Good day, ladies and gentlemen, and welcome to be 2010 Third Quarter SandRidge Energy Earnings Conference Call. My name is Modesta, and I will be your operator for today. [Operator Instructions] I would now like to turn the conference over to your host for today, Mr. Dirk Van Doren, Chief Financial Officer. Please proceed, sir.

Thank you, Modesta. Last night, the company issued a press release detailing SandRidge's financial and operating performance for the third quarter of 2010, and we'll file the 10-Q on Monday. If you do not have a copy of the release, you can find a copy on the company's website, www.sandridgeenergy.com. 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 on 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 rules, a reconciliation of the most directly 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.

Thanks, Dirk, and welcome to all of you to our third quarter conference call. I want to start by telling Dirk that we wish him all the best as he moves on from SandRidge. I've known Dirk since 1994, and I worked with him over the last four years on a daily basis. I'll miss his wit and tireless work ethic. However, I fully understand that there are changes in all of our lives that we have to be prepared for. In this case, Dirk is leaving us with a transformed company that is focused on a high-priced commodity with fantastic rates return. I am personally more enthusiastic about our company now than any time since June of 2008. Over the last two years, we've made some strategic changes that has separated us from many of our previous gas-weighted peers. We decided to significantly change our company by enhancing our exposure to oil. We did not focus on tight shale plays with high land cost, but instead focused on low-risk, high permeability oil carbonates in proven producing regions. We've made our first move into the Permian Basin at a time when adding conventional oil assets was out of favor. The resulting Forest and Arena acquisitions closed just eight months apart have transformed our company and positioned us to excel in the current environment. Just in the last 12 months, our oil production has grown from about 8,000 barrels a day to over 28,000 barrels of oil per day. Keep in mind, this production is a high-grade mix of 83% crude oil and only 17% natural gas liquids. The natural gas liquids space is obviously crowded and potentially faces future process and capacity issues, or worse, an oversupply of natural gas liquids. We're therefore not relying on a market that may…

Thanks, Tom. For the third quarter, we are continuing to see the impact of our strategic transition as oil revenues including hedges accounted for 68% of commodity revenues for the quarter, up from 56% in the previous quarter. EBITDA for the quarter was $149.2 million, and including the out-of-period hedged settlements, it was $197.4 million. We are in compliance with all covenants. At the end of the quarter and the balance in our revolver in early November, net of the preferred transaction and Green Shoe, was about $230 million. A few other numbers in the quarter need explanation. First, G&A was higher because of two one-time items. There was a $10.7 million cost related to the merger cost with Arena, and there was a $16 million cost related to a legal settlement. Second, the $457 million tax benefit related to Arena. The transaction was a merger for tax purposes and Arena had approximately $250 million tax basis in the assets. And we had to write the assets up to fair value of about $1.6 billion. That created a $460 million deferred tax liability. And SandRidge was carrying a $1.1 billion deferred tax asset with the full cost of valuation allowance created by our 2009 impairment. With the enclosing of the Arena transaction, we were able to use part of our deferred tax asset to offset the liability and the tax benefit. We still have over $650 million deferred tax asset with the valuation allowance. Since our last call, we've added over $775 million to our hedged book. Over half of the amount is crude oil in 2013 and a portion is natural gas in late '10 as well as '11 in the first half of '12. We currently have $2.3 billion of revenues locked via swaps and that could easily write to over $3 billion in the next three to six months. Finally, I'd like to thank Tom, the Board of Directors and all the SandRidge employees for a fantastic experience for the last four and a half years. I look forward to facilitating a smooth transition to my successor, who will also enjoy the support of an excellent accounting and finance departments. I wish everyone in the SD family all the best as the future of SD is brighter than ever. That ends our prepared remarks. Modesta, we're ready to take questions.

[Operator Instructions] Your first question comes from the line of Neal Dingmann with Wunderlich Securities.

On realized prices, Tom, as you kind of see going forward. I guess number one, just kind of as you see the mix, Tom, between the oil and liquids, how do you see that kind of playing out? It looked like maybe the realized prices were down a little bit because of that. And then secondly, just kind of the differential as you see that as you do a little bit more horizontal Mississippian and kind of what you see on I guess the overall differential in oil sort of on a go-forward basis.

We're at 83% crude. So I think we model to 85% or so but basically staying the same as we are now on the liquids to crude mix. As far as differentials, with that 15% to 17% liquids, the differential should stay about what we have today. The mix is crude oil, The liquids are left in, in the gas stream. The Permian drilling is 85%, 86% crude. So I mean on the margin, we'll move up a little bit on crude to liquids. But it should stay fairly close to what we guided here.

Your next question comes from the line of Duane Grubert with Susquehanna Financial.

Tom, can you talk to us a little bit about the ramp up logistics? So in terms of capital spending, we all tend to look at a number and want that all to be for well drilling. But can you talk about what component of spending right now is for stuff like roads and in-field stuff that might impact the way we look at capital versus capital being purely for well drilling?

Most of the increase is due to actual drilling wells. We had about 90 wells this year that we didn't anticipate. And then the lease hold budget is moving up with the horizontal Mississippian. There are expenses with infrastructure, and I'll let Matt hit on that in the Permian, but most of the areas we drill in are in pretty easily accessible oil fields including Oklahoma and in the Permian. So we address our salt water disposal in the Mississippian Play of Oklahoma and Kansas with drilling wells that add $200,000 per well cost there. But inside of our well cost, it really does take care of building roads and taking care of the infrastructure. Maybe Matt, you might hit on the Permian and look at what we continue to upgrade there.

Duane, in 2011, we're looking at capital dollars that are directly associated with drilling, it's going to be right about $890 million. And the way with our previous wells, the roads and locations are built into the fee. I don't have that number on top of my head, I'm guessing it's probably 5% of your cost. Your percent of roads and location of Permian may be a little bit higher than your percent of roads and location in the Oklahoma Miss just because the well costs are lower, the total well cost is lower and Permian is higher in the Miss, but it's probably on that 5% range.

And then in terms of the big step up in activity, you've had the capacity to execute at a higher level in the past when you're drilling lots of gas wells. As a go forward here and step up the activity level even more, what kind of gaps are there that concern you the most in terms of staffing or equipment, say?

Just kind of give you a little bit of history. In 2008, we digged up 46 rigs in the summer of '08 and going into 2011, we're going to keep our total rig count at 27. So from an execution standpoint, it's nothing that we haven't done before. Where we drill is going to be a little nit different, but what we're looking at running is 16 rigs in the Permian basin. Our Fort Stockton service base is not far from there. It's south between Permian and the Pinon field. So instead of rigs and equipment moving south, it's going to be north a little bit, so not a big difference there. In Oklahoma, we currently have five rigs running and we're going to be ramping it up to eight rigs in a year and probably another two rigs, I'm guessing at February of 2011. So not a huge ramp up there. So I don't see any problems going forward with our program. We're already at 23 rigs today, and we're going to 27. So it's not a big move.

As you mentioned, Duane, logistically it's challenging in the Permian basin especially where we drill in the Central Basin Platform because of how quick the wells are drilled. So we do have to staff up but move staff over to take care of that with engineers, land and geology. We're running 16 rigs. We can complete two wells a day in the Permian Basin. So we're going to drill 650 or 700 wells next year in the Permian. So just a lot of activity and that's probably why you don't see a lot of other companies trying to do this because you do drill a lot of wells in a pretty small area in the Permian.

And then on the new capital raise, a more cynical person might think, gee, the auction for your Wolfberry and Bone Spring stuff might have been done sooner than the January-type PSAs that you're talking about. And again, a suspicious view would be stepping up the program and raising capital ahead of those auction results might be because you're worried about the auction results. How would you respond to that?

Well, we don't have any results. The data rooms are still open. So I don't know, we could have preempted if we would have cared to, but I think we'll have a better outcome by going through the whole process. We're selling oil assets in an oil market instead of trying to sell gas assets in a depressed market. So I tend to be pretty optimistic -- what the offering does for us is give us tremendous flexibility. If you really -- I believe that the Mississippian play is a unique play today, one of a handful of plays I've ever been in that I think can change a company. And the reason I believe that is because you can control your cost. With the high-pressure frac-ing really being the main culprit, we're seeing in other areas that costs are tripling or more in what it takes to complete a well. And I just like being able to control our own services and then have the vertical well control to really know how hard to field can be is, is that has over 30 years of production history and it's the carbonate. So those things make me very, very bullish on the Mississippian so what the preferred does is it gives us more time to look and drill Mississippian wells and determine how we want to sell our excess acreage. We made it very public that we have more acreage than our company is going to be able to take care of. And I think that in the next year, you'll be able to see us not only monetize the assets that we're talking about in the Bone Spring and the Wolfberry, but now we'll have time to get the maximum amount that we think we can out of the Mississippian. And only time will tell us if how successful we are with that, but I believe that it might -- I won't say it's the best play in the United States, but it's got a rank very close if it has a scale that I think it does.

And then finally, to follow up on that, in the Mississippian, when you guys daydream about how good it could be, you've also daydream about what might not go well. Do you think it's going to be -- two years from now, let's say, is there going to be some "aha!" moments about the rock variability across the play or is it going to be that your completion style changes? Which would you predict is going to be the bigger unknown?

Our completion style. We already have too much control over the rock because there's thousands of vertical wells that would even -- you can even drill vertical wells in the play today and make economic wells. So all's we're doing is connecting vertical wells by drilling horizontally in a known reservoir that's been producing for decades.

Your next question comes from the line of Devin L. Geoghegan with Zimmer Lucas Partners.

I just wanted to understand, it looks like in the press release you guys implied that the spacing on the Mississippi could be done on 160s. My understanding is the play is really permeable. And when I think about the Bakken and the Eagle Ford, they talked about being done on four per 12 80s and 160s. I'm confused why, I'm just confused on the spacing you guys seem to be implying?

We anticipate drilling two wells per section, so 320 acres, but if you look at the vertical well control, you'll see those wells are drilled on 40 acre spacing. And I think that we've at least heard from some of our peers that they think that the wells will be drilled down to 160s. We don't really know yet, we feel very comfortable. We've seen wells drilled within the 320-acre space and there are two wells per section, and those wells don't appear to be communicating. So we're very comfortable with 320s. So we're hopeful that we can drill down to 160s. We're not seeing a huge fracture component to this. So it appears to be more matrix porosity and that would tend to make you want to feel like you could drill those a little closer together. So it is early and we're not saying we can drill on 160s but I don't think that's out the question.

Could you give, on the 62.5 Bcf of gas in 2011, could you all give a breakdown by region just to help us reconcile? I just wanted to understand where the big decline in the gas is coming from.

We're going to decline -- we're not going to be drilling gas wells, so we'll have a very steep decline next year probably around 18% to 19%.

The breakdown of the 62.5 Bcf of gas is as follows: On the Permian Basin, we're looking at 11 Bs; the WTO, 30 Bs; East Texas, about 9.5 Bs; Gulf of Mexico, about 1.5 Bs; Gulf Coast, 3.8 Bs; and the Mid-Continent about 6.8 Bs.

Just on the Mid-Continent given all the associated gas with the Mississippian oil because it's like 47% gas, I would have thought that the amount of natural gas coming into the company would have been substantially higher. Where is all the gas going? I actually had gas production much higher than you all have it, mostly because of the associated gas with the Mississippian wells? Where's it going?

Over half of the production currently is still gas. We're producing about 380 million cubic feet of gas equivalent per day. And I think 54%, 55% of that is still gas and we're only running one pure gas rig and that's going to be in Pinon. So we still have continued -- have gas decline in Gulf Coast, Gulf of Mexico, East Texas as well as the Pinon Field. And yes, we're going to make some of that up in the Mid-Continent but obviously not all of it. And what happens is we're probably offsetting maybe 20%, 25% decline down to maybe 18% decline.

And keep in mind, we're just now getting started in the Mississippian, so that production will ramp up over time. We have only moved just recently to five rigs. We'll be moving to eight by the end of the year. It will start to ramp next year, but the overall production in the Miss probably the 100 wells we drilled, it will be weighted towards the end of the year, not the first of the year, so I think that production will is be coming on more in 2012.

Your next question comes from the line of Jeff Robertson with Barclays Capital.

Tom or Matt, just a follow-up to the previous question. Can you say what the Mid-Continent contribution would have been or is expected to be in 2010?

In '10, or 11?

In '10 because -- so 6.8 is your 2011 number, do you have a number or a rough number what you think you'll get out of that area in 2010?

Let me get back with you on that. I don't have it broken out -- just, well, just this minute.

In the meantime, Tom, can you talk a little bit about your thought process in terms of allocating capital and setting spending levels where they are relative to cash flow and in the context of selling oil assets in the Permian to fund other oil assets in the Mid-Continent. Maybe in that, what your view over the rate of return and the upside opportunity is on your assets that you're marketing for sale versus the assets and the conventional Permian and the Mississippian where you are spending your capital?

As you notice, one easy thought is that we're selling at Bone Spring and keeping the Mississippian or keeping most of the Mississippian. We're not trying to be in every play, and we've done that in the past. We've sold out the Pinon and sold out the Haynesville and sold out of the Cana. So whenever we look at the different plays, we've made our choice and our choice for our company is going to be the vertical Permian and the horizontal Miss. Now with that, that doesn't mean that those plays are bad. It just means that in the Bone Springs, it looks like a fabulous reservoir to drill for, I just think it has a little bit more risk. It's currently in the play and the wells look fantastic, but for us focusing on the shallower and lower cost wells are where we want to focus. And so whenever we're valuating, we do look for our producing wells in areas that we think have lower rates return than we're spending capital. So that's the oil on oil. When I look at why we would press the balance sheet and move forward with an aggressive CapEx is really just because we think it's a rare time here that we can have these types of rates return and that by keeping our CapEx up for a couple of years, our goal is to get to where our cash flow neutral and still have a $1 billion to $1.1 billion of spending. So as we look out, that's what we're trying to achieve.

Lastly, in just in terms of the numbers on, do the operating cost or actually the production cost, do they include any amount that might be related to under delivery either to Oxy and the WTO or commitment fees to the legacy plants where you're pulling the gas out and split it through the Century Plant?

No, those were offset by credits and efficiencies that we actually have a gain.

Your next question comes from the line of Joe Allman with JPMorgan. Joseph Allman - JP Morgan Chase & Co: Tom, could you just clarify, how much do you expect to raise in 2011 from the asset sales, including the Mississippian?

Well, we've set out $400 million to $800 million. Now that obviously would more than fill if our need for capital in 2011. So as you anticipate, we're trying to look forward to 2012. Joseph Allman - JP Morgan Chase & Co: And then in terms of the cash flow versus CapEx question that Jeff asked, at what point based on your model do you expect to be cash flow neutral?

A lot of things change and then of course in the next couple of years. My goal is out of 2013 that all this comes together. Joseph Allman - JP Morgan Chase & Co: And then since you're really ramping down or you've ramped down the WTO drilling, are there any lease expiration issues there?

We have lease expirations either way. But think about the WTO is first of all, we've selected structures that we like. We would drill three structures outside of the Pinon Field and found commercial production on one. But either way even if we would continue to keep a very active gas program, we would be letting acreage go in the WTO outside of the structures that we want to keep. Joseph Allman - JP Morgan Chase & Co: So, Tom, for example in 2010, 2011 and 2012, can you talk about how much acreages, how much you're going to let go?

Well, today we have proprietary seismic and I think it will be very difficult for somebody else to compete with this in the area. So we don't anticipate spending a lot of money in the WTO renewing leases. Now with that said, we had 550,000 acres of land in the West Texas Overthrust. I don't have the numbers off at the top of my head, but I think we'll be expiring sometime between '11 and '14 or so if we didn't do any drilling and we have some five-year leases. Joseph Allman - JP Morgan Chase & Co: So what's the number again? What's your total acreage there and how much is expiring 2011, 2014?

I don't have the exact number. I think we have 550,000 acres in WTO and most of that will expire by 2014, unless we decide to move forward with drilling. Now we do anticipate that the gas prices will be back up in the next couple of years to where we'll put rigs back in the Pinon Field or you'll have the option if you continue to grow as an oil company and oil continues to be at $14 in Mcf and gas is at $6, $7 or $8, you might want to sell some gas assets. And the way I look at that is, that's your period of time that you could really pay down some debt. And I don't look at paying down debt as something that we're really looking at but we do have in our mind the oil growth is going to continue and we're going to have, for the size of our company of ours, we'll have excess assets. That's kind of how I think about it.

Joe, this is Matt. I just want to point out that nothing in the Permian Pinon proper will expire with the one rig running. We were able to meet all our obligations there to keep that going. You have to understand, we have 1,300 miles of seismic, so we had this area mapped out pretty good and we will get to pick and choose what we want to keep and what we want to let go. And because we still have a couple of years to work that process, we don't have an exact answer for you of how that's going to pan out.

And the whole idea of the company when gas prices are more attractive is to not only fill the century plant but to fill the legacy plants and that's still all in the Pinon Field. It doesn't require us to drill anything outside of Pinon which is all held by production. Joseph Allman - JP Morgan Chase & Co: The same issue, lease expiration as it relates to the Central Basin Platform and the Mississippian play. What are the lease terms on some of the new releases that you have there?

Central Basin Platform is almost all held by production with the acquisitions of Arena and Forest. And then in the Mississippian, most of our leases are three years with a two-year option. So we feel like with a 10-rig program, even if we didn't increase from a 10-rig program, that we'll be able to hold the 250,000 acres that we have looked at originally as being the right size for us. That could change, we might decide to tell more, we have more flexibility now. We were looking at that as the right size initially. Joseph Allman - JP Morgan Chase & Co: I guess as part of outspend of cash flow is also you get this acreage position and you want to hold it so you need to run 10 rigs to hold that at least 250,000.

No, not really. The reason that you have to spent cash flow is you're making 100% rates return.

Your next question comes from the line of David Kistler with Simmons and Company. David Kistler - Simmons & Company: Just looking at Slide 20 from your presentation on the horizontal Mississippian well performance, I'm just trying to take type to the last presentation and the last 30 days production numbers didn't really move. Can you kind of walk me through what's happening there and is that because things are on pump or just help me digest how I'm looking at this?

Yeah, David, you know, all these wells are on gas lift right now and that's a very efficient way to move high volume of fluids, and what it's turning out is that our production may be flatter than what we're declining. We run a model to get to the 386,000 barrels equivalent-type curve. We run a model that has this thing with an initial decline of about 60% ,and as we look at the daily production and then start updating our curve every day, it's looking potentially like it could be more like a 38% decline. So that's the main reason your last 30 days is not moving very much. Potentially this thing could be flatter and that's kind of the range between where we're at and getting up to 500,000 barrels equivalent. David Kistler - Simmons & Company: On the same kind of theme, but looking towards the front end of the curve. As we look at some of these, it looks like they go through pretty healthy dewatering phase as they flow back. Can you give me any color on, I guess, wells 19 and 20 in terms of coming out at slightly lower 30-day rates. Is that representative of water flowing back or do you kind of look at those as steady state?

It's just basically statistical over a large area. So we'll have some wells that come on at a very high rates and some that come on at less and probably has more to do with prosy [ph] of any given area than anything else. The water cut basically stays fairly static. So it's not necessarily a dewatering except for the wells that we feel like we overstimulated. David Kistler - Simmons & Company: On your DD&A guidance, going forward, it goes up substantially and I guess that's because the reserve base becomes more oily, less gassy. But as I look at that guidance going forward, does it also include or anticipate reserve revisions for next year?

It does not, Dave. We actually think that DD&A might trend down as we get our year-end reserves done. The bookings that would come in with Arena and the drilling activity, I think next year. Once we get the year-end reserves done that DD&A rate will probably be lower. David Kistler - Simmons & Company: G&A for 2010, you had an item in the notes about other legal settlements contributing to that going higher. Can you just walk us through what those are?

Yes, it's basically one settlement in the West Texas Overthrust over a disagreement on continuous drilling in a lease.

[Operator Instructions] Your next question comes from the line of Scott Hanold with RBC.

Just to go back to production, I just want to make sure I'm understanding this and one of the things you said, WTO gas is expected to be about 30 Bcf next year, and I think that equates to something like $82 million a day. What is that average in the third quarter because I think we're on the 120 in the June quarter and if I just sort of do some simple math and -- because it's a pretty linear decline curve around, what, 15%, I have a hard time getting that low in 2011.

The WTO averaged about 107 million, 108 million a day in the third quarter.

Okay, so it's down a little bit further than I had anticipated but it's still, I guess as you look into next year, if you're running a rig, one rig there -- why did it drop so much? Even if I, like I said, take it down 15% of the decline curve, I just don't get to there.

We have modeled some extra risk in the Pinon gas based in the first quarter of 2011 and I think that's where the bogey is. We're in the process of converting all our legacy gas plants over the century plant and that's about 260 million a day of high CO2 gas at a 35% methane. There's also a pretty big chunk of gas that we're messing around with right now. Right now, we have 85 million and 90 million day running at Century and we're experiencing vibrations with compressors. And I'm hoping to get those items resolved and then move the rest of the gas over. But we're going into winter, we're starting up a new plant. So we have a bogey of about 10 million a day methane risk in the first quarter of '11, which makes it probably, maybe hopefully, a conservative estimate. But what it does is it kind of contributes to 9/10 Bcf of gas in '11. So I think instead of producing company-wide, instead of producing on average of 180 million a day in the first quarter, we may be in this 185 million or 190 million a day. And I think that will probably make more sense to you if we took that risk out on a straight decline. But we do have some -- we could experience some problems just converting everything over.

Is it reasonable to use sort of -- still that sort of 15% more of your linear decline rate in the WTO with one rig. I mean, that should be a pretty conservative expectation going forward, is that a fair statement?

Yes. We have 18% decline model in the Pinon Field right now. So that's probably close to what you're thinking. You said 15%?

Yes, 15%.

I think that's in that range. And I think it's going to be this 15% to 18% range with one rig running.

Looking at the Permian. You all provided that third quarter earnings supplement which provides a lot of nice detail -- the only thing I'm just trying to cross reference,e if I look at your investor update that you put on sort of mid-October -- in the Permian oil slide where you identified 7,200 Permian oil drilling locations and in your update today you indicated there's 8,073. Where did that extra thousand rig locations come in? I think this one includes 700 that are going to be divested. So effectively up almost 1,500 or 2,000 locations?

It's really up in the Permian Moscow field. Initially, we were hesitant on booking 5-acre spacing. But we look at our drilling in our year-to-date, about third or maybe close to half of the wells have being drilling 5 acres and there has been no degradation at all in the type curve at the five acres versus 40 acres and so we've got more 5-acre spacing wells and that's caused the big difference.

Looking at Mississippian oil play, when you're out there identifying well locations, is there something specific you all are doing about how you're going to go about this drilling or is it using what you know on some of the vertical well control that allows...

It's mainly statistical.

Your next question comes from the line of Philip Dodge with Tuohy Brothers Investment.

Could you remind me how much of the 22 million BOE guidance for 2011 is from the horizontal Mississippi?

We have not split that out, Philip.

Can you give me a tentative estimate on the increment that you would see by the end of 2012, say, if you could go that far out.

No, we're basically -- the play is so new that we're a little bit tentative here to start making projections out that far. And we will have 100 wells drilled in '11, 100 more wells.

On that first question, the 62.5 Bcf in '11 of gas, we had about 6.9 Bcf of that from the Mid-Continent and I would probably estimate that just from -- I guess, where you're talking about is from the drilling horizontal wedge of the horizontal Miss, that'd probably be about a Bcf of gas in there.

Would you expect the production mix, whatever the production is, to move out of this ratio of sort of 53% oil, 47% gas?

Continue to be at that ratio?

Yes, would that be consistent, Tom...

We're comfortable with that. We think that in some areas in the play will be more oil but we haven't yet proven that. So we're comfortable with the 53% today. We might be changing that during the next year.

Your next question comes from the line of Richard Tullis with Capital One Southcoast.

Just looking at 2011 guidance at this point, I guess you're estimating about 59,000 barrels a day after what you plan to sell. And I guess that's about what you averaged in the third quarter as well. I'm just trying to reconcile the growth expectations for next year given the amount of capital that you're dedicating. I guess, why not a more robust growth rate?

Well, we're growing in oil and letting gas decline. I think we're maybe unique in this that we look at the two commodities as totally separate. And while everybody combines them in MMboe, obviously the revenue from one is much greater than the other. So whenever you combine everything together and project growth, you can say you're not growing but obviously, your revenue is much better by growing oil and letting gas decline, it's really that simple.

How much of next year's 21.6 million barrels is related to the Arena assets?

I don't think we've even isolated out Arena by itself in our modeling as it's all part of the overall Permian Basin. We continue to have about 70% of our budget looking at the Permian. So we believe that the Arena asset will do like the Forest asset has done and really start to grow as we put rigs to it.

I know you put your kind of blended Permian tight curve out recently. When you look at your total portfolio there, what's your typical first year production decline?

It's about 60%, just over 60%.

And what about the second year?

Blends in together, we end up with at -- at the end of the second year, 6%.

Second year is probably 30% to 40%.

And then you end up with 6% finals OER.

The Mississippian oil play, I know you have about 20 wells online so far. What are you seeing on LOE in differentials?

Really, all the LOE has to do with compression principal for gas there [ph] . Of course, you have a pumper that's going on out there. But the -- all our water disposal -- we drill water disposal wells and we drill them to the [indiscernible] pretty much takes water back in. So there's very little LOE related with moving water around. I think what we're running right now is about on average about $7,500 a month LOE per well.

What about price differential?

Well price differential is, for the bulk of this play we believe, there's going to be a couple of dollars off of NYMEX and the greatest gravity is about 35 API gravity. There is a small area to the West that you could dip below 30 gravity and that differential would be probably $6 to $7 off of NYMEX. But that's probably less than 10%, 15% of our drilling.

Do you have any well cost increases factored into the 2011 CapEx number?

As far as drilling completion?

Yes.

We're using $2.5 million to drill and complete and then another $200,000 per well allocation on the salt water disposal facility.

And what about across the Permian and elsewhere, do you have any cost increases?

No, we're not factoring any cost increases in the Permian. We can drill probably 800 wells in the Permian next year. So half of that or maybe more than half of that is going to be in Arena, where we stuck with the same pressure pumping company that Arena used and we're in good shape there and we're also moving another frac crew in the Permian. Now we have four different service providers pumping for us and the costs are pretty stable now. We have various agreements locked in to the end of this year to the end of next year. So I don't see any increases there, plus we use a lot of our own rigs and services as well.

We're drilling different types of wells than the rest of the industry. We're not competing with the same types of services, so we're not seeing any real increases in service costs and we're not seeing any backlog of getting wells completed. We'll complete two wells a day in the Permian Basin. We have no backlog in Oklahoma, either.

Your next question comes from the line of Jeff Robertson with Barclays Capital.

On the capital, I think your 11 million BOE of oil production excludes the volumes that you plan to sell. Can you talk about what a potential sale of some of your Mississippian acreage would do to the capital program next year? I guess my question is, you talked about $400 million to $800 million of proceeds, does the capital that you also talk about reflect anything from a potential sale in terms of bringing in a partner or would the sale have an impact on your capital number?

No, the sale would not have an impact on the capital and we've taken the most conservative approach assuming that we sell everything that we put in the slide. So if we were to raise $800 million, that would just go towards next year in 2012. What our goal is, is to bridge the gap across to '13. We'll see if we can do that or not.

And can you say anything about what kind of terms or what you'd be looking for in the form of Mississippian partner?

No, we'll just look for the best deal we can get, obviously. But it could range from any number of different types of transactions. So what I really like is that we're going to continue and you guys can just look as we bring on wells if they continue to get, be as good as they currently are, which we think they will. We believe we'll be able to have a very valuable asset.

Your next question comes from the line of Mike Breard with Hodges Capital.

Can you give us an update on your exploration program in the West Texas Overthrust and what the current drilling is and what you plan to do in 2011?

With the drilling plans in the West Texas Overthrust, we only have one gas rig...

I mean, the exploration plans, do you have prospects you've identified?

We still have the opportunity to drill some wells if we choose to. We haven't made a decision to try to drill other structures yet. The gas in those structures if there's commercial gas there isn't going anywhere. And we really are just trying to minimize the amount of money we're spending on gas. And so it's really just a wait-and-see attitude here of -- that's not to say we won't go drill an exploration well or two next year, but we don't have anything planned.

Your next question comes from the line of Gary Stromberg with Barclays Capital.

Dirk, looks like you reaffirmed your borrowing base at $850 million, relaxes covenants. There's also something that says it permits the sale of non-core assets without an automatic reduction in the borrowing base. What are those non-core assets, does that include the Bone Spring and Wolfberry?

Yes. It's the assets that Tom and I have spoken about. And the way we went about it was we took those out of the borrowing base before it was approved. So with those asset sales, nothing would happen with the borrowing base. Just a little forward thinking on our part and you won't see any change in the liquidity.

I guess as a follow up as I look at my model without asset sales, liquidity gets a little bit tight in 2011. Would you look to the high yield market to term out some of your revolver to help free up some liquidity?

No, we really have very high confidence that we can get some assets. So they're oil assets. You have to wait a month to see, but we would have already sold it if we have chosen to. So I'm just not thinking about having no asset sales.

Your next question comes from the line of Ken Carroll with Johnson Rice. Kenneth Carroll - Johnson Rice & Company, L.L.C.: I heard Apache yesterday talking about some other Permian successes, in particular some horizontal ...

We can't hear you. Kenneth Carroll - Johnson Rice & Company, L.L.C.: I heard Apache yesterday talking about some horizontal successes they had drilling in the Permian that they seem pretty exited about. Have you all looked at horizontal drilling or do you plan to test that at all?

We have not yet. We do know about the wells that are being drilled. So far, we're very comfortable with drilling either -- let's assume we drill well in Fullerton or Tex-Mex and on we drill down through some deeper horizons, you have basically four to eight different horizons that you can test a with very shallow vertical well. And we've been asked questions about some of the high rate wells that we brought on and those are all because we've taken them down a little bit deeper. I think that we're very hopeful that there's an application that can be made horizontally. You just always have to weigh the cost of those wells versus how much oil and gas we're going to get out. We just don't know yet. Kenneth Carroll - Johnson Rice & Company, L.L.C.: Is your acreage near the Apache acreage?

We're not too far, they're a little bit north of us on the Central Basin Platform drilling some horizontal in the San Andres. We're watching the program. We think if it make sense, we're certainly not afraid to try it. It's just still too early.

Drilling vertical San Andres is pretty efficient process, and we'll drill those in four days.

Your next question today comes from the line of Brian Singer with Goldman Sachs.

On the land and sizing budget for next year of $100 million, how much of that is land acquisition and can you give a little bit color on where you're looking to acquire? And whether there is a potential to look to be more aggressive to the extent that you're successful in a drilling program?

I think first of all, the land and sizing budget for next year for '11 is $50 million not $100 million. And the book of this land, I think -- we hope to get to 500,000 acres by the end of this year in the Miss play which I think we'll do or be real close. But we did budget about $10 million next year for that. And the $40 million is based on historical spending. We'll get lead sales that come up in the Permian that make sense to some other areas that we'll bid on.

I think if I'm reading about it, it does say it was raised to $100 million from $50 million but we could follow-up after.

$100 million this year.

For this year, it's $100 million, for next year it's $50 million.

Your next question comes from the line of Mitch Wurschmidt with KeyBanc.

What's the timing looking like on a horizontal Miss JV?

We don't have it planned. Actually, it's -- and we haven't said we'll have a JV. So we just said that we'll market some lease hold and what we have now is optionality. And as the play continues to get better, what we didn't want to have happened is to be forced to do something too early. So there's no time limit that we have now. We have brand new leases, we have a lot of acreage. And we have wells that are coming on and meeting or exceeding our expectations.

On the sort of gas production out of the horizontal Miss. Are you just being a little conservative I guess? Or you mentioned the wells being hooked later in the year. I just feel like when I'm modeling given getting more gas production out of that area -- are the wells, is the gas production being hooked up right away on that part of it?

Yes, once we drill a well, we can usually complete within three weeks.

What's the decline, I guess, for the gas side for those wells in the first year?

I think we're anticipating a basic decline.

What happens on the gas hold that makes it hard to model is, while, our water and our oil, we assume there's a kind of constant water to oil ratio that decline proportionately with each other, the gas -- what happens over time is the GOR increase as we drill a purger down a reservoir. So you start out with a smaller gas-oil ratio and it increases to a certain point and it becomes pretty flat and it rolls over with the oil and gas. So early on, you don't get peat gas as much you do three months down the road on these wells.

Just on the Pinon, what does LOE sort of look like for that field just compression and different things going just for our modeling purposes?

For the Pinon Field in calendar '11, Mitch, I think we've got our LOE going from about $1.85 or so average for '10 up to -- it may actually go up to that $2.15 area and that just really relates to volumes falling and a pretty sizable component of the cost after being a fixed cost.

Work includes 45% in production taxes.

[Operator Instructions] Your next question comes from the line of Rhett Bruno with Bank of America.

In the Mississippi and Oklahoma play, can you give any color on how much of the acreage you have now is outside the, say, the Woods, Alfalfa county areas and have you drilled any wells outside of those counties?

Yes, we're not going to break down exactly how much we have in each area. But the majority of our acreage is in Woods, Alfafa and Grant, and we drilled wells outside of Woods and Alfafa.

Would you say it's more of the north than the south?

No, I wouldn't say.

I would now like to turn the call back over to Tom Ward for closing remarks.

Thank you, and thanks, everybody for joining us. As we have embarked over this last year to make a change in the company, I think looking back on it, we have made dramatic change and it's not always the easiest thing to do. So whenever we have questions -- last year, when we started moving to oil, looking back on it now, we believe it was for sure the right thing to do. And as we move forward, we've raised capital now to be able to fund going forward. So this is a critical time for us today, and we feel like looking forward that all the work that we've done over the last year will pay huge dividends for us. So with that, I want to say thank you, and just feel free to give us a call if you have any questions. Thanks.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.