Good day, ladies and gentlemen, and welcome to the Third Quarter 2011 SandRidge Energy, Inc. Earnings Call. My name is Modesta, and I will be your operator for today. [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. James Bennett, Chief Financial Officer. Please proceed, sir.

Thank you, Modesta. Welcome, everyone, and thank you for joining us on our third quarter 2011 earnings call. This is James Bennett, Chief Financial Officer. And with us today, we have Tom Ward, Chairman and Chief Executive Officer; Matt Grubb, President and Chief Operating Officer; and Kevin White, Senior Vice President of Business Development. Please note that today's call will contain forward-looking statements and assumptions, which are subject to risks and uncertainties, and actual results may differ materially from those projected in these forward-looking statements. Additionally, we will make reference to adjusted net income, adjusted EBITDA and other non-GAAP financial measures. A reconciliation of any non-GAAP measures we discuss can be found in our earnings release and on our website. Also note that this call is intended to address SandRidge Energy, not our 2 royalty trusts, SandRidge Mississippian Trust I or SandRidge Permian Trust. The trusts will have separate earnings calls at 8 a.m. and 9 a.m., Central Time, one week from today on Friday, November 11. So please hold any trust-related questions until the calls next week. Now let me turn the call over to Tom Ward.

Thank you, James, and welcome to our third quarter operation and financial update. We continue to make great progress in executing on our 3-year plan of tripling EBITDA, doubling oil production and lowering our debt-to-EBITDA ratio. The plan revolves around our growth engine in the Mississippian formation of Northern Oklahoma and Western Kansas. This area has received a tremendous amount of attention in the last year, not only from SandRidge but from other large industry players. A snapshot of where we were last year to where we are now reveals that we have nearly doubled our acreage position in the original Mississippian play from 400,000 acres to 800,000 acres, while generating more than $800 million of capital from our initial investment of less than $200 million in acreage cost. Our organic production growth has increased by sevenfold from about 150 Horizontal Miss wells we drilled since January 2009. This represents nearly half of all the horizontal wells to date in the play. On the first 37 wells drilled at year end 2010, we averaged a 30-day peak IP of 244 barrels of oil equivalent, while the last 119 wells drilled in 2011 have averaged 308 barrels of oil equivalent a day. We currently have 18 rigs drilling horizontal producers, 2 rigs drilling saltwater disposable wells, while planning to exit this year with 20 horizontal rigs running. We have now adjusted our goal for 2012 to average 26 rigs, and this is averaging 2 more rigs than we would have indicated in the past for our 2012 Mississippi drilling plan. However, this will not impact our 2012 capital spending plan, as we will offset the increase in the Mississippian activity by reducing our Permian drilling by 4 rigs to 12 rigs. We're currently seeing better capital efficiency in the Miss program,…

Thank you, Tom, and good morning to everybody. We produced 6.2 million barrels of oil equivalent in the third quarter as compared to 5.6 million barrels of oil equivalent in the second quarter. This is a 10% sequential quarter-over-quarter production growth for the company. Oil production grew by 15% to 3.2 million barrels of oil in the third quarter as compared to 2.8 million barrels of oil in the second quarter. And natural gas production grew 4% to 17.9 Bcf from 17.2 Bcf in the same period. Even though we just completed a quarter of record production numbers, we are revising our 2011 full-year production guidance down approximately 2% to 23.4 million barrels of oil equivalent from our previous production guidance of 23.9 million barrels of oil equivalent. The new 2011 guidance consists of 11.8 million barrels of oil and 69.4 Bcf of natural gas. The slight downward revision in the 2011 guidance is primarily due to excessive pressure buildup in our company-operated, low-pressure gathering systems in the Central Basin Platform, as a result of tremendous production growth we have experienced since the beginning of this year. However, before going into details about the gathering systems in the Permian Basin, I want to point out that since we have already produced 17.3 million barrels of oil equivalent through the first 3 quarters of this year, our new full year guidance of 23.4 million barrels of oil equivalent would suggest that fourth quarter production will be slightly less than our third quarter production. The reason for the apparent fourth quarter production decline is that we are scheduled to close the sale of our East Texas properties the middle of this month. And when we do, about 4,000 barrels of oil equivalent will come out of our production base. Otherwise, excluding the…

Thank you, Matt. Turning now to our financial results. For the third quarter, adjusted net income was $2.8 million or $0.01 per diluted share. Adjusted EBITDA was $169 million, and operating cash flow was $144 million or $0.29 per diluted share. Adjusted EBITDA and operating cash flow are both up 8% over the second quarter, driven by a 15% growth in oil production, slightly higher realized prices and an improvement in per-unit expense measures. This brings our year-to-date adjusted EBITDA to $479 million and year-to-date operating cash flow to $378 million. On per-unit measures for the quarter. LOE of $14.01 per BOE and production taxes of $1.68 per BOE were both below guidance ranges and all other expense items were within guidance. Capital expenditures, excluding acquisitions, were $468 million for the quarter and $1.3 billion for the year-to-date period. For the quarter, drilling and production CapEx was up $62 million, due to increase in the rig count and drilling activity in the Mississippian, as Matt discussed, and leasehold acquisition was down slightly to $75 million compared to last quarter. Recall that we closed our Mississippian joint venture on September 28. Therefore, the third quarter drilling and production CapEx does not include the impact of the 13.2% drilling carry on our Mississippian wells. We remain very active with our capital-raising efforts, having raised approximately $1.85 billion of non-debt capital so far this year. Three of these transactions occurred in the third quarter, which resulted in over $1 billion in closed or announced proceeds. First, in August, we closed the IPO of SandRidge Permian Trust, our second royalty trust, where we raised $581 million through the sale of a 66% interest in the trust. Second, in September, we closed a $500 million Mississippian joint venture, consisting of $250 million of cash at…

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

Two questions, quick. I understand, Tom, between you and Matt, you talked about the gathering facility and the issues that you're going to have coming there. Just try to give an idea how much total, I guess, capacity is needed to be added or piped, et cetera, versus kind of what's already in place.

Sure, Matt can take that one.

Neal, a little bit more detail on what that -- what those projects are all about. These wells in and around the Fuhrman-Mascho area are very shallow. They're about 4,500 feet deep. So they're very sensitive to pressure. And in the past, what we've done, historically, as we've either bull plugged off the casing or tie the casing into the tubing and as pressure -- and as production increases, you start getting a line pack behind your tank batteries back to the wellheads. And so what we're doing now, and we've done this on one tank batteries and saw really good results, about 15% increase in production. But we're laying a separate line, and this is a polypipe, a 2-inch polypipe, that we can roll out pretty quickly and tie a separate line to the casing back to the battery. So what it does is it reduces the pressure at the wellhead down to the purse. And you get 10, 20, 30, 40 pounds reduction in pressure. You'll get more fluid entry into the wells. And what's been the impacting us the most is in the older wells that was drilled several years ago. And as we put on new wells, we packed a line the new wells can certainly produce. But your not getting a one-for-one incremental increase each time you add a barrel on because an old well is getting knocked offline. So we really think we can probably finish, we have 26 projects we can roll out. We probably can finish here, possibly late Q1. But I think, to be safe, we'll say Q2.

And just lastly, Tom, definitely, it appears that in the regional Horizontal Miss, it looks to me like economics continue to improve. I was just wondering, given the improving results, any thought about -- with the type, would you increase the type curves here? And then secondly, thoughts on how you see if you're able to comment yet what your thoughts would be on the new Horizontal Miss, how the economics could potentially stack up versus the first?

Sure. we'll be, in fact, we're in the process of doing reserves. So we'll look and see what our third-party engineers are seeing. We internally, we think that we could possibly be seeing a raise because our IP peak rates are higher than they were last year. And what really tells about a field is what happens over time is the EUR. Are the EURs going up or down over time. And now, we have 3 years worth of projections of which we've gone -- or 3 different end of years that we'll be looking to increase each year. So the Mississippian play continues to be very good. Now what I don't want to lead you to conclude is that with continually being better 30-day IPs, they'll continue to rise up to some point that is unreasonable. We like the 300 to 310 barrel a day IP on the 30-day, and that's a fairly efficient well for us. So we don't anticipate that's going to go to 400 or 500 barrels a day as some have concluded. But we do -- we just make a lot of money drilling these types of wells. And we see it all across the play. So we're not trying to, today, pick out a core area. And then, so that leads you to the second question you had is, there was nothing too unique about the idea of where we bought the original Mississippian. It just had -- the play had a tremendous amount of vertical production. We knew there was oil in place. We knew it was shallow. We knew we could dispose of water, and we knew that we're going to be perforating, frac-ing the same rock that's been produced vertically. So the new area, and obviously, we'll talk more about this in the next few months, is the same. And so, you have maybe a little more shallow production, maybe a little bit more oil. And so, we like it and there's just a lot of history. So that's the way that we see this and the reason we haven't participated in other plays. It doesn't mean that we don't like other plays. It's just we think there's higher risk in areas that don't have a tremendous amount of production history.

Your next question comes from the line of William Butler with Stephens.

In terms of the Permian gathering curtailments, when did those begin exactly? During the third quarter or as of now?

Well, I'll just let Matt take that one.

Yes. I think it's hard to pinpoint exactly when they occur. They impact us most in the third quarter. However, I suspect that we start seeing degradation in production, as we're adding new barrels on probably early summer. And then what happens is, initially, it's a wedge affect. As you add on new barrel of oil, you might see 9, 10. And that increase or got worse. And now, it may be 1/10 or 2/10, but I think that's what's causing the production to remain flat. So we've gone out and to make sure that our wells are doing all right, we've put individual wells on test, as we bring new completions. And there has not been any degradation in IPs. So it's difficult to pinpoint that down. But certainly, as you get to a certain point in the pressure and the reservoir just won't give up any fluid entry into your casing, there's nothing to pump out. And so, I would say early summer, if I had to put a time on it.

So I guess what I was trying to do is translate that curtailment number you gave to sort of on a per-day basis, and what would you say is the best way to think about that is?

I think on average, if you look at the last the 180, 200 days, and you'll probably got 2,500, 2,600 barrels a day or 2,800 barrels a day or something like that.

Okay. And then, are you all seeing saltwater disposal impacting LOE in any way, currently?

No. I think from that standpoint, it's been pretty flat, actually, down a little bit. I think that's what, we had about 10,000 barrels of saltwater. We had to truck around our Permian operations there, and that's down, so probably half of that now. And we still plan on getting that down to basically nothing by the end of the year.

So in your 2012 cost guidance, that's -- there's not really much in the way on the LOE side in terms of the saltwater disposal.

That's correct.

And then, I guess one last question is, if you guys were to sell additional royalty trust units, there would be production associated with that. And so, is that already reflected in the guidance you all provided? Or would that be sort of additional production, kind of like the East Texas assets sale, thinking about pro forma that way?

That would be additional, like if you're thinking about East Texas. So if we did another trust, we would adjust our -- we'll have a different net income attributable to minority net interest, and we'd be selling some PDP in production.

I guess, I was considering, if you all were selling units of existing in the open market.

Same question there, too. If we did sell some existing units in SDT and PER, then the public's interest would be larger, and our -- the net income attributable in noncontrolling interest in the income statement would go up a little bit, yes.

Your next question comes from the line of Craig Shere with Tuohy Brothers.

Three quick questions. One, I think William touched on some of it with saltwater disposal. It seems to be getting taken care of, but it looks like the LOE falling to $14.01 from $14.51, I think in the second quarter is making a lot of progress. Can you characterize the progress towards fully reversing costs from the electric and saltwater issues, as well as the inefficiencies from the ramp-up in the old Miss that was driving, I think, costs to -- what was it? $3.5 million?

The inefficiencies in the old Miss had us move to $3 million per well. We're seeing some service costs move down in the Mississippian play, but at the same time, we're bringing on additional rigs, ramping up and moving out into continuing to expand in the play. So we don't anticipate moving down our cost on the new Mississippian play on the cost per well. And then, on the LOE, I think for the Permian, as Matt mentioned, we anticipate continuing to move towards disposal wells versus trucking any water.

The $3 million doesn't include the saltwater disposals, is that correct?

That's correct. You are correct.

And 2 other quick ones. I see you broke out the EBITDA from midstream. That $50 million of EBITDA is obviously going to be growing over time. Do you see potential in monetizing that in any way in addition to the royalty trust and other property sales?

No. We're not anticipating monetizing the service operations yet.

Okay. Can you comment on per-acre average cost so far on the $700,000 of the new Miss.

No. We'll just be in and around our budget of $200 million.

Your next question comes from the line of Pearce Hammond with Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: Tom, if you can talk about the -- you mentioned you wanted to secure a partner for the new Miss. Do you want to finish getting all your leaseholds in place getting to the 1 million acres before you start that process? Or have you already started that process? And how should we think about timing on that?

We've said that -- I just said I think it will be through -- I think we will find a partner before the first half of 2012. That doesn't mean that we wouldn't start to discuss this with potential partners today. What we believe now or we know that we're on the course of winding down our leasehold buying. So by the end of the year, we anticipate being at or near where we want to be. So there's not much of a way for us to keep from getting to our goal as it stands today. So that's our how come we are, we're prepared to start talking to potential partners now.

What is the status right now of your CO2 contract with Oxy? You mentioned in the release, the Piñon Field. I'm just curious if there's any impact or any possible payments to Oxy on that?

There is. It's included in our LOE guidance, and then the contract with Oxy is a 30-year contract to deliver CO2 to them.

And then finally, how would you describe the service cost environment right now in both the Central Basin Platform as well as in the Miss?

We continue to see service cost fairly flat across both plays. We think that there are some other ways in the Mississippian project, in particular, that over time, we might be able to move down some cost. But today, we think that our costs are -- we're not seeing a service cost inflation in either of the plays and haven't since we started working there a couple of years ago. Pearce W. Hammond - Simmons & Company International, Research Division: And when you say over time move it down, do you think we can start to see the well cost moving down next year in 2012?

No. I think what we're looking at are different ways to complete wells, different -- just different as we build up a scale in an area that you do become more efficient as you drill more wells in each of the areas. But as long as you continue to add new rigs, that offsets the efficiency gain you have on your old rigs.

Your next question comes from the line of Hsulin Peng with Robert W. Baird. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: A quick follow-up question to your consideration for monetization of your trust units. I was wondering if there's some minimum threshold of units that you would like to keep internally? And also, if there's any -- what kind tax implication can we see from such a sale?

Sure. We have 3.8 million units of SCT and 4.8 million of common units for PER. The SCT units are past their lock-up period. Those are fully salable. The PER units will be through their lockup in February. Now that doesn't take into account the subordinated units that we have. We still have subordinated units in both trusts, and that represents about exactly 25% of the total units of each trust. So while we haven't targeted an amount, we would like to continue to hold the subordinated units don't convert to common for about 4 more years, and the common units are fully marketable now. In terms of tax implications, no, there are no tax consequences for us selling those units. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: So I was hoping [ph] there wouldn't be any tax leakage?

Correct, there would not. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: And it sounds like you will consider keeping the sub units, so only the common units would be potentially for sale?

That's correct. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: And the second question is -- I know you mentioned that you'll likely get to the 1 million acreage for the new Miss play by the end of the year. Is that when you think you can give us more details about the play, like where is the location and also the economics, the end of the year?

Yes. We're targeting the end of the year, yes.

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

When you think about the Oklahoma Mississippi and going into full development mode, and you're rapidly getting there. You're continuing to experiment at this stage, but if you would conjecture, let's say 5 years from now, what do you think is going to be the biggest difference. And I'll you 2 things that I'd like you to comment on. One, do you believe directionally that the down spacing is going to occur? And two, do you think you're ever going to be shooting for higher oil cuts? Do you care about how much water you're producing in your long view?

Last first. No, we don't care about the amount of water. Actually, in some of the areas where we have the most water production is where we produce the most oil. And as long as you're in the depletion drive, both the oil, water and gas depleted at the same amount. So having more water doesn't bother us. And in fact, some of the most permeable rock has the highest total fluid cut. And so, we encourage water production to get the most oil. What I think happens over time in 5 years is that this play becomes one of the larger plays onshore U.S., and the rig count moves up dramatically, maybe to a couple of hundred rigs, and we'll be a big part of that. So yes, I do believe over time that we'll be drilling wells closer together. I'm not ready to say today that it's exactly 4 wells per section or not. The worst thing you can do is overdrill a play, where I would much rather have 3 wells per section and know that we're spending the least amount of capital to get out the most oil production than to continually try to increase EURs and speculate that things are going to be higher in the future. So we'll just take this pretty slowly. But as you see, we've already tested the idea 18 times. So 18 pairs, and it is something we think about as far as drilling closer.

And then, that type curve, you guys say you're comfortable with 300 to 310 barrel per day number, and I respect that. But I'm curious if you have any anecdotal evidence of how wide is the range on the upside. What is the biggest well that you or maybe the competitor has had out there with this type of completion?

Well, I hesitate to say that because that puts us in with every other person who claims very high wells and don't talk about the overall trend of a play. So in fact, I just won't. Obviously, we have as high of producing wells as other large plays, but then we also have other wells that don't produce as much. So I would just encourage you to look at 300 barrels a day as a good well.

Okay, great. And then just back to the casing pressure thing one more time. Was I correct in understanding, Matt, that the solution to facility constraint is largely going to be casing pressure reduction, rather than building new facilities, at least at first?

Yes. I mean, largely, that's correct. We'll lay -- what we'll do, we'll lay separate lines of the casing. So that in itself will reduce the casing pressure. At the same time, we're anticipating a production increase. So we'll have to expand some of our headers that feed into the tank batteries. But yes, basically, you're right on.

Your next question comes from the line of David Deckelbaum with KeyBanc Capital Markets.

I just wanted a quick question for you. In the Mississippian, did I hear correctly that the gassy composition now is assumed to be 56%?

Yes, that's our anticipation. What we're seeing is that we were fairly correct on our oil type curve. But as we drill more wells, the composition of gas is increasing. So we're beating the type curve mainly with gas over oil, as we move out from the 244 barrels a day equivalent.

In the Permian, specifically in the Fuhrman-Mascho, I'm just curious to know, can you elaborate at all on what sort of EURs you booked PUDs on, and given some of the underperformance there now with some of the back pressure, do you see any risk to any of the PUDs that you booked at this point heading into year end?

Yes.

Our type curves are still the same. So what we're seeing is just a production issue, and there's no change in the projected EURs of the wells.

Okay. I guess preliminarily right now, midstream and some of the other miscellaneous spend was up $75 million, does that fully include all of the anticipated spend with getting Fuhrman-Mascho back up to where you'd like it to be?

Yes. A lot of cost from Fuhrman-Mascho will probably roll into next year, but that's incorporated into our 2012 budget. But in total, we're talking a pretty small amount year. We're probably talking something to the tune of about $15 million, $16 million to get all of this stuff done.

Your next question comes from the line of Mark Hanson with Morningstar.

Aside from some of the issues in the Permian, it sounds like things are firing in all cylinders. You've got a good hedge book in place, minimal service cost inflation, several years of inventory. I'm wondering here, as you think about the next couple of years, what are the biggest areas of concern for you or some of the biggest threats to achieve in your 3-year plan that you laid out?

Well, we try to hedge in the concerns that we have on the 3-year plan by hedging our oil production. So obviously, the biggest issue would be demand for oil in the world. And so, that's why we hedge so aggressively. And then, we also tried to not take -- we've hedged the other side of this by not taking into account any gain on the sale of the new Mississippian or any EBITDA from drilling in the new Mississippian. So I don't -- I think we've laid out a plan that we can hit very easily. So for me, we've already taken -- we've hedged our risk on a 3-year plan.

And then, as I look at the Horizontal Mississippian, I think I got my numbers right here. You guys exited the second quarter at about 12,700 BOE per day. You hit about close to 16,000 the end of July, and you averaged 12,800 for the quarter. I'm just wondering some of the variability over time there. Did you see a reduction at quarter end that would account for that lower average than, I guess, the trend would indicate?

No. We see continued growth quarter-over-quarter for the Horizontal Miss. We've grown it tremendously this year. I think we had around 53% growth, just Q3 or Q2, and we expect continued growth going forward.

Okay. And can you disclose what the current run rate is there?

As far as just the production?

Yes, average daily net production.

Yes, I think we're at around 18,000.

One more quick question. If you look at the 2012 guidance for per-unit lifting cost, it seems to be a little bit higher than I guess I would have expected, given that for the first 9 months, you're at about $14 per BOE. Maybe just some commentary there on potential cost increases?

Did you ask about the Mid-Con?

The aggregate lifting costs there for the 2012 guidance.

Actually, the lifting cost, we expect it to be about the same, finishing out '11 going into '12, that's going to be pretty flat for lifting costs. We did add some additional dollars per unit just to handle some of the fixed cost contracts that we have on the Piñon Field. So that increased, but from an operation standpoint, we see it being pretty flat.

[Operator Instructions] Your next question comes from the line of Adam Light with RBC Capital Markets.

Just a couple of follow-ups. On the Mississippian well results, can you at least sort of address how much variance, up or down from that 300-barrel a day well that you're seeing, and is it locational or is it more randomly spread through the play?

Adam, I'm sorry I heard the Mississippian well variances. I couldn't hear your question, I'm sorry.

What's been the spread between the poorer wells and the better wells versus that 300-barrel a day? And is there any dependence -- is it locational or is it spread evenly? Is the randomness even throughout the play?

Yes, I hear you now. So the play is a very large stratographic play, a stratographic trap that has -- so it's not like a shale play, it's set up to where there's not really a core area. So within each of the areas we drill, there are good and bad wells. And what the statistic we can use and can prove, I guess, is that in our first 37 wells, there was one that we talked about that would not pay back its costs. So on the downside, you kind of have a low rate of return, and on the upside, you have some extraordinary wells. So that's how you continue to have a very high rate of return on the overall play. But there is a wide variance in each of the areas, not in one particular area.

And for the rig allocation for the Mississippian, is that all for the original Mississippian? Or are you accounting for some drilling in the new play?

No. The only thing we've done in the new play is we account for the acreage money we spent, and we don't account for any sales or any drilling. So all of the drilling is accounted for in the original Mississippian.

So on the acreage spend in the third quarter, for the Mid-Con, was that all or substantially all for the new Mississippian or not?

I don't know exactly where all of them, but it includes our Mississippian new acreage bought in the Mississippian, yes.

And that was approximately 200,000 acres from the end of the last quarter. Is that -- am I right on that?

It seems like we had that, yes.

In our last call, we were at 200,000. Now we're at 7.

In the last announcement, I think was 500,000. So we're fast approaching where we need to be.

I'm just trying to do a little arithmetic there. And then, I'll try to ask this question, so you can answer it, James. The expectation on timing, given that we're in November already for this next trust, I'm presuming that's a 2012 event?

Yes, we can't comment on specific timing, Adam, but if you can take into account normal 30-day SEC review and that process, it would be really hard to launch something now and get it done in this calendar year.

Your next question comes from the line of Dan Morrison with Global Hunter.

A real quick one and kind of a follow-up on Adam's question. We had previously said that you haven't seen a hotspot develop or a core kind of emerge in the play yet. Does that still hold after the drilling you've done so far?

Sorry, Dan. Try it again. You're cutting out.

Sorry about that. Following through on Adam's question, you previously mentioned that you haven't really seen a core area evolve or hotspot. Has that -- does that still hold after all the drilling you've done so far?

Yes. We see the same type of variability across the play so far.

So it consistently inconsistent?

Excuse me?

Is it consistently variable?

Yes, it's consistently variable, yes.

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

Going back to the old Miss Play. Tom, what's the actual oil number out of the existing type curve. Is it around 200,000 barrels, a little bit better than that?

Yes, it's right in that range, 200,000 to 210,000 barrels on oil-type curve.

So if you bump up your EURs to match what you're currently seeing, is it your expectation that that oil number stays the same. It's just the gas piece that goes up?

Yes, that's correct. I think the old number will be real close. It may increase slightly, but you should see more of an impact on the gas side.

So how will that work if the reserve engineers don't give you any or as much of an increase as you're expecting? Do you think that the oil component there, whatever it might be, 200,000 barrels, could decline?

We don't anticipate a decline, based on what we've seen -- but you're right, that's up to the third-party engineers.

Okay. And are you planning to do any drilling in the new Miss play, say in the first half of '12?

If we find a partner and move forward in the play, but not until we sell some acreage.

Your next question comes from the line of Phillip Jungwirth with BMO Capital Markets.

On your 2012 production guidance, which Horizontal Miss type curve are you assuming to derive that? The current one or the one that you think -- the increased one that could potentially come by year end?

Our current type curve.

So I mean, that suggests that if you increase the type curve, you could probably see an increase in production guidance, which I guess would be more weighted towards gas than oil, based on what you're saying.

Well, that's a tricky question. We like our guidance, as we stated.

Okay. And then if you're experiencing constraints in the Fuhrman-Mascho, why wouldn't you be able to move rigs to drill the Clear Fork or some other of your other fields in the Central Basin Platform?

We are. We are going to move some of that around. But right now, the Miss is doing very well, and we have 800,000 acres in old Miss, not including anything in the new Miss. But in the Permian, we have 200,000 acres. So with this constraint, it makes sense to get reallocation rigs than new Miss and continue to drill that program out than to hold our acreage.

Keep in mind, we'll drill close to 800 wells. It's not like we're not doing our work in the Permian.

Right. And in 2012, do you still think you can drill 800 wells? Or what's the number of growth -- gross wells we should assume for '12 based on the lower rig count?

Yes, I got that. In 2012, we're kind of modeling about 760 wells in the Permian and about 380 wells in the Mid-Continent producers.

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

In your original Mississippian play, you ended up buying a lot more acreage than you had originally expected, because the lease costs were still low. Are you satisfied to stop at 1 million in the new Miss? Or would you raise that considerably if leased costs remain cheap?

No. We're satisfied with the 1 million, and that comes with anticipating in a 5-year plan how you can effectively drill out the play.

Okay. And then one other question. Are you looking for predominantly an oil company to joint venture with or a money-manager type, or does it make a difference?

Actually, it doesn't make any difference. We anticipate it will be more of an oil company.

Your final question today is a follow-up from the line of Craig Shere with Tuohy Brothers.

Very quick. Matt, I thought I heard you say that the costs for alleviating the pressure issues in the Central Basin Platform were only maybe $15 million, $16 million. But if I'm reading the delta between the third quarter and second quarter releases correctly, total midstream and other CapEx is rising $35 million between the 2 years. Can you explain where the other $20 million is coming from?

Sure. As we expand our Mississippian drilling next year, this year, we will probably drill somewhere around 170 to 175 Mississippian wells. Next year, we're looking at 380 Mississippian wells. So we have more costs going to facilities in the Miss as well, probably primarily in electrical infrastructure.

Okay. And so the things like electrical infrastructure and such, how much of this, if we think a couple years out, how much of this can really be monetized eventually? Is it just gathering lines? Or how do you think about midstream as it grows from $50 million EBITDA and maybe double sort of time?

Like Tom mentioned earlier, at this point in time, at least, we have no plans to monetize our midstream assets or any infrastructure facilities. It's just too integral at our development plan at this point.

Ladies and gentlemen, that does conclude today's Q&A portion of the call. I would now like to turn it back over to Mr. Tom Ward for closing remarks.

Well, thank you for joining us, and we look forward to talking to you in the interim and at the next call.

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