Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2011 SandRidge Energy Earnings Conference Call. My name is Gina, and I will be your coordinator for today. [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 conference, Mr. James Bennett, Chief Financial Officer. Please go ahead.

Thank you, Gina. Welcome, everyone, and thank you for joining us on our fourth quarter and year end 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. Keep in mind 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. Please note that today's call is intended to address SandRidge Energy and not our 2 Royalty Trusts, SandRidge Mississippian Trust I or SandRidge Permian Trust. Also, SandRidge will release its 10-K on Monday, February 27. Now let me turn the call over to Tom Ward.

Thank you, James, and welcome to our fourth quarter operations call. As you have seen from our press release, we beat our projections for the quarter and capped off a tremendous year for SandRidge. Let's take a minute and go through what transpired during 2011. We had a CapEx budget of $1.8 billion and cash flow from operations of $535 million. Where did the cash come from to fund our high rate of return drilling program? We raised over $2 billion in 7 transactions through joint ventures, Royalty Trusts and asset sales without increasing debt or issuing equity. As a result, we were able to grow our oil production by 60% and increase our SEC PV-10 reserves to $6.9 billion, which is an increase of 52%. We were also able to increase our net acreage position in the Mississippian to 2 million acres and retain 1.5 million acres even after the joint ventures with Repsol and Atinum resulting in $2.33 billion in value from cash and drilling carries. Our results in 2011 come only after the groundwork was laid starting back in 2008. Our move to oil was started by hedging all of our natural gas production in 2008 at over $8 an Mcf. At the time, we were considered too conservative as natural gas prices were surely going to bounce back in 2009. However, then we made the next critical step and bought oil in some of the best fields in the Permian Basin before the run-up in oil prices. This was met with resistance because we had to be buying oil in places where nobody else wanted it and it couldn't be a good deal. We moved into 2010 by buying Arena and met more resistance as we were thought to have overpaid for worn-out, shallow vertical drilling,…

Thank you, Tom. Before I run through a summary of our financial results, let me comment on our Dynamic acquisition. In terms of the fit and the reasoning for the deal, as Tom discussed, we were able to acquire Dynamic at a very reasonable price of $50,000 per flowing barrel equivalent per day, 3.4x EBITDA and 67% of proved PV-10. While we continue to view the Mississippian and Permian as our core drilling assets, in the case of Dynamic, if we can buy offshore cash flow and production for the low multiples that we are seeing, this represents a compelling opportunity for us to add inexpensive production and EBITDA, improve our leverage and de-risk our balance sheet, all of which remain consistent with our 3-year plan. Turning to the fourth quarter. As you can see in the earnings release, adjusted net income was $9.1 million or $0.02 per diluted share. Adjusted EBITDA was $175 million and operating cash flow was $153 million or $0.31 per diluted share. Fourth quarter adjusted EBITDA is up 34% over the comparable 2010 period, driven by a 26% growth in oil production and higher realized oil prices, somewhat offset by a decline in gas production. For the full year 2011, adjusted EBITDA was $654 million and operating cash flow was $535 million or $1.08 per diluted share. Note that operating cash flow does not deduct the distributions to the public unitholders of our 2 Royalty Trusts, which totaled $57 million in 2011. On per unit measures, LOEs continued to improve the last 2 quarters. And for the full year, LOE of $13.81 per BOE and production taxes of $1.97 per BOE were both below the low end of 2011 guidance ranges. DD&A of $13.97 per BOE was right within guidance and G&A of $6.35 per…

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

Tom, first question. Just on -- it looked like the last, I don't know, last several results on the horizontal Miss had been a bit better than what it was towards the beginning. Just wondered if you could comment on the type curve. Do you see that potentially reflecting the change again upwards or you're going to be content with that for a bit?

Well, we'll be content for this year, Neal, at 275 barrels a day on the first 30 days. We're the only company that gives all the data on our wells and the 30-day average of all of our wells that we drill. And so far, we're above the 275. And in fact, in 2011, we were at 302 per day on the first 30-day average, and we're continuing to be above that in 2012. However, we won't change our type curve. If it changes at all, we won't change it until the end of 2012, when we look back at the overall program as at the end of the year when we do our outside reserves. So remember, the type curve is established by the reservoir -- the outside reservoir engineers.

Okay. And then, Tom, it looks like on the upcoming or the second horizontal Miss Trust, that some of that -- some of those wells are going to be, I guess, in that what I consider now as the newer of the plays. And I was wondering now when you see sort of the operations or the wells you kind of have laid out to drill for the remainder of this year both within that new trust and just overall, will it be pretty spread out up in the Kansas, as well as entire area, or will you still be focusing on sort of different -- I don't want to say core areas, but the older areas?

Yes. I can't refer to the Royalty Trust, but I can say that we are expanding the saltwater disposal systems. So the key to the play is being able to dispose of water inexpensively. So as we have talked about from the very start of this play, it's knowing that there was a very large stratigraphic trap with oil in place and then how do you handle the massive amounts of water that come with that oil, and why it wasn't discovered over the last course of the last 50 years, this play, is because of the amount of water we produce. So the efficiency of taking care of saltwater disposal is what makes the core area. So the reason we've drilled the most wells in one particular area is because we already have the saltwater disposal system in place. You can save about $2 a barrel on thousands of barrels of water a day by having a saltwater disposal system. We're the only company that has a very large saltwater disposal system in place, and that's really the key to keeping the rates of return on the wells. And so to answer -- to further answer your question specifically is, yes, we plan and continue, we'll be moving out and adding saltwater disposal systems. But if you -- when you see our Analyst Day, you'll notice when Dave Lawler gives his presentation, that it's all keyed around the efficiencies of putting a disposal system first.

Okay. And the last one if I could, Tom. Just on the Dynamic, I know when you had the conference call around that, you mentioned just the plethora of all the workovers, not to mention the new wells that will be drilled. Is that sort of the plan to continue to look at rework opportunities in order to keep costs low? If you could comment on, as you see future rework opportunities mixed with the new well results, how you see kind of growing Dynamic maybe for the next year or so.

Sure. Matt will take that.

Yes, Neal, it's Matt. Yes, a lot of the projects going forward is going to be recompletions. They have 37 recompletions slated this year, and most of all that work is low risk through tubing priority work in existing wells and known production blocks. We'll probably drill 14, 15 wells this year, which 2/3 of those are development wells, and you have 5 or 6 that are exploration. But yes, the bulk of the work is going to be low risk up-hole recompletions.

Your next question comes from the line of Dave Kistler with Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Just following up on the Miss line. With that 2 million acres across the play for you guys, do you think about maybe at the Analyst Day breaking it up into couple different sections with different type curves? Just trying to figure out the best way for us to optimize modeling it.

Yes. I think at the Analyst Day, we still don't know enough about the entirety of the play to be breaking out different type curves. What we're trying to do is have a type curve that we feel is representative of the whole play, and we'll talk more about the extension versus the original part that we bought into and how the geology is the same, and how it might differ. And I think post-Tuesday, you probably should have a better understanding of how come we bought acreage where we did. And to say we're going to have a different type curve is just probably too new for that until we drill more sensibly across the play that -- I'm sure there will be areas that are better than others. We just have not drilled enough across the whole play to understand that yet. And what we're really seeing is good wells across the whole play. And so you can drill within areas instead of saying you have one core area within each of our townships. There are good areas to drill and areas that aren't quite so good. So we've drilled the most wells in the play and think that we understand where we like to drill so far. And that's -- I do think that on Tuesday, you'll get more of a flavor for what our ideas are. David W. Kistler - Simmons & Company International, Research Division: Great. Appreciate that. And then, just a clarification. I thought I heard James say that you only had about 250,000 acres that you'd look to JV in the Miss. Did I mishear that statement?

Well, keep in mind, we had publicly said that it was 250,000 to 500,000 additional acres, and now it's 0 to 250,000. David W. Kistler - Simmons & Company International, Research Division: Yes. And what's the driver of that change?

Just the Dynamic acquisition. David W. Kistler - Simmons & Company International, Research Division: So just not the need to monetize much, okay.

We want to own as much acreage as we can. David W. Kistler - Simmons & Company International, Research Division: Great. And then, last question. With about 82% of oil hedged for '12, what's kind of the targeting hedge profile for the company now? When you think about Dynamic, it's going to have weather-related risk, et cetera. Is there an optimal kind of hedge level that you guys look at? Or are you just looking to lock down pretty large levels, so you can lock in at least the near-term economics?

We're trying to cut the risk as much as possible in all ways in our business model. So if you think that our costs aren't rising, in fact, our service costs haven't moved up since mid-2009. And we now have rates of return in the Permian of 72% on the projected wells we're drilling this year and the rates of return close to 100% in the Mississippian. And we just see this as -- if you can lock in that price, it's nothing more than greed to try to get more than that. So as -- it's what you see, will continue to see is us, as prices move up, is to continue to hedge into that. And hope that prices continually move up, so we can hedge more in out-years. And I think it's as simple as that. So we're just trying to lock in, take out risk in our business model.

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

A couple questions. So first, the 1.5 million Miss acreage, that is after the 2 JVs, but assuming a successful second Mississippian Trust, what would the net be after minority interest?

Yes. The -- I don't know, can we talk about the second Mississippian Trust? We really can't.

We can talk about our whole acreage and what it would be after the Mississippian Trust.

Yes. I mean we're at 1.5 million net acres, and I can tell you -- I'll just tell you the second Mississippian Trust, what we're contemplating is only about 52,000 acres. So there's a very little impact to the entire play for SandRidge, if you will.

And how -- since you're retaining more ultimate acreage here, how should we think about any changes in the long-term drilling plan, wouldn't you need to jack that up a tad to ultimately HBP everything?

No, no. We're in good shape there. Because we run the rig count that we have planned in the ramp up. We're just adding a rig, all the way through '14. We look at substantially holding all of that acreage in a 5-year time frame.

I'm sorry, a rig a month through '14?

Yes.

Okay. And I guess, somewhere, given the time line you just described, the second Miss JV with Repsol was a bit of a step-down in value per acre versus the first Miss JV due to the inclusion of the extension play that obviously hadn't been as de-risked. At what point do you feel like you can say, well, this largely is de-risked and it's at least worth possibly what the original JV was?

Well, we think Repsol made a great deal. As it was the same de-risking that was in the original Mississippian before we drilled horizontally there is that you have thousands of vertical wells. And so in our opinion, it's very much a de-risked play. So now, we just have to go drill horizontally and convince everyone including ourselves, I guess, that it's the same as the original play. You'll be able to see a lot more on Tuesday, and understand our reasoning as to how come we think that the extension Miss is virtually the same as the original.

Okay. And the last question, Tom, with the guidance out there for doubling the EBITDA, and recognizing you didn't want to just issue equity and dilute everything but also recognizing some equity was used to acquire the attractive valuation, the free cash flow and the reserves from the Gulf of Mexico asset. How do you think about, I guess, production in EBITDA per share? I mean, do you have specific targets in mind for that?

Yes, this is James. The Dynamic acquisition was very accretive on cash flow per share and earnings, all those measures. So one of the things we look at is cash flow per share accretion. At the same time, what's our leverage levels and how do we de-risk it. So it's really balancing all those. I don't think we have a specific cash flow or earnings per share target in mind for that -- that far out, really, just focusing on EBITDA. But again, not wanting to have an over-levered balance sheet, not wanting to dilute the shareholders to get there.

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

As more companies come into the Mississippian, are you seeing any cost pressures as you add rigs? Or are these offset by the benefits of scale such as water disposal, as you mentioned and reduced drilling risk?

Yes. We're not seeing any cost pressure from the service side as we move in, move more into -- or rather, companies move into the Mississippian. Keep in mind that we use equipment that is readily available and has been the backbone of our industry over the last several decades and very shallow, low-pressure equipment. And the only offset that we have from not lowering our cost substantially is the efficiencies of bringing on new rigs. And so we continue to keep our costs essentially flat as we bring new rigs on.

Great, thanks. And then I think you mentioned in your opening comments that the $200 million of reserve CapEx that you're planning for the Dynamic assets from May on is back-end loaded. Can you add a little color on what's driving that and whether going forward, annualizing that rate to 12 months would over or understate your ongoing spending plans?

Yes. Answering the last question first, I think, going forward into 2013 and on, we can think about $200 million. What's happening this year, as you know, Dynamic was in the middle of an IPO process. They've grown through acquisitions since 2008, and this is their first year of really running a capital program. And the first thing people think about is when they hear about $200 million capital program, they take that, divide it by 12 and it's $16.67 million a year, and everybody wants to prorate that to the 8 months we're going to own Dynamic, so say $133 million. The fact of the matter is, they have 3 rigs coming in from Dynamic and the ways it's -- they're lined up, they probably will hit all the same time in April. And so, there's very little capital spending in January and February in everything because of the process that we're going through with this transaction and everything. Everything is kind of delayed, probably 4 weeks to 6 weeks. So the bulk of the capital spending is going to be really May through December. In fact, the high watermark is probably $35 million, $40 million in June or July and then it starts rolling off. But yes, we put a real hard pencil to it. We probably could have guided to $185 million, $190 million, but we chose to keep it at $200 million.

That's helpful color. And then lastly, with your focus almost entirely on the Mississippian, Gulf and Permian, can you just give us an update on the Century Plant C02 contract at Piñon mitigation there and whether we should expect any changes or restructuring to it?

Yes. No, there's no changes to the obligation to Oxy. And I think we have publicly showed numbers in the range of maybe $20 million annually for the penalty. But there's no change in that. We'll pay our penalty. We -- there's no reason to drill gas wells at this time with the high rate of return oil wells that we have in our portfolio.

Your next question comes from the line of Charles Meade with Johnson Rice. Charles Meade - Johnson Rice & Company, L.L.C.: First, Matt, thanks for the clarification on that Dynamic CapEx, I was wondering the same thing. But, Tom, I was hoping you could elaborate a bit more on your thinking with the Mississippian acreage. I think we're getting the message that you guys have a kind of diminished need or appetite to sell more acreage. But how does that fit with your incremental $50 million to buy acreage in the Mississippian?

Well, as I mentioned earlier, within townships, we have a different taste -- different well -- different types of wells. So as you noticed in the last 43 wells that we gave production on in the last slides that we had, there are some wells that are extremely good and some wells that are poor. And I think there are geological reasons around that. And so what we do is, once we have a good area that we're drilling in, we tend to try to buy more acreage and that's the infield drilling that -- or infield acreage acquisition that we're able to do. It's in fairly small amounts, but it does add up. But it's very accretive to us to buy that acreage knowing that we're going to drill it very soon. Charles Meade - Johnson Rice & Company, L.L.C.: Great. That makes sense. And so how many total acres do you think that's -- additional acres that's going to get you, that $50 million?

Well, we haven't -- we don't know yet as we just added that, assuming we're going to be able to buy that acreage in 2012.

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

Tom, looking at the guidance that includes Dynamic, I know you're only including May through December and building in some down time. But I was thinking back to the Dynamic roadshow. And so, weren't they looking at like 26,000 to 27,000 barrels a day in 2012? And that probably already included down time, I'm guessing.

Yes. Well, I don't know about the roadshow of Dynamic. When we reviewed the company and based on our acquisition, we looked at the company as producing 25,000 barrels a day in 2012.

And what are they currently producing?

Just -- well, they've been averaging just about 25,000 barrels a day. It's correct, Matt?

That's correct.

And then looking at the Permian EUR, I guess, change in current presentation versus say last year, when you went from 83,000 barrels a day -- I mean, 83,000 barrel EURs to 58,000. I mean, can you talk about that? What's driving that change?

Yes. We're going to talk a lot about that in our Analyst Day presentation next Tuesday. But just kind of long story short, there's a change in the well mix. As with most programs, you go out and you drill your highest rate of returns wells first. As we roll those wells out of the program, getting down to the smaller number of 100,000-barrel wells, we start drilling something that looks more like a Fuhrman-Mascho well, which is about 38,000 barrels like in 2012, about 600 or 760 wells or so we drill. It's going to be in Fuhrman-Mascho at 38,000, 39,000, 40,000 barrels a day. So that drives the entire average of the program down a little bit.

So you're looking at it more as a yearly EUR number rather than long term?

It is more of a program, annual program number. But also this year, we're getting to the point where that program pretty much represents the entire reserve space going forward. So this is what I think you can expect going forward, is this kind of 72% rate of return, 58,000 barrels equivalent-type number.

Okay. And lastly for me, any indication yet, I guess, from BOEM on how they're going to handle the transfer of the Dynamic leases? I know Energy XXI ran into some pretty significant delays following their acquisition of Shell assets a little over a year ago, where the BOEM held up some of the leases for an extended period. So any early indication from BOEM on handling?

Yes. We are working through those issues as we speak right now. And at this time, I don't -- there's no indications there's going to be any delays or any problems doing so. So I don't expect any issues at this point.

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

Just a quick question on Permian, kind of update on the replumbing project that you all launched into, is that pretty much wrapped up?

Yes. I think in our November call, we say we would be complete with that by the end of the second quarter this year. We're on track to do that. There were 28 tank battery projects. We finished 11 of them. By the end of 2011, at year end, we're currently working on a dozen more here this quarter, and we'll finish that in the second quarter. So far, with decline in production and with new wells being added on, the net impact is probably 500, 600 barrels equivalent per day. And we were anticipating kind of 1,500 barrels to 2,000 barrels of improvement when we finished. I think we're on track to do that.

Great, thanks. And with the Dynamic, you talked a little bit about recompletions kind of being the gist of the capital program in near term. When -- are there any drilling projects in this year's CapEx, or when do those start to come in?

Yes, there are. I was mentioning earlier, I think, the plan is to drill about 15 wells starting in April, kicking off with 3 rigs. So yes, that is a pretty significant part of the capital project for 2012 drilling.

Okay. Sorry, I missed that, Matt.

I'm sorry?

I said, I'm sorry, I missed you saying that.

Okay.

[Operator Instructions] And your next question comes from the line of Joe Allman with JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Tom, just strategically, at this point, you now have 3 core assets when you include this Dynamic deal. So are you satisfied with these 3 core assets? And my impression was that you were satisfied with the 2 core assets, and that you were going to actually stick with those 2 core assets until some point in the future. So just like looking forward, is this in terms of the portfolio?

Sure. I never know what the future brings, but what I looked at was options as far as funding our Mississippian growth, and then the Dynamic or the idea of shallow Gulf of Mexico but really having a team that can make accretive transactions in the cheapest well in the world basically was appealing to us. So yes, we did make a move from 2 core assets to 3 core assets. So we're hopeful that we can continue to buy low-cost oil, if others are willing to sell out of an area that is selling $125 oil today for 2.5x cash flow, I think we'd be willing buyers. But I don't have any plans, as we talk today, to have a new area. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. That's helpful, Tom. And then remind us how much free cash flow you think the Dynamic assets will throw up each year.

Yes. There's been a number -- we've talked about around $100 million. That's a good estimate. Joseph D. Allman - JP Morgan Chase & Co, Research Division: So and you're basing it, you're taking on several hundred million dollars of debt. So it will take you, say, 6 or 7 years to pay off that debt with the free cash flow. Is that...

Well, but you still have an asset that's producing 25,000 barrels a day. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Even after you paid off the debt you're incurring for this transaction?

Each year. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. And in terms of the -- so are you going to be taking on all the professionals from Dynamic to run the program?

We are, yes. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. And on an annual -- like what kind of G&A add is that annually?

In the range of $30 million, which is consistent with what Dynamic had in their best one. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. All right. And then I know you guys went through sort of how you're going to be paying off your funding gap, your CapEx versus cash flow the next 3 years. But can you just kind of go -- just list the items that you're going to monetize? Are you still going to sell the common SDT unit? Is that still planned? And then the common PER units?

Yes. You saw we sold almost 1.6 million units earlier this week. We said, I think starting 6 to 9 months ago, that those -- all those common units are available to monetize and as funding options. So I don't know, I'm not going to comment on specifically when and if we'll sell them, but it's an option for us to use to monetize. We could also JV some more of the Mississippian acreage. And keep in mind that we've got $200 million of cash right now, $250 million if include the units we just sold. A fully undrawn revolver, which we expect to increase to the size of that revolver later this -- earlier -- early in the second quarter. And also, cash flow from operations is going up quite a bit this next year. And so we think we're fully set this year and what that positions us to do is come next year, we're in a good position to utilize some long-term debt if we need to. Our credit measures have improved. So we think we're through this period where we were in 2011 of 7 transactions monetizing assets. We're kind of winding down our asset monetization needs here.

That's why I call the next 3 years, years of harvest. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Got you. Okay. So at this point, once you get this Dynamic deal done and you're basically satisfied with the balance sheet at this point, no need to reduce debt beyond now?

That's right.

Our credit metrics are improving.

Your next question comes from the line of David Heikkinen, Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a question and I wanted to clarify, did you talk about adding one rig per month in the Mississippian between now and 2014, so would that take your rig count from roughly 21 rigs to 45 rigs in 2014?

Yes, we're looking at moving to 45 rigs. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And so, as you think about a 2014 capital budget, what will that be?

We haven't projected 2014 capital budgets yet. But as we -- we've talked about staying within the range of between $1.8 billion to $2.2 billion. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then just going to the Permian, Matt, I think you said that more of your locations are more like Fuhrman-Mascho heading forward, thus the shift in type curve, is it -- that your remaining inventory is more San Andres like or...

Yes. I think, what I was trying to say is that our program is pretty much going to be dominated by San Andres wells. For example, in 2012, 600 to 760 wells will be San Andres wells, and that's the way we should think about it going forward. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. So more of the shallower, lower-cost wells?

That's correct. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And then just kind of final question, and this is comparing and contrasting. Range talked about the chat [ph] being important and being on a structural high, important from their acreage in the Mississippi line. Do you have any thoughts about, I don't know if you'd read their commentary or thought about the importance of having chat [ph] or being on a structural high in the Mississippian. But if you have any thoughts, it'd be helpful just to compare and contrast for us.

Sure. We look at the play as a very large stratigraphic trap that has subtle structure involved in it. But more of being encouraging the processing [ph] impermeability out of water-bearing rock. And so it's not important for us to be structurally high in a given area. So yes, we do look at structure in very specific areas, but over the region, that's not important, and we've drilled some of our best wells in structurally low positions.

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

Just to follow up. Originally, before the steep ramp in the rig count in the Mississippian, I think you all were looking at efficiencies maybe driving cost to, if I remember, $2.7 million a well. But that a rig a month led to some inefficiencies, you kind of postponed that for a while. Given the fact you're going to be adding a rig a month for an extended period of time here, is there a point where the legacy rig count becomes so great and the efficiencies of those become so great relative to the additions that you think we start turning the corner on cost, average cost per well a year out?

Well, I'll say this. Let's take -- watch us on Tuesday and we'll spend a lot of time talking about cost, because the real driver in future rates of return to even be higher rate of return is in lowering costs. So there are a number of ways that we're looking to lower costs. However, as we bring on a rig per month, we're still anticipating keeping our cost flat because of the inefficiencies of new rigs that come in. So as of today, I'd like for you to keep your cost at a $3 million range, but watch us on Tuesday and see if you can be encouraged about how we might be able to drive down cost in the future.

Your final question in queue is from the line of Anne Cameron with BNP Paribas.

A question about your rig count. So you're adding a rig a month, that gets you to a max rig count of, I think, it was 45 rigs?

Yes, 313.

Okay. and so how many -- like that's gross of the Royalty Trust rigs?

That is.

Okay. So if you do another Royalty Trust, like what's the sort of max amount of rigs you could have committed to drilling PUDs on the Royalty Trust acres?

Well, we can't talk about the second Royalty Trust, what we can talk about in the first Royalty Trust is that we had basically 3 rigs running on the SDT.

Okay. And the max rig count of 45 rigs was the same max rig count before you added the extra million acres in the new Mississippian?

Yes.

Okay . So how is it that you can double your position and still run the same number of rigs without, I don't get, say, like impairing the present value of the acreage?

Without impairing -- so your -- without impairing the present value of the acreage.

Well, it's going to take you longer to get that acreage [ph].

Well, it's how come we sold 500,000 acres, and I don't think it impaired our present value on it.

Okay. But these are gross rigs or net rigs?

They are gross rigs.

Okay. So isn't -- aren't the same number of rigs going to be running on your acreage overall as before those transactions?

We're looking at drilling kind of 7,000 wells out here over the next 12 years. That's how the NAV of this acreage is figured out. So if you're looking at 45 rigs, you're kind of drilling 500 wells a year. So I mean, there's really no movement in the PV. I mean, if you look at 500 wells a year, you're looking at kind of potentially holding 300,000 acres or something like that a year times 5. You have your 4.5 million acres held. And that's just Oklahoma. In Kansas, you can hold about 1,240 acres per well. So I think the way we have it designed is 2 ways, one is to maximize our present value to realize NAV and at the same time holding all our acreage.

You have additional question from the line of Alex Heidbreder with Millennium.

So I understand that you guys don't want to sell acreage because that makes a lot of sense because it's very NPV destructive. But in terms of trying to bring forward some of the NPV from the Mississippian, why aren't you looking to bring forward some of the 7,000 net locations? I mean, even if you're doing 500 locations a year, you still have 12 years of inventory today, and years 7 through 12 don't create a lot of NPV.

So you want to drill more?

Yes. Well, or find someone else to drill it for you and keep the economics.

There are 5 other guys right behind you that want us to drill less.

But they're wrong.

Well, it's really the efficiencies of the play. And I think if you watch on Tuesday, you can see that they're trying to, let's say, double our rig count and do disposal work and having all these. When we look at an area, it's really 18 square miles and we put in disposal system, you have to really do everything, not just go out and drill wells and bring them on. You have midstream and really disposal system is also critical to this and to keep our cost down. You don't want to be moving in too many rigs at once. So we feel like the best thing for the company and the most efficient is to maintain the highest rate of return is to add about a rig a month.

And so by the end of the year, that means you're at a 500 per year rate?

By the end of '13.

By the end of '13. And how aggressive or conservative is the 7,000 net locations?

Well, it's 3 wells per section, and you can have a debate on whether you should be more or less on that. I don't think anyone is less than 3 wells per section that's currently drilling. So I don't know if that's conservative or not. And I think we're comfortable with 3 wells per section.

I mean, 10 years from now, is that still going to be the number or it's going to be 4 or 5 or what -- I mean, if you had to guess as to where it's going to go eventually?

Well, if I had to guess, I'd guess at 3 wells per section because that's what we currently model. But there are -- we've tested 4 wells -- or we've tested as close as having 4 wells per section, we're not seeing interference. But that doesn't mean that we want to change our idea yet of 3. We don't want to spend capital and have drainage, so that's how come we're projecting 3 wells right now.

Got it. I'm patient, I'll let you drill it out. But you guys are clearly not receiving hardly any of the NAV value today for the 7,000 locations.

Yes. You would be one of our few shareholders that are patient.

And I don't think another JV or 2 would hurt NAV as much as it would bring forward NPV.

We hear you.

Ladies and gentlemen, that concludes the Q&A session with all question answered. I will now turn the conference over to Mr. Tom Ward for closing.

Thank you. And as always, we appreciate your attendance, and we look forward to seeing you next Tuesday at our Investor Day. Thank you.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect, and have a great day.