Good day, ladies and gentlemen and welcome to the third quarter 2009 Sandridge Energy earnings conference call. My name is Lacy and I’ll be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Dirk Van Doren, Chief Financial Officer. Please proceed.

Thank you, Lacy. Last night, the company issued a press release detailing SandRidge's financial and operating performance for the third quarter of 2009 and also filed the 10-Q. If you do not have a copy of the release, you can find it on the company's website, www.sandridgeenergy.com. Also, you can sign up for all releases that will automatically be sent to you and this is located under the Investor Relations tab. Now, for the forward-looking statement. Please keep in mind that during today's call, the company will be making 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 and adjusted EBITDA, and other non-GAAP financial measures. As required by the SEC, the reconciliation to the most direct comparable GAAP measures are available on our website under the Investor Relations tab. Now let me turn the call over to Chairman and CEO, Tom Ward.

Thank you, Dirk and welcome to our third quarter conference call. We also have on the call today Matt Grubb, our COO and Kevin White, our Senior Vice President for Business Development. I’ll have a few brief remarks and then turn the call over to Dirk to discuss the quarter’s financial results. Our primary focus for 2009 has been to raise capital and strengthen our balance sheet in preparation of the Century Plant startup next year. As a result of the various capital transactions and asset sales that we announced, along with being disciplined about managing our capital program during a time of low gas prices, we were able to exit the quarter with nothing drawn on our $895 million bank revolver. The single most important goal, which we have accomplished, is to maintain the financial capacity to execute the growth strategy that we have mapped out through 2012. We call this our “Road to 2012 Plan.” This plan leads us to producing over 500 million cubic feet a day of gas in two years, primarily by ramping up development of our high CO2 gas in the Pinon field when the Century plant comes online next summer. Keep in mind that we can grow as fast or faster than any company in our industry. In fact, during 2008, we grew production 58% and grew by 72% from prior year. The primary reason for us being able to achieve this growth rate was having the available CO2 plant capacity to drill our Warwick Thrust wells. The Century plant will again give us the ability to grow as we did in the past years, but on a much larger scale. At year-end 2008, we had only 315 million per day of CO2 treating capacity. We currently have 375 million cubic feet per…

Thanks, Tom. Since our last call, we achieved our financial goals and are now in a position to move the company forward on a plan for growth over the next few years. Our internal model was projecting $130 million of EBITDA and the actual was $131 million. We had projected $100 capital expenditures and the realization was $98 million. And nothing was drawn on the revolver at quarter-end. Additionally in October, we successfully re-determined our $985 million revolving credit facility. Looking at a few of the numbers for the quarter, our production taxes were very low on a unit basis because of natural gas severance tax credits. These credits are positive to our financials, but difficult in terms of guidance because of the uncertainty of timing of the credits quarter-to-quarter. Turning to capital expenditures, our GAAP expenditures were $98 million for the third quarter and $542 million for the nine months. We use GAAP numbers in our internal model. We had $120 million accrual at the beginning of the year, which had declined to $34 million at the end of the third quarter, making our capital expenditure numbers flow through the cash flow statement slightly higher. Since our last conference call, we have not been very active in the derivative market. We have had added one basis swap in 2013 at $0.48. Moving to the capital structure, compared to the first half of the year, the third quarter was relatively quiet. Our goal, as we stated earlier, was to have nothing drawn on the revolver at the end of the quarter and that was achieved along with a cash position of approximately $15 million. Currently, our net revolver position is undrawn with a few million of cash, which is positive given the large interest payment this month and matches our internal plan. We were in compliance with all our financial covenants at the end of the quarter. Another area to discuss is guidance. We have lowered production guidance, which Tom discussed. Looking at our Analyst/Investor slides from a March presentation shows we thought EBITDA would be $595 million at a NYMEX natural gas price of $5. Please reference Page 94 of the presentation. So far this year, NYMEX has averaged $3.83, down 23% and our 2009 EBITDA performance should be a few percentage points below the March guidance. As for capital expenditures on a GAAP basis, we will be under the $700 million high end of the guidance range. Looking forward to our conference call schedule, we are now listing on the back of the press release for November, December, January, and February. Please plan – we plan to release our fourth quarter and year-end numbers on Thursday, February 25th after the market closes and have an investor call the following day. Additionally, we have scheduled our Investor/Analyst Meeting for the morning of March 3rd in New York City. That ends our prepared remarks. Lacy, we are ready to open the call for questions.

Thank you. (Operator Instructions). And our first question will come from the line of David Heikkinen with TudorPickering. Please proceed. David Heikkinen – TudorPickering: Good morning, Tom and Dirk.

Good morning. David Heikkinen – TudorPickering: Thinking about 2010 guidance, just wanted to be clear as you think about that either with or without the Crusader acquisition, the thought is as you can make that number. Is that –

That is correct. We don't know whether we’ll have Crusader, whether we’ll make that acquisition or not and won’t know until mid-November. David Heikkinen – TudorPickering: Okay.

So in our guidance what we did was to make sure we added Crusader in our guidance as we looked at our internal model anticipating the acquisition, but felt comfortable that we will make the 120 Bcf either way. David Heikkinen – TudorPickering: And let’s say Crusader doesn’t happen, do you further the production that is non-Crusader with increasing capital or do you buy something else or how do you make up that 7, 8, 9 Bcf depending upon what Crusader is producing now?

We already have the capital in our budget projected for Crusader. So we’ll just move that. David Heikkinen – TudorPickering: Okay. So basically, the $750 million budget includes the capital for Crusader. So you’d shift that to East Texas or Oklahoma or West Texas is the way to think about how you get to 120 Bcfe?

That’s correct. David Heikkinen – TudorPickering: Okay. And as you think about –

And we also feel like that we have enough room in our model that even if prices were lower and we needed to go back through a time of – let’s assume we had a warm winter or if prices got back down to the point that we don’t make any EBITDA or cash flow by producing wells or drilling, we would – we believe we have enough in this budget to be able to defer. David Heikkinen – TudorPickering: And as you think about the timing of Century now in the second quarter, really ramping activity mid-summer, are you thinking June/July start for Century? What’s the most recent update?

I’d say – I think that I've been consistent in saying either in the last part of June or the first of July and that weather could either move that up or move it back by a couple of weeks. David Heikkinen – TudorPickering: So no change?

– really in July I think is a fair – David Heikkinen – TudorPickering: So it’s really just rain or winter that slows or speeds things up is the only thing. Nothing on the track of deliverable items that –

No, everything is fine moving forward with building, just trying to narrow down a project of the scope. It is the second largest construction project in Texas and it does – trying to get it down to one day is a little bit difficult, but I think we are doing a pretty good job covering within few weeks. David Heikkinen – TudorPickering: And then as you think about second quarter to third quarter volumes, the curtailment and – can you walk us through kind of area by area production second quarter and then where it was in the third quarter so we can get an idea of kind of at this lower capital level, what your production actually did sequentially?

Yes, I’ll let Matt take that.

Yes, David. As you know, from Q2 of '09 to Q3 of '09 we went from 319 – I'm sorry, from 292 to 274, about a 6% decline and what’s not very explicit or visible here is that as we’ve talked a lot about the Century plant and talked a lot about our historical growth, it’s really all been driven by the ability to process CO2 gas, okay? So even though we had a decline there from Q2 to Q3 in total corporate production, we actually had an increase in production of 19% from our high CO2 gas and just bring – on an expanded time frame a little bit, if you looked at the first nine months of this year versus last year, corporately we had a 9% growth, but about 112% growth in high CO2 processing. And so what it tells you is that really what we are limited right now – the only thing that’s limiting our growth is plant capacity and we always have right now with a fixed limited capacity number as we drill new Warwick wells and even when we find very good Warwick wells that are 50%, 60% CO2 or 40% CO2. Units have been shut-in in a well that might be 70% or 80% CO2 so you can produce this particular new well and get more MMBtu process, okay? So that’s – so you never realize the full benefit of new wells and you always have some production shut in that are of poor quality. So that’s really the issues we’ve been faced with and then with the low price, we just can’t go out there – it does not make any sense to go out and drill a lot of other wells outside of Warwick at this time. So really that’s…

In Pinon, our net production probably 60%, 65% of that is from high CO2. David Heikkinen – TudorPickering: Okay. So as you think about the rest of the business –

David, also keep in mind that we have not drilled any – really any – David Heikkinen – TudorPickering: The Dugout Creek at all?

Yes, in Pinon it’s all just been in the Warwick. David Heikkinen – TudorPickering: So really what happened is the declines are a combination of your Dugout Creek, East Texas, Oklahoma, really you are growing some West Texas oil, but everything else declined to make up that company 6% decline is the way to think about the –

That’s right. And what we chose, David, is at a time whenever – of low prices, we didn’t want to drill (inaudible) wells. David Heikkinen – TudorPickering: Yes. And really, what I’m just thinking is from a snapshot inside of SandRidge gas macro and you are king of getting a look at conventional low rig count activity and how much that declines every day. Aren’t you? I mean, kind of just taking a step. So that was all that I was thinking through.

Yes. I don't think there is anything – David Heikkinen – TudorPickering: Different about SandRidge than any asset.

But most of – other than our high Warwick Thrust, we would decline much like any other reservoir in the United States. David Heikkinen – TudorPickering: Yes, interesting. Thank you, I appreciate the time.

You bet.

And our next question will come from the line of Dave Kistler with Simmons & Company. Please proceed. Dave Kistler – Simmons & Company: Good morning, guys.

Good morning. Dave Kistler – Simmons & Company: I want to follow up a little on Dave’s comments as well. If I just look at – as Matt outlined, the uptick in processing capacity to 375 million and then having another 100 million coming on let’s say July, just by ramping up in there, you can get pretty darn close to delivering that production growth. Is that fair or is the decline that you mentioned outside of that portfolio high enough that you are going to have to drill outside of Pinon as well?

No, I think that’s – I think that’s a fair statement. If we had Century plant today, we can outpace decline in other areas, just drilling the Warwick Thrust. So I think we can continue to grow production just drilling Warwick. What drives drilling outside Warwick is mainly pricing. So depends on what happens over the next three to six months. We can wrap up and will beat our 120 B’s guidance if pricing stayed kind of where they are at. I think we will be kind of flat going into Century plant. And when Century plant comes on, that gives us the adequate capacity to ramp up Warwick drilling and outpace decline everywhere else.

And we had capacity even this year with nothing drawn on a revolver that we could have had still an aggressive program and very good reservoirs outside of Pinon to drill and in fact, what we’ve looked at are rates return in excess of – or can compete with any of the – the best plays in the United States, but we have chosen to not really want to expand those at a time when you don't make any cash flow or EBITDA from that activity. Dave Kistler – Simmons & Company: That's helpful. And kind of following up on that, what commodity price would you need to accelerate in say, Texas, Oklahoma, et cetera and my thought there is that’s probably emblematic of where the commodity price needs to be for people to get after some of the more conventional plays.

Well, we target $6 NYMEX. Dave Kistler – Simmons & Company: And can you tell me what kind of rate of return that would throw off of those?

I think you’ve got that Matt. Don't you? Basically, we were in the – Matt can come up with I think the specific number, but those plays at $7 NYMEX I know that we were up in the close to 60% rate of return rate. So I think it’s in around 35% to 40%, but I can get an exact number on it. Dave Kistler – Simmons & Company: That’d be great.

Dave – hi – yes, Dave, this is Matt. I just looked at the current strip and this strip over the next three years is probably in this kind of $6.50 range in our rate of return of all our plays from East Texas to Mid-continent to Warwick onto our Ector County oil play, ranges from a low of about 15% to high of about 176% rate of return. The 176% rate of return is our Ector County oil play. The Warwick in that kind of price level is about 35% rate of return. So I think if we look at the strip over the next, say, just three years, you are in the $6 to $7 range and everything we have will work with a pretty nice return. Dave Kistler – Simmons & Company: Okay, that’s helpful. Then just looking at the Pinon and Warwick specifically, with another three months of results, obviously some of it impacted by what you chose deliver and from purely a curtailment basis, et cetera. Do we have any new information on where we think EURs are and what declines look like, anything like that that you could share this morning?

Everything within the Warwick Thrust is continuing to be exactly as we have stated. It’s basically 7.5 Bcf per well and anticipated 62% CO2 content and the per-well economics have stayed the same. We don't anticipate changing those. Keep in mind, the reason why that wouldn't change very much is we’ve drilled around the outside of the field except for we are having more expansion. But if you just take all of the wells within known gas there – that has the same distribution across the field of good wells and bad wells. And I there is some maybe question about whether there is the quality of Warwick, but there we do drill some poor wells that don't have fracturing, but we drill excellent drills that have very high delivery rates. So that average is not changing. Dave Kistler – Simmons & Company: Okay, great. And then lastly, you kind of mentioned that you think there are about 30 structures that you guys have identified. I think in the release maybe you highlighted 20, can you just talk about how those are spread across the WTO? Is there any area brims [ph] as a huge sweet spot?

Not really. So what our belief is and what is coming to the model comes out from looking at our seismic, which has really just finished and we started interpreting this year. That shows that you have a very large of thrusting, has a leading edge with back thrust back – behind it and it would be unusual to have just one field in this type of geological setting. So we see Pinon and the Northwest part of the West Texas Overthrust and structures coming up against each of the thrusts as you move across the West Texas Overthrust. So what we looked at was a model that would show the same depth and size in comparison to Pinon and see those across the overthrust and those are 20 structures in the same formation as Pinon field. We have 10 structures at a very deep – in the 15,000 plus range Ellenberger and Fusselman. Those projects probably will be – not be drilled as quickly as looking at the same type of structures as Pinon just because of the depth difference and we know in the Ellenberger and the Fusselman are the deep zones that they’ll have high CO2, but we believe that as we move east across the West Texas Overthrust, we’ll see little to no CO2. And we don't see a degradation of structure size going to the east. What you do have is more exploration risk as you move east. And on the west side of the overthrust, you’ll see more of a risk for high CO2. So each area has their sets of risks. What we can’t tell with seismic, we can tell structure – what we can tell is structure. And we know that the source rock is there and there is gas in place. What we don't know is the amount of fracturing and the amount of CO2. Dave Kistler – Simmons & Company: Okay, great. Well, thanks so much guys, I appreciate it.

Thank you.

And our next question will come from the line of Matthew Lemme with Highland Capital. Please proceed. Matthew Lemme – Highland Capital: Hey, good morning guys.

Good morning. Matthew Lemme – Highland Capital: Dave and Dave kind of touched on this a little bit, but just in terms of the ramp-up production with the CO2 plant, help me understand something. So you are going to drill a bunch of wells in preparation for the opening of plant. The – what happens to those wells before you have a place to put the CO2? Are you drilling and completing and that just not hooking up to sales?

We will drill, we’ll complete and we’ll be banking that gas preparing for it to move, turn onto the Century plant when we turn it on. Matthew Lemme – Highland Capital: Okay. And so then – and that’s where you will get a pickup in production once that turns on?

That is correct. Matthew Lemme – Highland Capital: Okay. And then you mentioned that you would need about 11 rigs to keep that plant filled. About how many wells does that work out to in a year?

Well, Matt will grab that real quickly. The 11 rigs that we will use after it’s filled in 2011. So that’s kind of a 2012 and beyond, assuming that we don't have a need for additional capacity or additional sales of CO2.

Yes, hey, Matt. With the 11 rigs, you are looking at probably in the range of 100 to 120 wells. Matthew Lemme – Highland Capital: Okay. And then, if you were to drill one of those today, about what would they cost?

$2.2 million. Matthew Lemme – Highland Capital: $2.2 million? Okay. And that’s drill and complete?

Yes. Matthew Lemme – Highland Capital: Okay, terrific. And then Tom, I know you are viewing gas prices, but let’s just say gas prices don't go your way – you – at what point do you really ramp up 2011 hedging or what’s your timeline on – ?

I never know until we determine to change our view, but what happened – I can say what happened in the past was that last year we had a fairly bullish outlook and they by late fall to early winter, changed our view and hedged all of our 2009 and – well, 85% of our 2009 gas and then 70% of our 2010 gas and so I would assume the same thing this year. Once we decide that something wasn't going our way, we’d be pretty aggressive to hedge out 2011 gas. Matthew Lemme – Highland Capital: Okay, great. Thanks a lot.

Thank you.

And our next question will come from the line of Anne Cameron with JPMorgan. Please proceed. Anne Cameron – JPMorgan: Hi, good morning.

Good morning. Anne Cameron – JPMorgan: So the 11 rigs to keep Century filled, will that keep Century filled and all of your existing CO2 treatment facilities?

Yes. That keeps everything full for really the entirety of the contract with Oxy. Anne Cameron – JPMorgan: Okay, great. And then the inventory of wells that you have drilled but not completed by the time Century comes online, can you give us an idea of how much production that is? I’m sort of like how fast will you get the extra 100 per day in July.

I think what happens – what really happens is Century plant will be our lowest cost processing plant and how this will work is we are drilling and banking up CO2. As soon as Century starts, we are going to divert our gas from our existing legacy plants into Century and try to fill that up right away. And so what happens is you turn on gas and start filling the other plants as you overflow Century. And you do this really to maximize the value of your methane sales. And – so right now, we are looking at ramping up to 26 rigs by about mid-year of 2010, of which about 20 rigs would be drilling the Warwick Thrust. So we look at on average, maybe there is – for the six months, there is 15 rigs running. You are looking at drilling about 65 to 70 wells for the – in preparation for the Century plant. And some of that will be offsetting a little bit of decline as we fill out our current capacity of 375, but we only need about four rigs to five rigs to do that. So I anticipate these wells come on at 3 million a day of wet gas. (inaudible) bring on 150 million a day type when the Century plant comes on of wet gas. And so you got 30 – 34%, 35% percent of that is CO2. So probably 50 million a day of methane gross and then you net that out, you take 75% of that. Now you are looking at maybe 35% net methane. Anne Cameron – JPMorgan: Okay, great. That’s actually really helpful. Thanks. And then just one other question. The CO2 tax credit that you can claim the $0.53 per M, when will you be able to take that credit and do you have any plans to monetize that? I know you all don't play taxes at the moment and what’ll that look like?

We don't talk a lot about that because of the confidentiality agreement with Oxy. We can say is that there is a tax credit that is going to go through the plant and that we’ll share in that. And that really wouldn't start until the plant is up and running in 2010 and then would be full capacity in 2011. So it is a benefit to us and we don't play taxes. So we would have to find a way to monetize it. Anne Cameron – JPMorgan: Okay, great. Thanks very much.

Thank you.

And our next question will come from the line of Jeff Robertson with Barclays Capital. Please proceed. Jeff Robertson – Barclays Capital: Thanks. Good morning, Tom. Just a question on capital for 2010 with the $750 million budget you all are talking about. Are there development dollars in the budget currently in the event you make a discovery with your exploration program or would any kind of delineation type drilling be incremental to the capital?

That would be incremental and in fact, if we made a discovery and needed to develop, we’ll probably have to come back and talk about a restructuring of the company in some way to look at how we would develop another Pinon field. Obviously, everything we have looked at from a capital standpoint is just to develop Pinon and doesn't really anticipate having a discovery. So we – well, I believe we will have, it’s not something we contemplate to get from the capital standpoint. Jeff Robertson – Barclays Capital: Okay, thanks. And secondly, Tom, you all talked a little about that – the per-well cost of $2.2 million for the wells needed to drill or to fill the Century plant. But what kind of other capital – what’s the total capital amount that will be needed to keep that plant full including the wells plus any other infrastructure-type capital that you all will have – that SandRidge will be responsible for?

And – starting in 2010? Jeff Robertson – Barclays Capital: No, no. In 2012, once you’ve got the plant full and you are just trying to keep it full or if you just try to keep it full.

Yes, I think by 2012, most of that capital really will be drilling, because by then you have – would have pretty much built up all your infrastructures. What we try to do is build out pipe and then have compressions out ready in front of the drilling program at least six months. So by the end of 2012, we would pretty much be done other than some ongoing maintenance capital, compressor overhauls, and pipeline maintenance, things like that. But large capital expenditure we would pretty much be done with on the infrastructure side. And that’s not – that’s assuming we don't have a discovery outside of Pinon. If we do have a discovery outside of Pinon, then obviously everything changes at that point.

And the reason we don't set up an idea of what the capital is needed for a discovery is we don't know the CO2 content, we don't know if we would need another plant or not need another plant and we really have to see the quality of the gas before we make that determination. Jeff Robertson – Barclays Capital: Thank you.

Thank you.

And our next question will come from the line of Mark Meyer with RR Advisors. Please proceed. Mark Meyer – RR Advisors: Good morning, gentlemen. Tom, it sounds like a $6 NYMEX is really the threshold with respect to deferral and/or acceleration. What does that translate to from a net realized standpoint?

We model $0.70 corporately on a basis that it’s – we are hedged a little better than that, but I think you could basically say that’s $5.30. Mark Meyer – RR Advisors: Okay. Any recalibration to your macro in light of August 9, 2014?

Not necessarily. No, I still think that we are on target for – I do believe that we are working away excess as we speak and probably just add a little more gas to work through than I anticipated and maybe that moves it back some later than what I might have said a month or two ago, but I don't have a really good feel for when this happens in 2010, but I’m very comfortable that we are moving in the right direction and prices will be higher in – by the last half of ’10 or the first part of ’11. So I’d say that today, with the rig count where it is and I’m still a believer in higher prices in the future. Mark Meyer – RR Advisors: Can you talk about I guess the dominant risk factor and how you set your priority of the exploratory prospects? Is it chance of structure of is it risk of CO2 or a more complex combination?

Well, we have a lot of structures to choose from and the risk, I believe, the margins risk is fracturing and in Pinon field, the geology that is set up at Pinon field has extremely good fracturing obviously to get as much – to get 7.5 Bcf per well out of the well bore. So what we look for – we know the structure, so we can tell that – we can tell that we have the zone in place. So our – I think the – what we look at is the chance of CO2, which is on the west side, but you are closer to the Pinon field and you can tie those structures back to the Pinon field on seismic and so that gives you less risk of reservoir risk. And then on the west side – excuse me, on the east side, we know there is – they’re producing fields that are too small of structures that we wouldn't have drilled, but have produced tens of Bcf of sweet gas. So we don't think there is necessarily a high risk of CO2 on the east side of the West Texas Overthrust. The question then is that you are 30 to 50 miles away from your producing analogous field and you just have a higher expiation risk on – for your reservoir. Mark Meyer – RR Advisors: Last one. I’m looking at your Warwick IP scatter plot. Any thoughts about maybe tightening that cone as you go forward or are you just living with the – I guess, the inherent variability of the geology?

In the Warwick? Mark Meyer – RR Advisors: Yes.

It’s just inherent. We have a 60 Bcf well that was drilled in 1990 that was offset by a well that produced just several hundred million cubic feet, just – maybe just over a Bcf of gas. That’s just a part of all of the Warwick Thrust. You have gas wells in everywhere you drill and you have extremely good wells and poor wells and you take that average and you get 7.5 Bcf and that’s not changing. And there is nothing new that we’ve really seen. In fact, what you will see by the other plots that we show on that slide show you’re talking about, is that in fact we have wells that look like they’ll produce more than 60 Bcf, buy they were drilled in the last three years and you are not going to give that much reservoir – that much gas in a reservoir until you have a few years of production. So – for example, the well that has the 60 Bcf EUR that was drilled in 1990 would not have been projected to make that much gas in the early ‘90s. Mark Meyer – RR Advisors: Great. Thank you.

Thank you.

(Operator Instructions). And our next question will come from the line of Adrayll Askew with Hartford Investment. Please proceed. Adrayll Askew – Hartford Investment: Yes. Can you speak to the current environment in West Texas as it relates to services and what’s your expectation I guess going into 2010 as you guys ramp up your drilling program?

I’ll let Matt take a part of this too. We don't see any issue with getting services that we’ve hedged in a majority of our services through 2010 and as far as ramping up our rig count, we already have the people notified and in place to start that process. So we are well under way with our ramp-up. Matt?

Yes, I think Tom (inaudible) – I mean, most of our services on the rig side, we provide ourselves. So that’s not a problem there. And as we ramped up really in the period from – really towards the end of 2006, all the way up through 2008 where we went from roughly starting out with about six to eight rigs in Pinon, all the way up to 34 rigs in Pinon at the height of the industry there in the middle of '08. Really, what that did for us was it provided some services in area that will help us here on this ramp-up again. So the surface companies are there, the yards have been built and really, they’re waiting on us. So I don't anticipate any problems at all ramping up drilling in the WTO.

And Matt’s team also in the summer really started locking in discounts that will we’ll receive through 2010. So we have a very good feel for what our costs are going to be. Adrayll Askew – Hartford Investment: Okay, that’s very helpful. Thank you.

Thank you.

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

As always, we just appreciate your participation and please give us a call if you have any further questions. Thank you.

Thank you for your participation in today’s conference. This concludes your presentation. You many now disconnect. Good day, everyone.