhaps because its cooler from a geological sense but clearly the wells we’re making there are oil wells. And they’re oil wells that are deeper than you’d normally see in that part of the desert. Our backlog of our inventory we are looking continually evaluating, assessing prospects are developed off of our very large seismic inventory. In fact we’ve been reshooting some of the areas, our main producing area that we’ve shot a decade ago and the data quality now has been amazing in turning up even more and more ideas. Whether its on exploration projects or production enhancement projects or work overs, we have the, every year we have this inventory of maybe like 300 production enhancement projects and then we do the jobs, the next year we still have 300 production enhancement projects to do. The work continues to spawn other ideas and other work whether its on the exploration side, the exploration drilling, or the development of production enhancement activity. Now as far as horizontal applications, activities for horizontal exploration in Egypt are really not even touched. And we are beginning to investigate through horizontal drilling certain formations, certain reservoir sequences that we think could be applicable to such and but many times these things have been done for years in North America and they just now arriving on shore in Egypt. There are no known horizontal plays operating in the country but we’re looking to see what we can do in that area from what we know from North America activity. We have four horizontal wells planned for 2010. Doug Leggate – BofA Merrill Lynch: I guess I’m not going to get the answer on the three to five year production targets, the only other one I have, moving to North America, I hope I’m not touching on any sensitivities here but the Horn River is obviously one thing but you have been pretty active right next door in the [inaudible], I’m just kind of wondering if you can give us any update on your activities or your plans on what you’ve seen so far and how that has played into you decision perhaps to get involved in Kitimat.

We’re buying a lot of acreage in a lot of different places in the world and Canada happens to be one of them. So that’s pretty much what our position is going to be there. Doug Leggate – BofA Merrill Lynch: The likely timing of when you start to see gas plus in Argentina start to [inaudible] those realizations and I’ll leave it there.

The first contract which was for the 10 million a day, that actually started last month in January.

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

A couple of questions, let me start with you mentioned a five and 70 that you’d be generating, did you say you’re going to generate 6 to 6.5.

Roughly.

If I’m looking at forward guidance if I put, if I just look at margins, to generate $6 million at five and 70, [inaudible] is flat, are there any other changes as far as any other components that are moving significantly because it seems like that implies a higher margin for next year.

That flat that I mentioned excludes taxes other than income and so when oil goes up we get hit in the North Sea with [inaudible] CRT so that’s probably works a little bit against what you’re saying but in general you’re probably on track.

It seems like a cost structure coming down a little more next year. You’re excluding the impact of taxes is that accurate.

Our cash cost per unit probably are going to be, we’ll, as I indicated we’re going to target having it flat excluding the CRT and other taxes other than income. So wouldn’t have more production, we’d probably see a little higher costs but when you spread it out over more production DOE will be up, if we hit our target it will be flat.

You talked about the Permian basin have you started doing any horizontal work down there yet or anything on that front as far as activity to apply that technology down at the Permian.

Yes we have as Rod indicated on his work in Egypt, we’ve also doing the same thing in the Permian basin picking out targets and doing some of that drilling. We’ve actually have a horizontal well being completed as we speak in our [inaudible] Lake unit so, that will be a fairly active play for us down in the Permian this year because we really want to see what kind of potential we have in the large acreage base we have down there.

And that’s just going to be an ongoing program throughout the year, we may hear something later in the year.

Absolutely and I hope you hear a lot about it later in the year.

In Egypt, as you move west is there any I know you announced an agreement today but as I think about historical Apache to the kind of the western desert, and some of the oil exploration is there any difference in the cost recovery mechanisms or anything you can share.

The cost recovery mechanisms of course can vary from concession to concession because each is an individual law. However for Apache’s concession, the 22 concessions we have the variance between the concessions is very, very small.

With the exception of one and that’s [Karoon] and the production is—

We have no shared excess cost recovery in [Karoon] and at north [Eldiau] are very tiny concession. All the rest of them have shared excess and very favorable physical terms in terms of profit splits. Renewal terms, the two that we just renewed, very importantly the called offset that was a seven year extension, that we had approved by the government. East [Baharia] it was a three year extension. Called offset is very important to us because it’s the home of one of our bread and butter operations historically and this will be unlike a typical exploration concession that you’d be granted in the country, there are still relinquishment associated with the seven year, the block seven year term to do all that work.

And the splits don’t generally change.

The splits stay the same, they’re the same base physical terms as we had from the original concessions.

Your next question comes from the line of Ben Dell – Bernstein Ben Dell – Bernstein : I just had one quick question, you’re obviously ramping up your capital program a lot and I was really wondering how much is your rig cost and service costs have you got locked in going into 2010 particularly I guess in the US on shore business given the horizontal rigs right now.

I think there’s very little right now, perhaps the only place that may not be that way is in the Gulf of Mexico where we usually take a longer view of our jack up rigs, but certainly the land rigs in the US we still believe they’re going to be flat because the vast majority of things that are drilled in the United States today are still gas. And I think gas was down [$0.03] today so I doubt if you see a real surge in rig rates here at $5.12 gas.

Your next question comes from the line of Brian Lively – Tudor Pickering Brian Lively – Tudor Pickering: Just a question on the Granite Wash, given your vertical well control can you give some color on variability in reservoir properties across the play both laterally and then within the major productive horizons.

I don't know how much color I can give you, but you’ve called on a key point there, clearly across the entire Granite Wash play there’s a variety of numbers of sands available for development and different yields we would expect out of those. So we obviously have a pretty good feel for what we’d see in some of the areas that we’ve drilling for years out there and so we’re concentrating on those areas that first of all would have the highest liquid yields, with that said we’re going to be a lot of work around really trying to set our entire position out there over this year. So you should expect us to be very active in that Granite Wash play across our entire acreage position this year. Brian Lively – Tudor Pickering: We talked, we’ve heard about the [Marmeton] and the [Etoka], but what are the other intervals that you will be pursuing in the coming year.

We’ll have [Marmeton], [Etoka], we’ll have, we talk a lot about the Granite Wash A, B, we talked about the Caldwell. We have a variety of them that we’ll be testing this year and really the interesting piece for going forward on this play in my opinion is getting to the point where we could actually get where we could do multi laterals and develop more than one of these intervals in the same well bore. But we’ll be trying that concept out too. But I think that’s where the future is. Brian Lively – Tudor Pickering: You are going to try multi lateral in 2010.

Absolutely. Brian Lively – Tudor Pickering: Switching over to the Horn River have you tested both the [Muskwa] and the [Clua] intervals.

Yes we have. On our present, we have one well completed in, well we actually have two wells completed at [Clua], the first one is a vertical well but we have one horizontal well completed in [Clua] from 2008, however we were somewhat compromised on the frac jobs we got on it and we only got four frac jobs out of it. It is about half as thick as the [Muskwa] so we won’t spend as much time on that because if you’ve got certain number of rigs running you’re going to go after your bigger targets first. But I will tell you we’ve got two wells on the 16 well 70-K pad that we are completing right now, two [Clua] wells are in that mix and so we’ll know a lot more about the [Clua] by the end of this year. Brian Lively – Tudor Pickering: And since you’ve had some run time on I know its just a select few wells but has your spacing assumptions changed any now that you have some production.

That’s what I was talking about experimenting some more out there, we’ve got a lot of activity going on, the pad we’re drilling presently are 52-L pad, we’ve actually spaced, we’ve brought the spacing between individual laterals out to two different widths. We’ve added about 80 meters to one side of the pad and about 50 meters to the other side of the pad. And that’s, the real key out here is we’ve got literally 200 pads worth of potential at 15, 16 wells per pad and so far we’ve got four of these developed so we’re trying to get the right answers on the big picture. We’ve got a lot of activity to go. In a perfect world you would get your spacing between horizontal well bores out further and put more fracs in the individual laterals and that’s what you’ll see us doing a lot more of this year, up to 20 fracs on an individual lateral. Brian Lively – Tudor Pickering: And how long of a lateral would that be for 20 fracs.

Well we’re out to 2200 meters.

Your next question comes from the line of [Marvin Hayes – CVP] [Marvin Hayes – CVP]: I was wondering obviously given cash on the balance sheet, liquidity, etc., we’ve been talking about expansion of CapEx and property acquisitions and things of that nature, with that said I’m wondering are there existing properties or plays at this point that from let’s say reach critical mass or would demonstrate superior economics compared to some of your other opportunities that may be potential candidates for divestitures as you optimize your portfolio.

We’re not a very good seller. Its hard enough to [find]. [Marvin Hayes – CVP]: Clearly they’re cheering I guess so I guess we should simply watch where the capital dollars go in order to assess that.

We certainly do, I’m always jaded by, we bought some things over from Exxon over a number of years and its always been a cat fight. The gentleman that used to be pretty influential in Exxon used to tell me, because we were arguing about 40 acres, and he said Steven, 40 acres was a lot its hard to come by so we have a little bit, not that we’re anywhere near the quality or size of Exxon but we have a little bit of the same and the reason is frankly if you look across our portfolio and I’ll give you for example, let’s take [Nebis]. It was a little shallow gas play and all of a sudden we drilled CPM wells on it and I think we probably are still producing 80 or 90 million a day out of the [inaudible] methane at [Sabah] that we really didn’t see. We’re talking an awful lot about Granite Wash, we probably got Granite Wash 500 wells. We drilled our first Granite Wash probably in the 50’s and we’re getting ready to come through there with a horizontal play that we have HBP of 200,000 acres. Or if you look at some of the things we’re doing in west Texas, horizontal wells and the water floods and all of a sudden you are able to increase production. Only acreage in real well known hydrocarbon areas really gives you an advantage especially if you’re large which is why you see us in large positions in most places that we’re in.

Even if you look at Horn River, that grew up under a marginal play for us. We added a lot of acreage but it really started with ratty old acreage that we hadn’t sold. There’s a lot of optionality in some of that old stuff that doesn’t look very attractive. It’s a hard thing to source through because it shows up in costs and you’ll wonder why you’re holding onto it and then every now and then you find something underneath it that makes it more than worthwhile. [Marvin Hayes – CVP]: In the past when we’ve looked at potential basis differentials and realization in North American natural gas the Rockies, in past historically was particularly good standing, obviously with pipeline takeaways and access to the eastern markets much of that has been alleviated. But as the [Marcelus] comes on to become a very significant material producer in the next three to four years, can you assess your North American natural gas portfolio, are there places where you’re concerned about basis differential or simply crowding out of perhaps supply that’s closer to market than you may be and how you might be thinking about potentially directing those concerns going forward.

I think honestly it’s a very good macro question, because as these shale plays have come through there’s absolutely no doubt that you’re going to change the dynamics in North American gas. Now what the end results of that is, I’m not real sure. Because it has a lot to do with pipelines etc. but there’s no doubt that [Marcelus] is in a favorable position. We’ve seen that frankly a little bit in the Gulf Coast with the Haynesville gas going across. Its fascinating to me that depending on the price you get basis differentials in Canada from $1.30 and its probably the lowest its been right now than it has been in a long time. And you ask yourself why. I’m not sure but I think it is generally and we don’t have an answer for it frankly right at the moment. But trust me we are very cognizant of that. But I don't know what the drivers are going to be other than closeness to the market.

And we’ve got to keep our costs down and that’s one advantage that Horn River play has ultimately it sets up very well geologically and that ought to be able to enable us to get our costs down and therefore suffer a bit more of the transportation and distance differential.

Your final question comes from the line of Ken Carroll – Johnson Rice Ken Carroll – Johnson Rice: Quick question back to the investor conference you talked quite a bit about your eagle your position, [inaudible] how you attempted some oil, is there any further testing in that. I think you mentioned looking to the gas window a bit.

We are going to be doing a little more testing this year. I will say and it’s a different area technically. Having said that so was the [Barnett] shale at one time, back when it was making 300 MCFs a day and frankly Devon had the foresight to go out there and buy it. But there will be a time and I really believe this and I don't know when that is from a technology standpoint the [Eagleford] the important thing about it is its got some of the highest per acre coal in place of any shale play in the United States. So and the important thing about that is we’ve got about 450,000 that sell by production. So we can like most of our acreage one of the reasons you don’t see us as trend setters a lot in North America is most of our acreage is held by production so we can let people do an awful lot of experimenting before we turn the technology. Same reason we’re starting to get in west Texas, there’s been a lot of horizontal wells. If you look on the map you can see that. But we have a tremendous acreage position out there that now allows us to go out there and really start exploiting our base property. Ken Carroll – Johnson Rice: But the early wells you have talked about have all been in the oil window, I thought you had mentioned at some point trying to go in the gas window, has that been done or is that part of the testing this year.

I’d hate to say it this way but I think we’ve got lots of gas.

There are no additional questions at this time; I would like to turn it back over to management for any additional or closing comments.

Thanks for joining us today and if anybody has any further questions, I’ll be in my office after the call.