Tertiary Oil Guidance
Mike Sciala – Stifel Nicolaus: On your tertiary oil guidance you said you’d be towards the high end of the range there. It looks like if you continue to grow at the same rate you did in the first half you’d be above the high end. Craig, given what you said about what’s going on with the various fields, what would you need to see to change that the preset guidance up a little bit more?
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Craig McPherson – SVP and COO: Well may be just for clarity. So we said it will be in the upper range, so what that means it will be between the midpoint and the upper number. Where we end up is going to depend on the pace at which Oyster Bayou, Hastings, Heidelberg and Delhi respond over the next six months. So really we are watching those fields as we mentioned we are very pleased with how they are performing but there is uncertainty on the month-by-month basis on how they are going to respond further so we are just acknowledging that uncertainty in that range. So while its possible we can be on the high end of that range it’s not a slam dunk and we really just need to watch the performance of those fields over the next six months.
Mike Sciala – Stifel Nicolaus: Can you say where the tertiary production is now or maybe what you saw in July?
Craig McPherson – SVP and COO: No.
Mike Sciala – Stifel Nicolaus: I thought that might be the answer. For Thompson field on your last call you said you needed to do some more work to see how much of that field would be floodable, do you have any better sense now on Thompson Field?
Phil Rykhoek – President and CEO: We are still looking at it I don’t think we have anything at this point to change anything we’ve said, I think we’d just stay with what we previously stated.
Mike Sciala – Stifel Nicolaus: In terms of your proved reserves that you booked before Hastings I think you typically book about 75% of the potential that you see in these fields looks like you book a little bit less than that at Hastings is that because it’s a bigger field and do you anticipate booking any more proved reserves there by the end of this year?
Phil Rykhoek – President and CEO: You might get some minor adds, but it isn’t too far off, the 75%. If you look at the range – well, we’ve been given a range on it, but as we in our slides show at least the low end of the range is 60, so 75% of that will be 45. It was a couple million barrels off, but it was very, very close to that same 75% estimate, so pretty much on track on both Hastings and Oyster Bayou, we do expect to add reserves in the future. Maybe you get some small blocks by year end, but I think it will be more likely over time as the field response, and we can justify it.
Mike Sciala – Stifel Nicolaus: Then on your well cost in the Bakken, I think, you were targeting below $10 million, it seems like it’s crept up a little bit. Yet I hear that everybody is seeing more service availability there, do you anticipate that that will translate into lower well costs in the second half, or where do you stand there now in terms of sort of the mid-range for a 20 frac stage well.
Craig McPherson – SVP and COO: Yeah. So, maybe for clarity, our Bakken well prices have come down significantly. So, last year, we were over $11 million a well. In our first half, we’ve averaged about $10.5 million. Our current costs are coming at or below $10 million per well, and we still see room for improvement. So, we’ve seen a steady significant decrease in our Bakken D&C costs, so we’re actually quite pleased with where we are with that trend, and really still pursuing additional cost savings, but we believe we’ll be below $10 million.
Mike Sciala – Stifel Nicolaus: How do the economics there now stack up to your CO2 play?
Phil Rykhoek – President and CEO: Well, you’ve seen our slide so we’ve consistently stated that we think that our EUR probably has given us better returns in the Bakken and I think it would still be there. Obviously it helps the lower cost that’s a big factor and of course the other part of the factor is we just get a lot better pricing for oil and EUR then we do at the Bakken. But we would still see returns on EUR quite a bit better than Bakken as far as rate of return.
The Bakken Follow-Up
Neal Dingmann – SunTrust: Just a quick follow-up on the Bakken. The well cost coming down is it besides the efficiencies or I know a lot of people earlier had number of fracs and different things that are already contracted. Now do you have any longer term contracts that are expiring that could make cost come down or is it more just efficiencies that will continue to push the cost down?
Craig McPherson – SVP and COO: It’s primarily efficiencies that results from moving to pad drilling, but also we’ve really improved our efficiency in particular just to recall avoiding shell strikes that not hitting shells that require us to do additional work on the well. So that’s improved greatly. We have renegotiated some of our services contracts and so that’s starting to manifest itself in the cost. We’ll continue to have those discussions with our service providers. I don’t know that we have a big contract that’s upcoming that’s going to have a sizeable shift with its expiry. Really for us there is no magic bullet, we look at every piece of the puzzle related to our joint efficient cost and want to be excellent at each one of them and so that really is just driving our cost reduction.
Neal Dingmann – SunTrust: Do you anticipate going after some Three Forks in a different dense’s there or will you leave that to others for now and just kind of continue as you’ve been drilling?
Craig McPherson – SVP and COO: We are drilling the (Three Forks) expansion and most of our wells for later part of this year.
Phil Rykhoek – President and CEO: Well we have only tested the second or third…
Neal Dingmann – SunTrust: That’s what I was getting at, I guess.
Phil Rykhoek – President and CEO: We are watching the industry on that.
Neal Dingmann – SunTrust: Just lastly over, you mentioned the Jackson Dome I think adding that rig, that because of the type of drilling that you are doing over there won’t add to the reserves would that second rig though, well can we expect a bit of an increase just on the production side, because the CO2 for the remainder of the year and then is there idea of maybe adding that third rig over there?
Craig McPherson – SVP and COO: What we are really doing, is we are building CO2 volumes for next year and for the future. So that’s first and foremost it takes a while to get them online. So it’s really in 2013 that you’ll see the CO2 where we increase. And then we don’t, we also are gaining efficiencies on our drilling in Jackson Dome area so we’ve done that too. So I don’t think you’ll see us go above rig program and into the future. Let’s make that clear I want to just make sure because we think we can get to the volumes that are required with the existing wells that we have scheduled to be drilled.
Neal Dingmann – SunTrust: Then just lastly you all have been pretty disciplined on the hedging strategy will you kind of continue just as far as percentage going, already given the continued commodity volatility out there?
Phil Rykhoek – President and CEO: I guess our philosophy is to try to hedge the 12 to 18 months out and as you know that we have hedge all the way through the end of ’13 so we’ll continue with that philosophical concept I guess. We do try to be opportunistic though and to layering more hedges when prices are high and kind of watch it when prices come down a little, so that’s one reason we haven’t put any in place in the last month or two, as oil has been little bit weaker. So, we’re patient, where we think – we’re very well protected through the end of ’13, so we’ll kind of watch through maybe an uptick in prices, and layer on some more.