Good day ladies and gentlemen, and welcome to the fourth quarter 2009 SandRidge Energy earnings conference call. My name is Jeanette, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. (Operator instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Dirk Van Doren, Chief Financial Officer. Please proceed.

: Now for our forward-looking statement; please keep in mind that during today's call, the company will make forward-looking statements, which are subject to risks and uncertainties. Actual results might differ materially from those projected in these forward-looking statements. Additional information concerning risk factors that could cause such differences is detailed in the company's filings with the SEC. Today's presentation will include information regarding adjusted net income, adjusted EBITDA, and other non-GAAP financial measures. As required by the SEC rules, a reconciliation to the most directly comparable GAAP measures are available on our Web site under the ‘Investor Relations’ tab. Now let me turn the call over to our Chairman and CEO, Tom Ward.

Thanks Dirk. SandRidge remains flexible in our plans and has demonstrated that we can move quickly and efficiently to execute ideas that will enhance the long-term value of the company. This is evident by the Forest Permian acquisition that we closed prior to year-end. As natural gas prices remained soft in 2009, we decided to re-risk our portfolio by lessening our exposure to natural gas and increasing our position in oil. We are today a company that is over 50% oil on a PV-10 value basis and have hedges in place to deliver $9.15 per Mcfe for 80% of our 2010 production. We are poised to move forward with a model that provides growth through a diversified portfolio of both oil and gas opportunities in areas of proven production, utilizing conventional drilling and completion procedures that keep our long-term cost structure low. We’ve also locked in over $1.1 billion of oil revenue from the sale of oil through 2012, and currently have six rigs running in the Permian Basin focusing on the Clear Fork formation but also developing low risk San Andres and Spraberry reserves. We continue to expand our drilling in the Pinon Field and now have 12 rigs drilling. The Century Plant construction continues to go well and we are slated for a summer 2010 startup. As we were exiting 2008 and entering 2009, we were well aware of the challenges that face SandRidge and took some timely, critical and successful steps through cash flow protection and strengthening the balance sheet. We hedged the majority of our 2009 and 2010 gas production at prices that have proven to be well above cash prices. In fact, our gas hedges increased the $3.36 realized field price by $3.84 resulting in a $7.20 per Mcf net realized price. Similarly, our average…

Thanks, Tom. 2009 was spot on based on our financial projections in terms of EBITDA of $584 million compared to our estimate of $595 million from our investor analyst meeting in March of ‘09. Our regional estimate assumed $5 per Mcf natural gas prices for ‘09 on an unhedged portion and the actual price was $336 per Mcf. This cash flow plus capital we raised, which Tom spoke about earlier, made the year highly successful from a financial viewpoint. Looking at the fourth quarter, we had EBITDA of $150 million, which was above our internal model, and we’re cash flow neutral during the quarter. We ended the year with nothing drawn on the revolver and we are in compliance with all our financial covenants. As we look at 2010, we have 106 Bcfe hedged at 950, thus a significant amount of our EBTIDA is locked in for 2010. Our focus in now shifted to 2011. While we have 4.9 million barrels of crude oil hedged at 86.52 per barrel we are un-hedged for natural gas. Based on the current strip price for natural gas, in 2011, we should be able to hedge a significant portion of our production and achieve a blended price north of 850 per Mcfe. Why is that possible, because oil will become a larger percentage of our production in future years. The new SEC reserve rules have caused investors difficulty understanding the impact across the industry. The SEC rule changes increase the likelihood of companies booking no value to negative value PV-10 reserves. So what is important; crude reserves or present value? Slide 8 in the slide presentation on our Web site includes SandRidge PV value per Mcf of proved reserves at different prices held constant as well as some of our peers. We choose these…

We will be in New York on Tuesday for our annual investor and analyst meeting, and we look forward to provide an in depth look at SandRidge. This ends our prepared remarks. Jeanette, we are ready to take questions.

Thank you. (Operator instructions) Your first question comes from the line of David Heikkinen with Tudor Pickering Hold. Please proceed. David Heikkinen – Tudor Pickering Holt: I guess I'll get the use of that someday. Aus think about the proved developed reserves going from 943 Bcf at year end to the 978 Bcf at the $5.79 price deck can you reconcile production acquisitions, revisions, and additions to proved developed?

David, we will pull together something here real quickly. I will probably let Matt take that question. David Heikkinen – Tudor Pickering Holt: Okay. And then as you think about the hedging, Dirk, you mentioned that you could get a blended price of $8.50. Are you thinking about structures that would include crude oil volatility or more complicated structures or do you just think of a flat swap?

No what we’ve done before. We don’t plan it doing it. That would be straight swops. That would be – priced yesterday at $83 per barrel for the 11 oil trade and it would be a 585 for the natural gas trade, straight swap.

We continue to be slightly bullish right now as I think we are seeing a tightening in the market on natural gas for the near term. But the problem is as we all know, that the gas rig count continues to climb and we are afraid as we move over the 900 to 950 range of gas rigs, that will ultimately have the negative impact on future prices and in think that’s what the markets worried about also. So it is a kind of a time here that we are saying we are going doing time to date, but we will look forward to the next couple of months of layering on our 2011 hedges. David Heikkinen – Tudor Pickering Holt: On the guidance, while Matt still looks at the proved development side, your oil volume guidance came down. Can you reconcile what changed from post-acquisition to now around the oil volumes?

Sure. That really was not meant to be a change in guidance other than taking away the high end of guidance. So we didn’t change the oil to gas ratio and there has not been an official change in guidance. David Heikkinen – Tudor Pickering Holt: Okay, so basically just expect to stay at the time low end, not – and if you think about activity levels, if you shifted more towards oil, I'm trying to read into, is there an opportunity to drive oil towards that high end of guidance if you shifted more activity there, or how much oil volume could you hit this year or next year if you were to shift that direction?

And today we want to talk about volumes changing any. But we will say that we are driven by EBITDA and if we move towards more of a mix of oil, you could assume that our goal is to spend the same amount of money and make the most of EBITDA we can. Now if you switch to oil, it is not as easy to grow production, but it is easier to make the cash flow. So that’s what the goal is, it is really to create value and not be held by this magic number of growth that sometimes can be meaningless, but yet the industry continues to be fixated on only volume and not on EBITDA. David Heikkinen – Tudor Pickering Holt: And then on the reserve reporting, the performance revisions going from 7.5 Bcf down to 6.6 Bcf, as your pressures were 500 pounds, had Netherland Sewell or had you all built in a future capital into your year-end '08 reserve report – to drop pressures ¬2010 Thomson Reuters. All rights reserved. Republication or redistribution of Thomson Reuters content, including by that would have maintained that 7.5 Bcf, or whenever we get the 10-K and look at the future development costs is there something that was in the proved side that said there was a compression component of future capital built into that 7.5 curve?

Yes, David this is Matt. On that question, the capital for compression is actually in the midstream capital. It is not running the Aries case. So basically what we decide – we didn’t burden the wells with the compression capital and we didn’t show any kind of an increase in reserves due to lowing the pressure. David Heikkinen – Tudor Pickering Holt: But in the 7.5 you had on assumption that you had lowered to 200 pounds, just so I understand that?

No. In the 7.5 – let me just back up a little bit on that reserves, we started out at about three year ago at 5 Bcf and all these oils were flown into about 1,100 pound pressure system. And as we increase our drilling activity, we also do a lot of field work, we had in lot of new pipes and a compression and we lowered the field pressure form 1,100 pounds to about 500 pounds. And all the PDP wells response to that lowering of field pressure and therefore moved the type curve up to 5 Bcf to 7.5 Bcf. As we ended our way, we had plans in 2009 to continue to lower the field pressure from 700 pounds to 200 pounds. As part of our budget catch, we decided to hold off on those projects. But as we didn’t lower the field pressure, the wells suffer from the 500 pound line pressure. So it came up to 7.5 Bcf type curve. David Heikkinen – Tudor Pickering Holt: So at a 500 psi system, you really should have been booking in the 6.6 B's, not the 7.5. Is what you are saying now on performance? Just making sure I'm getting that.

What we couldn’t tell at year end of ’08 was how those wells – they may find and not go up the curve in ‘09, but unfortunately they did due to the higher pressure. So at the yearend of ’09 that’s why we made a change. David Heikkinen – Tudor Pickering Holt: So you really aren't going back up to – the way would you go back up to 7.5 Bs is because of dropping to 200 pounds, not just maintaining 500.

That’s right. Our plan this year is to drop it to 200 pounds and we would expect the type curve to get back to where it was. David Heikkinen – Tudor Pickering Holt: Then would you have a capital investment for that midstream to take it back up to where it was. So your capital efficiency per well is a little higher. I just wanted to make sure I reconciled that. That's helpful. Do you have the proved developed?

Yes, let me just kind of walk through the proved developed here. We ended the yearend 2008 at 943 Bcf. And we had 223 of total write-offs and then we added through drilling a 137 Bcfs and then we had additional write-offs in what we call hails of a 130 Bs and then we produced a 105 Bs and then we added the Forest cycles – the Forest deal was 204 Bs in PD reserves, 440 total, 204 is in PD. So we ended the year at 823 Bcf of PD. And if you add the tails back in because of pricing improvement we would be at 953. David Heikkinen – Tudor Pickering Holt: Okay, that's all. Thank you.

Your next question comes from the line of Dave Kistler with Simmons & Company. Please proceed. Dave Kistler – Simmons & Company: Good morning guys.

Good morning. Dave Kistler – Simmons & Company: Looking real quickly at the 102 Bcf that was added from the Testnes [ph] on the performance revisions is that going to be – are you guys going to start putting that out as separate type curve coming from the Testnes, or is that going to be something that's going to be comingled with the Warwick thrust production as type curve? Can you just help us there? Then what would that type curve look like?

We will discuss the Testnes type curve at the analyst investor day. Rodney will have that and what will also show is that on most of the wells we can comingle, it's actually not comingle, it's dual complete the Warwick thrust with the Testnes and we'll have a separate type curve for that also. Dave Kistler – Simmons & Company: Looking at the capital budget of about $750 million going to exploration and production, can you break that up between the Pinon and the Permian side of things. And then as step 2 of that, what level would the Pinon to have stay at to honor obligations to Oxy, just to your comments on gas prices and wanting to maximize EBITDA is there an ability to take that portion of the budget even lower?

Yes. But here is the way we will discuss today is not change of budget from what we had because we were looking at moving from more gas rigs to oil rigs. But we haven’t made that change yet. So there is no official change in the budget, but we do have the ability to speed up or slow down our drilling, as you know there is a 30 year commitment of 3.5 Tcf of CO2 across the Pinion field. We haven’t lost the CO2, either fortunately or unfortunately the gas has tremendous amount of CO2 in it, and we still have those reserves in place. And that’s why we opt CNS together made a very long-term contract so that we could flexible in the amount of gas we want to bring on in one particular year or maybe a span of years. There are penalties that can be incurred but there are not to a point that it wouldn’t – if you have made that choice, you would be much better off today drilling over the gas, and remember, we do have a substantial amount of gas, it is already flowing into existing plants that we can move all to Century which we plan to do. Dave Kistler – Simmons & Company: Okay. Just for a little clarification on that, Tom, I'm sorry, so what percentage of that $750 million is allocated to Pinon?

$: Dave Kistler – Simmons & Company: $430 million, okay. And the flexibility on that, just so I'm clear about it, is actually pretty large because of the term of the contract. Right?

Right. Dave Kistler – Simmons & Company: Okay. So if you want to change that later, you can. And then, thinking about oil inventory and the ability to accelerate there, after having the Permian properties for a couple of months what are you guys thinking about as far as drillable locations there? What upticks are we seeing versus when you originally purchased it? Anything like that?

I will let Matt this specifics but, we love the acquisition that we made and we love being in oil and we continue to see a lot of upside in the properties that we acquired and Matt will go through the specifics, do you have those specifics locations Matt?

Yes, I man on the Permian, you know the good thing about the Permian is when we bought it we really – we bought at a higher oil price than what we booked at the year end, because the year end was a 12 months average. But at the acquisition pricing we basically bought it for very close to PDP value. And as a turn out, we have a roughly 27 hard locations out there to drill, about 800 PUDs and plus 1,900 what we call resource locations. There is quite a bit of room to run there and a lot of that is very low risk, increased density, plus close in extensional type drilling. So it's just a lot of drilling. Right now, we are running six rigs and we are looking to potentially wrap it up to eight rigs as the year move on down towards – maybe in the middle of the year. Both these locations are Clear Fork locations. That’s something we have been drilling for the last three years in Nitric [ph] county area. Dave Kistler – Simmons & Company: Great. One last, if I may. Looking at the new type curves associated with the Pinon, and realizing they're temporary in nature, as you bring compression back, can you just talk about what the break-even price would be as far as the production associated with those wells, just so we can be think about in terms of, okay, if pricing hits a certain level, as analysts can we expect that we'll see an adjustment to the capital budget?

Yes, I think that the break even for the – our PUDs has been running at 387 but out there in the Pinion field at a little over $4, you start adding PUDs back in. At about $5.25, they are pretty much kind of back on the book. So I think, year end, it’s $5 range or break even. Dave Kistler – Simmons & Company: Okay. And that's at the wellhead in the Pinion, that $5?

That’s right. Dave Kistler – Simmons & Company: Okay great thank you guys so much.

That’s just a break even on development costs to drill the well. Dave Kistler – Simmons & Company: Okay great thank you guys so much, I really appreciate your time.

Thank you.

Your next question comes from the line of Brian Singer with Goldman Sachs. Please proceed. Brian Singer – Goldman Sachs: Thank you good morning.

Good morning. Brian Singer – Goldman Sachs: Question on the borrowing base. You mentioned that you're seeing interest of some banks getting into that. I wanted to see where you thought the borrowing base would go, and your interest in tapping that and whether that would be for additional acquisitions versus spending above cash flow to drill more oil versus gas wells.

The borrowing bases would stay at 850; we really don’t need any more money than that. And right now, we have no plans on acquisitions. So any shortfall, we would just use on a borrowing base.

I would just clarify that we always look at acquisitions. If we have the opportunity to make another Forest type acquisition, we would probably try to do that. Brian Singer – Goldman Sachs: Thanks. Then secondly, can you talk about any horizontal opportunities on the Forest properties or any of your other oil properties?

Yes, we do have. We will be addressing those on Tuesday on the analyst day. Brian Singer – Goldman Sachs: Great. Thank you.

Thank you.

Your next question comes from the line of Joe Allman with JPMorgan. Please proceed. Joe Allman – JPMorgan: Thank you. Good morning everybody.

Good morning. Joe Allman – JPMorgan: Hi, Tom, looking at slide six in your presentation to try and figure out what's your assumption now for the dry gas EUR in a typical Warwick well?

Our type curve is 6.6 Bcf. I believe that whenever we put in our compression, will lead back to the 7.5 Bcf per well and the upside what we show is 8.4 Bcf. What we will talk about too also on Tuesday is just if you add the Testnes through this, we can enhance our reserves even more that way. So we just internally ask to look at this as a 7.5 Bcf type of well. Joe Allman – JPMorgan: Okay. But in terms of just the methane component, the dry gas, I think previously – I'm sorry –.

Really not changed any Joe. As we have always looked at 62% to 65% of two and that’s still fairly consistent. It might change from over time from – we might have been as low as 62 to as high as 65, where you can give yourselves a 5% range in that CO2 across the field. Joe Allman – JPMorgan: Previously you were saying just over 3 Bcfe, and then I think in December you were saying something like 2.9 Bcfe or so. So you're still think about those kinds of numbers?

Yes. I mean on a 6.6 type curve, you will arrive at 2 Bcf, that’s netting out CO2 as netting back to – netting up the royalty. That’s typically about 23% out there. And then these are net Bcf, gross Bcf, basically you just take the amount of netting content multiplied by your –

I do think that’s the difference that we come up with, some people and there may be some of the slides we have had, we have talked about gross gas without net of royalties, so I think that’s making the difference that we are talking about. Joe Allman – JPMorgan: Got it. So when I look at that slide and I see the red line, that's a performance of your wells, right?

That’s right. Joe Allman – JPMorgan: So in general, your wells have done better than your type curve. It looks like the most recent wells have been hugging that 8.4 Bcfe type curve.

That’s little bit dangerous to look at, because if you have a components of your wells at the front end of the curve, I think the type curve led you follow the type curve. Joe Allman – JPMorgan: Thank you. And then in terms of your year-end he reserves, at the SEC price deck, what was the percentage of gas reserves at year end '09?

We should have that handy, don’t we? We are going to flip to that, from a volume basis? Joe Allman – JPMorgan: On a volume basis. We got the PV-10.

Gas was 52% and oil 48%. Joe Allman – JPMorgan: Okay, got it, thanks. In terms of the acquisition, when you put out your press release on the acquisition it indicated you bought 482 Bcfe, and at year-end '09 talking about 440 Bcfe. Was there a 42 Bcfe negative revision?

Well, those are really tail effect, and would run at lower gas price where you go negative cash flow a few years are there. Joe Allman – JPMorgan: Okay, got it. So most of that was the tail effect on proved developed reserves?

Well, that will be across the board. But I can't remember the exact price but you know you ran stating $5 and now you are cutting off at $57. Joe Allman – JPMorgan: Okay, got you. All right. Thanks, very helpful.

Your next question comes from the line of Eric Anderson - Hartford Financial. Please proceed.

Yes, good morning. I wonder if you could just take a minute or two and talk about some of the exploration prospects that you've got lined up for this year. On the gas side that is, the Pinon types.

Yes, we have two rigs that are currently drilling wells that we said will be down in the first quarter of this year. That still is true. We will talk more about those two wells and where there are at, at the analyst day. We continue to have plans to drill six exploration wells across Pinion in 2010. And we haven’t chosen any of the other structures yet, because we want to see these two wells down and get it log. And really there is nothing more to discuss today on those, other than we will talk more on Tuesday.

Okay, fair enough. Thank you.

Thank you, your next question comes from the line of Wei Dow [ph] with Stone Harbor. Please proceed. Wei Dow – Stone Harbor: Yes. I didn't catch the number on the PD you ran through the changes on a proved developed reserve. There was a write-off – hello?

I think we understood. You want the change in the proved developed reserves that we gave? Wei Dow – Stone Harbor: Yes, you started with 943 and then the second number you were running through and you are saying some write off; that was related to what write off?

Well, those just are reversions due to type curve changes, high-line pressures, that kind of stuff. Wei Dow – Stone Harbor: Okay. What number was that?

That number was 223 Bs. Wei Dow – Stone Harbor: Okay.

Okay? And then we added 137 Bs prior to conversions and new drill. And then we lost 130 Bs due to the tail impact of lower pricing. And then we lost 105 Bs due to production. And we added 204 Bs of PD reserves from the Forest acquisition that gets you to 823. And as price have improved – prices are already higher than year end, so what you could do is add that tail back in so that gets you back up to 953. Wei Dow – Stone Harbor: Okay.

So you would potentially have a positive increase in PD reserves, even through all the revisions – Wei Dow – Stone Harbor: Okay. Just in terms of the way – looking at your press release, page three, where it breaks down the reserve changes, I'm just a little confused. For example, the 223 write-off, is that amounting to the non-price revision, or does that get knocked out with your extensions? Because clearly you added 133 of PDs – just PDs – through drilling, but I'm only seeing a net of nine on that page three.

I am sorry; let me get to where you are at. Wei Dow – Stone Harbor: So, If I look at the page three, 9 Bs of reserve under the SEC rule, I'm assuming the revisions are price related, and your PD reserve didn't really go up, then the $800 – or is it $600 million of CapEx, what did that get spent on?

Yes, I am sorry. The net revisions was – when we talk about a net reversion, the total performance, going through all the numbers it comes up to 313 Bs of net revisions and 255 Bs of positive add. So that is I think 58 Bs differential, or call it 60 Bs, okay, and this is some round impact. So when you look at page 9, it revision of 69 Bs in extensions – this curve you have 9 Bs. That’s the difference right there. The 260 in net revisions match up. Wei Dow – Stone Harbor: Okay.

Those are performance revisions. The 1.123 negative revision is all due to pricing less the 130 Bs in tail write-offs because of lower – because of higher economic limits, because of lower prices. Then the 993 Bs remaining are the gas PUDs write-off. They are due to pricing. So basically you have 1.123 Ts of write-offs that are attributable to pricing and net 60 Bs write-off that are attributable to performance. 305 Bs [ph] of production. Wei Dow – Stone Harbor: Okay. All right, thank you.

Thank you.

Your next question comes from the line of Jeff Robertson with Barclays Capital. Please proceed. Jeff Robertson – Barclays Capital: Thanks. Coming back to the high CO2 gas in Warwick Thrust, if you moved all of your gas, do you have the flexibility to move all of your current production into the Oxy plant when that comes up?

Yes. Jeff Robertson – Barclays Capital: :

No, we won’t be able to reflect that until next year’s reserve report after we see – we can project efficiencies, but we need to see it before we put it into our reserves. Jeff Robertson – Barclays Capital: Can you talk a little bit about or put some parameters around what those efficiencies might be?

Sure. Matt, you take that.

Well, from an efficiency standpoint, one of the problems we have now is that the plants that we are operating through, the technology that we are using are dated. These legacy plants were processing CO2 were built in the late ’60, early ‘70s. And it’s an absorption process with the proprietary chemical called Selexol. And when we flashed the gas from 1,100 pounds down to 2 pounds to extract the CO2, we lose probably 6% to 8% maybe 9% of methane out the stacks right now. With the Century Plant, there is two processes there. There is absorption process like the Selexol, I just described, but also there is a refrigeration or fractionation process. It’s a two-step process of extracting CO2, but in doing so you improve your methane losses. It will drop from about 8% down probably in the 2% range. So right there, you should gain about 6% in methane sales just in the process of sale. But that’s not booked, or that’s not mull in our projection nor is it booked in our reserves run. Jeff Robertson – Barclays Capital: Matt, could that an impact then on the overall 6.6 Bcfe to 7.5 Bcfe type curve?

Sure, it could be an impact. I don’t know what the magnitude of that impact might be. But anytime you can show higher sales there per Mcf from the well head, because you will have a gain at the tailgate of the plants. That will certainly help with type curve and with your PDP forecast as well. Jeff Robertson – Barclays Capital: Okay. And, when you do that, if you just – at the end of the year, when you look at moving your current production over, when you move it over, how much CO2 would be coming out of that plant? In other words, how much of the obligation would be satisfied by existing production?

Let me answer it this way. The annual obligations are confidential due to competitive reasons for Oxy. However, the outlook is 3.5 Ts over 30 years. You can do some simple math there and get around to what an annual obligation might be. But just with our current production right now in the high CO2 gas, close to 300 million day of total volume, you are looking at probably 75 Bs or 80 Bs right there alone if we didn’t do any drilling of CO2. With the drilling that we are doing this year, we’re probably going to produce, I am guessing, in the 90 Bcf range of CO2. And then – we’ve also been banking volumes with Oxy to the tune of 30 Bcf, 40 Bcf over the last couple of years. So I don’t think there is going to be a problem at all in meeting the obligation at this point. Jeff Robertson – Barclays Capital: Last question you all before, if I remember right, have talked about some midstream monetization in 2010. Is that still something that's possible?

Sure. I guess that both of us have an option. I think the way we’d describe it is CCW has an option and SandRidge has an option, and we'll be reviewing that this year. Jeff Robertson – Barclays Capital: Okay. Thank you.

Thank you.

Your next question comes from the line of Brian Kuzma with Weiss Multi-Strategy. Please proceed. Brian Kuzma – Weiss Multi-Strategy: Hi, good morning guys.

Good morning. Brian Kuzma – Weiss Multi-Strategy: You guys may have already given this today. Did you give the production split on production from Pinon versus Permian on the fourth quarter numbers?

I think we have that. Hold on for a second.

Just a minute Brian. Brian Kuzma – Weiss Multi-Strategy: And then just a more conceptual question. I think it's one that everybody is asking themselves here today, is – you guys need $4 to book close to the PUDs in Pinon, and you guys used to have a chart that showed Warwick wells having higher rates of return than all the other plays, and all the other producers booked all those PUDs at $3.87, I'm just curious what your thoughts are on that – versus what other operators are doing versus what you're doing and – if there's something else going on there.

I can only address what we do. But I can say that a low rate well, if you are forced to have flat pricing for ever, doesn’t have as a good rate of return as a high rate well with flat pricing. A low rate well in a market in contango has a better rate of return than a high rate well that brings on the production early in the life of the well. If you believe that prices are going higher in the future it’s better not to produce as much of you gas early in the life of the well. So that if you kind of think through that math you can kind of get to the different rates of return that you might have between high rate initial wells and low rate initial wells with less decline. Brian Kuzma – Weiss Multi-Strategy: Okay.

Okay, Brian, back to your first question. You are asking about production? Brian Kuzma – Weiss Multi-Strategy: Yes.

And you wanted a breakout. Is that correct? Brian Kuzma – Weiss Multi-Strategy: Yes. That’s right.

Okay. Brian Kuzma – Weiss Multi-Strategy: Probably as many assets as you are willing to give.

Yes, I can give you everything here. You are looking at Pinon is nearly half of our production; and this is a very current data. You are looking at probably, of a total of 300 million a day production, you are looking at 120 million from Pinon, 72 million from the Permian. These are all in Mcfed. 36 million from East Texas, 17 million from the Gulf of Mexico, 28 million from the Gulf Coast, 23 million from the Midcontinent, and about 3.5 million in other, including tertiary. Brian Kuzma – Weiss Multi-Strategy: Okay.

And then your other question was the PV-10 of total developed? Brian Kuzma – Weiss Multi-Strategy: Exactly, yes.

That’s about $1.1 billion. Brian Kuzma – Weiss Multi-Strategy: And then one last one from me. When I looked at Forest reserve profile at year-end, it looked like they booked the Permian like they added a whole bunch of PUDs and booked the Permian at, I think like 550 Bs or something like that using year-end pricing. You guys always booked it at 440 Bs. Is there some conservatism there that you guys think that you could be able to book just more PUD reserves out there at year end, you guys versus Forest? I'm confused.

I don't remember Forest having that number. But I don’t believe there was ever a published number like that from Forest. Brian Kuzma – Weiss Multi-Strategy: Okay.

I think we basically – the only thing, the only difference we had was that we lost some reserves because of the tail that we mentioned that came in really just as we booked. We only owned it just a few days before the end of the year.

What I can say is that we did some sensitivities in that as you can see in that one slide, but if you use the spot price of year-end 2009, of about $78, $79 a barrel, book reserves for Forest would have been very close to that 550. It’s in that 525, 530 range. Brian Kuzma – Weiss Multi-Strategy: Got it. Okay. That’s helpful.

That was moving up from where we were. Brian Kuzma – Weiss Multi-Strategy: Okay. Thank you.

It was about 482. Brian Kuzma – Weiss Multi-Strategy: 482?

That’s right. Brian Kuzma – Weiss Multi-Strategy: Okay. Thank you, guys.

Thank you.

Your next question comes from the line of Andy Rob [ph] with SPR. Please proceed. Andy Rob – SPR: Hi guys. Good morning. Just had a quick question on capital allocation; I was hoping you could just help me understand why spending up to $100 million on the new SandRidge Commons building is a good use of capital for shareholders, particular if you are cash constraint. Thanks.

Sure. We had – you ask about the building, correct? Andy Rob – SPR: Yes.

We had an opportunity in 2007 to either – we were out of space in the existing building that we were in and we had 10 floors there and we’re looking to buy land and build or the opportunity came to buy what is potentially here downtown about 1 million square feet of potential space where we are going to take out some of the building so it won't ultimately be that much, but – for $25 million. And then we built out some of the floors and if we were to move forward over the course of time, you might be able to get up to the price you are talking about. But it is – we felt like, one, it’s a very good investment for us. It was cheap real estate to own. It's great to be downtown. And we are glad that we made the purchase. I think it is a good asset for us and gives us ample opportunity for growth in the future. And we own two city blocks of downtown Oklahoma City. Andy Rob – SPR: Okay, thanks.

This is Dirk. I might add that number $100 million is going to be spread out over 5 years to 10 years. So it’s not a huge amount of expenditures that are going on right now.

And assumes future growth. Andy Rob – SPR: Okay, thanks.

Thank you.

Your next question comes from the line of Philip Dodge with Tuohy Brothers Investment. Please proceed. Philip Dodge – Tuohy Brothers Investment: Good morning. I just wanted to ask you the current cost of the Clear Fork well, how much that’s gone up from the bottom and what the trend in recovery in one of those wells would be?

Sure. The cost is basically the same as we discussed earlier. At one time, we got down to where we were drilling wells just under $700,000, it might be just over $700,000 per well now. The type curve is in one of our slides I think is 67,000 MBO and 115 million cubic foot of gas. Clear Fork wells have just a tremendous rate of return at today’s prices. And especially where we’ve drilled the – now about 120 wells in the Goldsmith Adobe Unit, the rates of return have been phenomenal. Philip Dodge – Tuohy Brothers Investment: Okay. Thank, Tom.

Thank you.

(Operator instructions) Your next question comes from the line of Gregg Brody with JPMorgan. Please proceed. Gregg Brody – JPMorgan: Good morning, guys.

Good morning. Gregg Brody – JPMorgan: Just a follow-up question on reserves, just for some clarification. I think I was a little confused on the discoveries on my part.

I am sorry Gregg, I can’t hear you. I am sorry. Gregg Brody – JPMorgan: How's that?

Better. Thank you. Gregg Brody – JPMorgan: Just in terms of the expenses and discoveries, the number which is nine, is some of your concealed drilling showing up in different category than in the previous? You talked about that 255 number of positive additions that is showing up in the revisions number.

Showing up in our reserve numbers? Gregg Brody – JPMorgan: I'm just trying to reconcile that why that extension and discovery number is so low. Is it different from the way other companies report?

Well, the 255 was it so low? Gregg Brody – JPMorgan: No. So the expenses and discoveries number, you have 9 Bcf of adds there. Then you mention the 255 of positive adds that’s showing up in the revisions, that's part of the changes to previous estimates. Is that basically in-field drilling that's driving that?

Yes, it’s really all in-field drilling. Gregg Brody – JPMorgan: Is that different from the way other companies typically report it?

Usually I think in-field drilling would be reported the same way. Gregg Brody – JPMorgan: And then just a follow-up question on the same line item – revisions to changes to previous estimates. It looks like it goes up and then down as you move the price up. I would think as price goes up that would keep going up. Do you know what's driving that?

Yes, Matt’s got that one.

Are you talking about on the table? Gregg Brody – JPMorgan: Yes.

Hang on. Let me reconcile the math real quick here.

Do you have any other questions while Matt is doing some math. Gregg Brody – JPMorgan: No, I think that's it. Just maybe one more. You broke out your oil percentage for the P-10. The value – what is that for the actual proved reserves?

What’s the oil value? Gregg Brody – JPMorgan: No, on a percentage of the proved reserves.

For percentage on the end of year case? Gregg Brody – JPMorgan: Yes.

I believe that is – I was going to say off the top of my head. I’ll give you the exact number. We can get that one, too. What's the percentage on oil end of year?

End of year oil by volume.

By volume. I think we said that earlier. I thought it was 48%.

By volume, your end of year reserves is 48% of oil.

Brian, I'm going to let Rodney Johnson, Head of Reservoir, answer your last question. He can do a better job than I can on the number movement there.

Yes, Brian, if you follow – Gregg Brody – JPMorgan: Gregg.

Gregg. I am sorry.

If you follow the extensions and discoveries bucket that is a calculated number and as you move up the price scale what we had identified is extensions and discoveries. Some of those didn’t actually run at year-end, at the higher prices those actually run, so you can see a delta from 9 to the 29. What really happens is all the other buckets are calculated as far as price changes, acquisitions, divestitures, and extensions. And essentially that number is the delta that makes up the change in reserves. So as that extensions goes up the revisions gets slightly bigger. Gregg Brody – JPMorgan: Okay. Thank you, guys.

Thank you.

At this time, we have no further questions. I would now like to turn the call back over to Tom Ward for any closing remarks.

As always, we thank you for joining us and we look forward to seeing you next Tuesday in New York City at the analyst and investor meeting. Thank you.