Good day, ladies and gentlemen, and welcome to the First Quarter 2011 SandRidge Energy Incorporated Earnings Conference Call. My name is Kiana, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. Now I'd like to turn the call over to Mr. James Bennett, Chief Financial Officer. Please proceed,

Thank you, Kiana. Welcome, everyone, and thank you for joining us on our first quarter 2011 earnings call. This is James Bennett, Chief Financial Officer. 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 inherent risks and uncertainties. The actual results may differ materially from those projected in these forward-looking statements. Additionally, we'll make reference to adjusted net income, adjusted EBITDA and other non-GAAP financial measures. A reconciliation of any non-GAAP numbers that we discuss can be found in our earnings release and on our website. Now let me turn the call over to Tom Ward.

Thank you, James, and welcome to our first quarter financial and operations update. I'll lead with a few opening remarks and turn over to Matt and James. For the last 2 years, we've had a very simple and focused strategy of acquiring and drilling for shallow conventional oil and carbonate reservoirs. We initiated our acquisition of oil by focusing on the Permian Basin because of the tremendous source rocks and production that have been developed over the last 80 years. The Permian Basin is the largest oil-producing basin in the Continental U.S. with over 29 billion barrels of oil produced. After focusing on the Permian, we decided to further focus on the Central Basin Platform as our core area of interest. The CBP has produced over 12 billion barrels of oil from only 3 million acres, defining the best oil-producing area within the best oil-producing basin. We made 2 acquisitions with a net investment of $1.8 billion. It's now worth over $3.2 billion, showing a growth to investment of nearly $1,400,000,000 in than a year. Not only have we made tremendous value growth, we now have nearly 10 years' worth of drilling even though we drill over 800 wells per year and own over 185,000 acres of prime land. Plus, we did not have to spend capital on expensive non-EBITDA-producing acreage. At the same time, as we are acquiring on the Central Basin Platform, we targeted another shallow carbonate oil play in the Mid-Continent. The Horizontal Mississippian play is now recognized as one of the premier shallow oil projects in the U.S. SandRidge storage [ph] worked this area in 2007 by drilling less than a dozen vertical wells. However, as we developed the idea that there were tremendous amounts of oil in place over a very large area, we stepped…

Thanks, Tom, and good morning to everybody. I will elaborate more about our production drilling performance, CapEx and LOE. First, I will walk through a reconciliation of our Q1 production. If we can start by going back to Q4 of 2010, we produced 28,400 barrels of oil per day and 204 million cubic feet of gas per day for a total of 62,400 barrels of oil equivalent per day in Q4. In Q1 2011, we produced 28,700 barrels of oil per day and 192 million cubic feet of gas per day for a total of 60,700 barrels of oil equivalent per day. Q1 2011 production was slightly lower than Q4 of 2010 production due to the sale of the Wolfberry assets and the severe freezing weather that SandRidge and other operators experienced in West Texas. In the month of February, we had below-freezing temperatures for about 2 weeks and single-digit temperatures and the rolling blackouts for several days during that period. We believe these extreme conditions were 30-year, if not 50-year, weather events in the Permian Basin. The sale of the Wolfberry assets account for about 1,600 barrels of oil equivalent per day, and the weather-related downtime amount to another 1,900 barrels of oil equivalent per day for a total impact of about 3,500 barrels of oil equivalent per day in Q1. If we add this back into our Q1 production, we would have produced 64,200 barrels of oil equivalent per day, and we'd have seen a 2.9% production gain quarter-over-quarter instead of a 2.7 production loss, 2.7% production loss. As a result, there was nearly a 6% production swing due to the sale and the weather. In regard to oil production, we produced 28,400 barrels of oil in Q4 of 2010 and 28 -- I'm sorry, we produced 28,400…

Thank you, Matt. I don't plan to recite every number in our release, but I'll touch on a few of the items warranting further discussion. For the first quarter, adjusted net loss was $10.1 million or $0.02 per diluted share. Adjusted EBITDA was $146 million, and operating cash flow was $100 million. EBITDA is up 12% versus the fourth quarter of 2010 and 4% versus the comparable period in 2010 as a result of higher oil production and higher realized oil prices, somewhat offset by a decline in gas production and lower realized gas prices. On the expense side, total lease operating expense increased approximately $24 million over the first quarter 2010 as a result of the Arena acquisition, which closed in July of last year as, as well as an increase in total production and a higher percentage contribution from oil. Oil production in the first quarter of 2010 was 47% of the total versus 28% in the first quarter of 2010. On a per-unit basis, lease operating expense is $13.55 per barrel oil equivalent. It was approximately $2 per barrel higher than the 2010 comparable period and slightly above our guidance of $13.10. And as Matt discussed, the primary reason for this higher per-unit LOE in the first quarter was an interruption in production and an increase in onetime costs due to the severe weather and associated freeze in the Permian Basin. Excluding the weather-related impacts, LOE would be right at the high end of our guidance. All other expense items were in line with the guidance range, and we are reaffirming our full year guidance. Our earnings release includes an updated guidance table. The only 2 changes to note in the guidance are slightly higher oil differentials due to a higher production contribution from NGLs and the…

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

A question, Tom. You mentioned about going to Grant, Woods, obviously, besides Alfalfa County in the Horizontal Mississippian. I'm just wondering kind of. I know it's early but how you're seeing that. Maybe if you could give a little more color as far as kind of how you're seeing that play out as far as thickness, liquidity, et cetera, on that.

Sure. We target between 200 to 800 feet of total thickness in the Miss. Grant, as we've talked about, has a little bit -- vertically -- from the vertical wells, has a little bit higher oil ratio than further west. However, the estimated ultimate recoveries are somewhat better vertically to the west. So we've -- but the value between oil and gas on the vertical wells is about the same. So we've always looked at Grant, Alfalfa and Woods as -- and even clear out to Comanche in Kansas as being basically the same type of reservoir to drill for. And so far, in the wells we're drilling, statistically it looks just like the other areas we're drilling in. It is early, but we've now drilled over a dozen wells. We're producing over a dozen wells, and it appears that they're the type curve-type wells.

Oh, good to hear. And then, Tom, at one point, I think maybe at the Analyst Day, you had talked about given what's going on in Cushing about trying to divert some of your takeaway. Just wondering what it's about: sort of takeaway pipeline, et cetera. If you could comment there.

Sure. The only plays that we look to divert away from Cushing is out of the Permian Basin. And that is still ongoing with discussions. And Matt, do you want to address that?

Yes, Neal, there's -- unfortunately, there's not any short-term solutions. What's going on in Cushing right now is, as you know, there's about 50 million barrels of oil storage capacity. And just in the last 3 years, we've gone from about 17 million to about 40 million barrels inventory. The storage is filling out. How about -- by the end of this year, there are 4 companies that is adding storage. So we should see about -- that 50 million going to about 65 million of storage capacity. That'll give us some relief. However, as far as pipe coming out of Cushing, I know we in Ridge are looking at projects as well as TransCanada and some other parties. But we're publicly realistic 2 years out from build to hauling more oil out of Cushing into the Gulf Coast via pipeline. We are looking at a project, and -- that Magellan is looking at potentially reversing what they call their longhorn line from Crane County back to the Gulf Coast. And that may -- I think there's a lot of interest in that. We're certainly interested in doing that just to get a little bit of oil away from Cushing. But still, that's probably 18 months out.

Got it. Got it. And then the last question, maybe for you, Tom, is just on, or maybe for Matt, is just on service costs in general. Obviously, yours are much lower than a lot of the other regions out there. But are you doing anything to lock in long-term contracts like a lot of others who are out there? Or just on completions in general if you could comment.

We are effectively hedged on the drilling side with the rigs that we own. And we look at the areas a little bit differently. In the Central Basin Platform, we use even less horsepower on our fracs than even in the Mississippian. But both of them are low-horsepower fracs. The Central Basin Platform has really very little service cost creep, except especially the very shallow vertical wells we drill. As you get into horizontal wells and move up from the 500- to 750-horsepower rigs up into the 1,000-horsepower rigs, we think there could be, as we look out into the future, some future costs creep in, in the area, and that's what we're going to try to keep away from. As you think about this, we were planning to go from 12 rigs at least 24 rigs next year. We know that other people in the play have bought very large amounts of acreage, and we assume that they will be moving up rig counts either through private equity or public companies as they start to develop the play. All of the Mississippian isn't that much different in this respect in that you only have a certain time period to get wells drilled. Now for us, fortunately, we were there early and have 3 years with 2-year options. So on very inexpensive leases. But lately, companies are having to take shorter and shorter term in order to get a hold of leases. And that will require more rigs to come in the area. So we anticipate that the Mississippian will have some kind of a pressure going forward in service costs, but not from high-pressure equipment that's being pressured around the United States in a lot of different areas. So it's different, but still we'll have some -- the Central Basin Platform, we just don't see anything other than labor and fuel as being an issue.

Got it. Okay, good answer.

And our next question is comes from Scott Hanold with RBC Capital Markets.

Hey, Tom, you all talked about 3 options. Obviously, the fund gets to a much higher level of activity in the city next year. When you look at those options, can you kind of just broadly give us a description of how you think of each one of those and maybe your preference at this point?

Sure. The royalty trust structure, we like a lot. We continue -- if you have rates of return in excess of 100% and you have willing buyers at 10% rates of return and if you can do that in more scale, that would be our preference across the whole play. The problem is, as you know, is that they'd only -- we only had 42,000 acres in our AMI on the royalty trust that we just did. We will continue to look at that as an alternative moving forward. And along with that, we were interested in talking to potential partners for a joint venture. We don't know in what size that would be, but that's something that we'll evaluate. And the third option is that we just we keep more ourself. And so everything we're doing is with the idea that we like the play more than we did the last quarter, and we want to own more of this ourselves. So that is what we're trying to move towards.

When do you feel you all need to make a decision on which way you go? I mean, should we expect sometime in early second half of the year? Is that something closer to the end of the year you -- I mean, how long -- when do you think you -- when do you want to have financing taken care of?

We want to have financing taken care of for 2012, before the end of 2011. So I think you'll start to see us be active throughout the rest of the year, just like we were at the beginning of this year or sort of last year. So, I mean, what I focus on the most is making sure that we fund next year's drilling program.

Okay, good answer. And on the -- I think you mentioned you're going to move some more company-owned rigs in the Mississippian. And would those be coming from the Permian? Because correct me if I'm wrong but you're operating all your owned rigs, am I correct?

We have some that are working for other parties right now. We have 10 rigs that are working outside.

Okay, so you'll be able to take those back? Is that right?

We can do that. Or we can also -- you have the same effective hedges if you hire somebody else and leave your rigs in the Permian. We are planning to move some rigs up.

Oh, okay. And one last question, if I could. When do you plan to start stepping out to the Northwest like Comanche County? When is that first well going to be drilled?

Now.

Now? Okay.

Yes, we have one well drilling in Comanche County or completing.

That's great.

Our next question comes from David Heikkinen with Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Tom, just on the rig commitment and the services side. Can you talk about the duration or type of commitments you're doing as you go to 12 rigs? And then I think kind of last question was getting into the vertical integration and desire to really vertically integrate the Mississippian as well. Just kind of general thoughts.

Sure, I'll take the vertical integration. When we came into the company, we already had a number of rigs. We still have 31 rigs today. It's been very efficient for us to have our own people working in the same area for long periods of time in the Permian Basin. We've brought some of those rigs up. But 6 of our 12 rigs working are Lariat rigs, which are company-owned, and we've been happy with that model of owning some of our own rigs. However, at the same time, we have other rig companies that are working for us that, as they move into the play and work for a while, are also very efficient. And I'll let Matt address how we're planning to move forward with the rig count.

Yes. Right now, we have -- about half the rigs drilling in the Miss play we do own. So we have about 6 rigs out there that are third-party. And they're on various contracts. We have some that are 6 months contracts to a year contract, and we're continuing to renegotiate or negotiate those for 2012 already. We've also had some 24-month contracts that we're working on for the 2012 program. So they're different contracts, but I'll tell you, the rates are still very good, and they haven't materially increased very much. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And so does it have a ladder kind of 6-, 12-, 24-month rolling contracts on the 12 rigs?

It is but -- yes, it is a ladder. And when we're trying to source rigs today for our '12 program, those are the ones that are coming in at 24 months, because what they're going to do is take them off whatever program they're on now and commit them to us starting, say, in January -- first quarter of 2012.

And then, Dave, think of this just that the -- we use a range of 750-horsepower to 1,000-horsepower rigs. So our preference is not to have to bring out rigs that are stacked and put them to work. We have done that. But our preference is to keep rigs that have been working in other places and bring them into the play so that our efficiencies are good. I don't think we'll have an issue getting rigs unless other companies are going to move up to 25 or 30 rigs, and that's where we worry. Today, there's not an issue with getting rigs. It's just that we know there is a lot of acreage being bought by several different companies, and we just assume that rig count will be going up. So if you look at the market of 750-horsepower rigs, heavy 800- to 1,000-horsepower rigs, today there's ample rig capacity. So all we're doing is looking out to 2012, making an assumption that the Mississippian grows rather than stagnates. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then on the water disposal side, I mean, water disposals take a lot of fluids. As you double your activity level, how much capital would you have to put into water disposal next year? Can you talk about that?

Yes, I'll address that a little bit. It depends a lot on where we drill. Because right now, even with one or 2 wells, we're drilling disposal for it. So we minimize LOE and we'll grow into the disposal plan. I'll tell you right now we have 24 disposal wells in operation. By the end of this year, we should have around 30. And currently, or our current disposal volume is for 150,000 barrels of water per day. The disposal capacity we have is over 400,000 barrels per day. So the main reason we upfront-loaded our disposal well is so we can continue to develop these wells and not have -- not be behind in disposal wells. I think by the end of this year, we should be pretty good for 2012.

And I think, too, that as we drill -- or as we drill new areas, that requires some new disposal systems. So we will continue to have some frac costs as we continue to look into new areas. So as you think about output to Grant, those are all in one disposal system, but the pipeline system can be connected in between disposal wells. So it really depends how successful we are in all the other areas. We assume we're going to have successes, so maybe I could even say it depends on how quickly we decide to step out into different areas and test new areas. Even though there's vertical well production there, we probably will move around and drill horizontal wells in different areas. So that's -- it's not set in stone as to how many disposals we'll have because it depends where the horizontal well program goes. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay, so thinking about that 24-rig program, how much would be step-outs? Is it 1/3, 1/4? I'm just trying to get an idea of how should I allocate capital.

Well, let's -- I think that, I mean, it's hard for me to say because at one time, the Grant County wells were considered step-outs and now they're not. So when we drilled the disposal system in Grant County, it was considered a step-out. And now it's just basically hooking into the Alfalfa County system.

And our next question comes from William Butler with Stephens.

I was wondering if you could provide some more detail on percentage of liquids production with NGLs?

Sure. I'll let Matt take that.

Yes. In Q1, we ran about 18% NGL. We had actually modeled a little bit lower than that, around 14% NGL. And the reason the NGL was higher was that it was not at the expense of oil production. But we did renegotiate some contracts in our favor with the processes in West Texas, which boosted our NGL netbacks. So we okayed the plans.

So just to clarify. The 18%, is that as a percent of total production of oil or liquids production? Sorry.

Liquids.

Okay. And then on the royalty trust distributions, given sort of the ramp in the current distribution, what is that going to show up in terms of for the year? What do you think the total distributions on the trust will be on SandRidge's cash flow statement?

Sure. And I'll point you to the S-1 for SandRidge Mississippian Trust. In there, it outlines the distribution schedule by quarter.

Yes.

So that's a really a good place to start in terms of what the projected distributions are by year. So you can really pull that right out of the S-1.

Okay. And then 100% to the public, I guess, even backing that. On your rigs, they're running at 100% utilization now, the old rigs?

Yes, that's correct.

And has it gotten to a point on the demand, or do you see it getting to a point where you all might actually look to use that as a source of funds? Lariat?

Oh, not necessarily. The rigs are -- when everybody wants a rig, you want them yourself. And when nobody wants them, you can't get rid of them. So I guess that right now, we enjoy having our own rigs working for us.

Okay. And given what's going on out in West Texas with the fires and dry weather, do you see any issues for water availability for frac-ing?

No, we haven't had any issues.

Okay. And then last question. In terms of competition for leasing in the Mississippian Lime, what is sort of the current going rate now for acreage?

Well, it's higher. I think what that we have done, and you can look on our presentations, so we have a geological model that we have stayed within. And we're only are buying within the areas that we've outlined in that presentation. That doesn't mean that there isn't a Mississippian outside of that. And so you can have large amounts of Mississippian acreage being bought that might be every bit as good or better than what we have. It just doesn't necessarily fit the geological model that we've put together. So I think that just because people have bigger and bigger acreage positions, it doesn't necessarily mean that we're competing on that acreage. And for a week, what we have done is now basically slow down our acreage acquisitions into the areas that are close to our existing production or inside of that geological model we had presented. So I think we can say that acreage prices are going up but that our spending is decreasing by fairly dramatically.

Okay. And you still anticipate getting up to the roughly 1 million acres?

Yes.

Okay, great. That's it for me.

And our next question comes from David Kistler with Simmons & Company. David Kistler - Simmons & Company: Real quickly, just looking at you've drilled 72 wells in Miss. 37 of those are in the royalty trust. Of the balance between that and the 72, how many of those were dedicated to the royalty trust? And when will you have a level sufficient to thinking about doing another royalty trust?

We're going to talk about those?

Hell, yes.

We're not.

Oh, we're not going to talk about the trust number wells on this call. Well, I can tell you this. What's public is that we have dedicated 3 to 4 rigs to drill royalty trust wells. David Kistler - Simmons & Company: Okay, so we can complete...

I'll talk about -- when we did the royalty trust, we had 12 rigs running. And so I think that you do have to have proven reserves to put into another trust, and that's what we're building on. David Kistler - Simmons & Company: Okay. So just thinking about it from a run rate then, if 9 rigs are allocated probably by mid-summer based on the number of wells that are being drilled, you'd probably have a sufficient number to be able to start having a reserve evaluation and potentially move forward with another trust?

Well, that's fair. As long as the market's still there. David Kistler - Simmons & Company: Yes. And then really, I'm just trying to lock down thinking about the capital side of it. And as long as we're on that...

I've said publicly that I wouldn't mind looking at $1 billion from royalty trust net to SandRidge this year. David Kistler - Simmons & Company: Perfect. Perfect. Then looking at the revolver, it came down a little bit with the issuance of senior notes, which is to be expected. But there'll be a redetermination in the fall, I imagine, you're obviously tied very closely to reserves. Too early to say, but maybe looking back at the redetermination you just had, a possibility for that to be expanded. Any color you can give us on that would be great as kind of a vehicle to think about 2012 funding.

Sure, Dave. We did disclose our redetermination. We decided to keep it where we had the revolver at $850 million. With the upsizing of the IPO -- I'm sorry, the high-yield offering, that took it down to $790 million. We decided to leave it there at the redetermination date. I think we had ample room to push it up. But given our sources of capital this year, we really don't anticipate being in the revolver all that much. So we didn't need, say, $1 billion revolver. We'll revisit it again in the fall. But I think this level, $790 million, is ample liquidity for the near term. David Kistler - Simmons & Company: Great, appreciate that. And then a little bit out of the bailiwick. I don't know if you guys can comment on it, but I'm guessing you've been watching it. Any kind of update you can give us on the Eagle sale and what the status is of that?

Well, I actually talked to Steve Antry this week anticipating that we might get a question and asked him what he might like to say if he had a chance to sit on the call. And what he told me is that he would say is that they had decided, after their well performance and watching our performance and the performance of the royalty trust, to delay their proposed sale and leave their options open to drill more wells for the next 6 to 12 months. David Kistler - Simmons & Company: Great. Appreciate the color. One last, just cleanup question for modeling. Natural gas production down 6%. No rigs directed towards drilling that. Is that kind of the decline we should be working in? Or when will that abate a little bit in terms of as we model things forward?

Yes, I think we produced I think --- in this outcome, I think 76 Bs of natural gas last year. And we were -- I think we only produced about 66 Bs this year. And so our natural gas in Q1, I think it was actually a little bit ahead of what we had projected for Q1. So I think we're still right on track to do that.

And that's why I would say, too, so actually yes, we think we're fine on our gas production to date.

Okay. Great, I appreciate it, guys.

Our next question comes from Amir Arif with Stifel, Nicolaus. Amir Arif - Stifel, Nicolaus & Co., Inc.: Just a couple of quick questions. Just you had mentioned you've got some disposal facilities in place for at least as your volumes ramps up. But you doubled your rig count, is there the constraints in terms from the frac-ing or anything else that you see as that you had in this fall? Pipeline takeaway?

Well, that's s -- everything we're working on today is preparing for that higher rig count in 2012. So we think that we'll have ample availability of services. Amir Arif - Stifel, Nicolaus & Co., Inc.: Okay. And then I think you had mentioned that you'll only be able to hold about half your acreage. Is that based on the current rate of 12 rigs or is that even after you double up to 24 rigs?

No, that was at current rate of 12 rigs. That's why we're moving forward with a plan to capture more than that. Amir Arif - Stifel, Nicolaus & Co., Inc.: Okay. And the 5,300 barrels a day number that you mentioned, is that the exit rate for Q1?

I'm sorry, what?

The 5,300 barrels a day. Amir Arif - Stifel, Nicolaus & Co., Inc.: Barrels a day for the Mississippian.

That's not exit rate for Q1. That is, the 5,300 barrels? No? No?

No.

Oh, I'm sorry. That's correct. Amir Arif - Stifel, Nicolaus & Co., Inc.: So that's the current rate? Okay, good. And do you have -- or can give us a breakdown of how much of that was for the trust versus...

I'm sorry, how much of that was what? Amir Arif - Stifel, Nicolaus & Co., Inc.: Was for the trust versus for SandRidge?

Yes. The trust -- yes ,it looks like the trust's projection -- its right around 3,300 barrels.

I'm just saying let us....

So it looks like about 60% of that was trust. Keep in mind that when we did the trust, we had 37 PDP wells, and they all went into the trust. Amir Arif - Stifel, Nicolaus & Co., Inc.: Yes.

And so we just started over on the drilling. Amir Arif - Stifel, Nicolaus & Co., Inc.: Yes. Okay. And then as you ramp up to 130 wells for the year, do you have a rough estimate of where you think your exit rate could be for the year on the Mississippian?

No, we just talk about exit rate company-wide. We don't want to give it out play-by-play. Amir Arif - Stifel, Nicolaus & Co., Inc.: Play-by-play, okay. Well, for the full year oil guidance, can you give us sense of how much of that is Mississippian? It's not the exit rate, it's just the full year guidance, right, for them.

No. Again, we're not going to talk into details about play-by-play. We still look to produce 12.3 million barrels of liquids equivalent this year. And then the only 2 areas we're drilling is in the Permian and the Miss. So that's where your contributions are. Amir Arif - Stifel, Nicolaus & Co., Inc.: Okay, perfect.

Our next question comes from Joseph Stewart with KeyBanc Capital Markets.

Hey, Tom, just one question for me. Could you talk about some of your thoughts on timing for the potential JV given Chesapeake's announcement this week. Just considering their expertise in the JV arena? Do you think it might be better to wait for their potential deal to kind of set a floor on future bids?

Well, that would assume that we're preparing to do a JV. We are just looking right now at potential partners, and we've had some conversations. But there -- right now, we don't know which may we'll go. So I think in the next few weeks, you'll be able to see which way or ways that we're looking at. So I guess that the easy answer is to say that I'm not sure that we would want to time our proposal around a JV to wait on someone else assuming that they would get theirs done at a time that fits us. Because we want to fully fund our 2012 budget this year and not sure that that's their plan. So no, I don't think we would wait.

Okay, great.

And our next question comes from Duane Grubert with Susquehanna Financial.

Yes, Tom in terms of the rig count, you're already at an aggressive activity level, and you benefit from having your own rigs. Can you talk to us about how you think through whether you should actually purchase more physical rigs?

Well, we haven't purchased any rigs over the last few years because of the number we had. That doesn't mean that we wouldn't look to purchase rigs in the future if they were the kind of rigs that we needed to have to sustain a play. So the only way I would look at it is to say that if for us to purchase rigs would mean that if that were the way for us to guarantee that we can move forward with our plan to drill, then that'd be something we look at. But if there's sample rigs to lease and we don't think that there's any going to be a call on those rigs, then no, we wouldn't necessarily look to that to be our favorite way to drill. So I think we would leave it open.

Okay. And a related question. With some operators also vertically integrating all the way through frac equipment, have you thought about building out frac fleets given the multiyear run likely of a frac program in Oklahoma?

No, we're still not seeing any issue with low-pressure frac-ing. And just to remember that we are different and that the backbone of the U.S. gas industry over the last 4, 5 decades has been on drilling 8,000- to 10,000-foot vertical wells using small equipment. And that equipment is still available, just not all of it in use. So we prepared a slide actually that shows how limited the rig usage is in small rigs, and that's still the way it is today. But we just assume that there's going to be activity on the rig side that might take away some of the higher end of the 1,000-horsepower rigs out of the small market. And so that's the one thing we're most concerned about, not about frac fleets.

And then on road and type or line type infrastructure, do you have any cycle time differences from one area to the other in that? And some of your stuff is a leasehold that seems to be fairly remote.

In the Mid-Continent.

Yes. I mean, in the Mississippian specifically.

No. Well, actually, not in either one, no. Our lead times for digging wells have been very quick just because there's ample systems in place throughout the play. Now we might have one well or one well stranded out that takes a few weeks. But all in all, we bring on wells within 21 days after we're through drilling.

And finally, on the intent to double your rig count, does that require changing your personnel quite a bit? Or what's the capacity to execute relative to that plan that you have installed right now?

No, we have enough people to be able to execute the play.

Very good.

That doesn't mean we don't continue to hire. But that's -- we can't do that here.

And our next question comes from Philip Dodge with Tuohy Brothers Investments.

Could you talk about the ramp-up in the Miss rig count to 24 in terms of what it might average for 2012?

That's what we believe we will average in 2012.

Average 24 in 2012? Okay. And then what effect you see that having, Tom, on the production incline when you get to 24?

Oh, we don't give guidance out that far. But that is basically doubling what our production incline is today.

Okay. So yes, that's helpful. Appreciate the comments.

And our next question comes from Dan Morrison with KKR.

It's actually Global Hunter Securities...

Yes.

Not KKR. How do you look at allocating capital between the Mississippian and the Permian? Is there, I mean, obviously, one source of seed capital is to dial back in the Permian again so that you can ramp up in the Mississippian.

They're both about the same. If you look at our rates of return, both of the plays are extraordinary. In the Permian, it's just -- we have HBP acreage. But up until -- if you're looking out to 2012, we're more like 50-50 on allocating resources. This year, we've been more allocated towards the Permian, and I think that's -- we want to continue with both plays. And that's -- my thought is, is that our company wants to drill more and lock in very high rates of return. So that's -- we want to be able to drill and maximize as much we can. In the Permian at 16 rigs and drilling 811 wells, it's hard for us to ramp that number up logistically. We might be able to a little bit. But in the Mid-Continent, it's much easier where you have a larger area to deal with and you do have a leasehold that you have to cover.

And our next question comes from Stephen Caven, a private investor.

I was wondering because EPS missed this quarter.

If you're talking about our $0.02 loss versus the Street, I would say 2 things, that I think people were projecting production probably to flatline throughout the year instead of ramping like we had. We ended the year at fourth quarter with production of 62,400 barrel of oil equivalent, and we sold about 3,000 -- over 3,000 barrel of oil equivalent a day and then we're ramping from there. So I attribute it solely to people projecting the production flat rather than ramping throughout the year.

And so you would say that this is temporary?

I'm not sure what you mean by temporary. I'll say it this way. We don't -- we thought this was a good quarter. We don't really consider it a miss, the fact that people were guiding a little bit higher. We're actually right on track with our plan for this year.

And our next question comes from Noel Parks with Ladenburg Thalmann. Noel Parks - Ladenburg Thalmann & Co. Inc.: Just a couple of questions. And sorry if this was mentioned earlier and I happened to miss it. In the Central Basin Platform, especially thinking about the former Reno [ph] properties at Fuhrman-Mascho,, can you just talk a little bit about how down spacing has been going out there?

Yes, down space. When we talk about down space, we're talking about 5-acre spacing. And in fact, it's going very, very well. We drill 199 wells in the first quarter in the Permian Basin, and roughly 125 wells were Fuhrman-Mascho, of which about 80 of them were 5-acre wells. And they're coming in right at our type curve projection. So the down spacing is working well, and we have plenty more of those locations to drill. Noel Parks - Ladenburg Thalmann & Co. Inc.: Great. And going back into last year, one of the things that had been difficult about those properties out there were some various infrastructure issues, thinking about electricity and so forth. Have those been totally resolved at this point? Or I was wondering, with the weather and wildfires out there, if there are any new challenges that had come up on those?

Yes. I don't know if they're totally resolved. I would say they were substantially resolved. We have not had a downtime this year even with the severe freezing and the wildfires that Arena had experienced a year before just due to infrastructure. I think we've built a couple of our own substations, and that has given us the ability to restore electricity very quickly anytime we have a power outage. And we've worked with our processes very well out there. We've had very little plant downtime, compression downtimes. I think things are going very well, and the steps that we've taken operationally to improve the run time has worked out well for us. Noel Parks - Ladenburg Thalmann & Co. Inc.: Great. And one question on the Mississippian. You talked about the economics in general and just thinking that we now have the luxury of oil prices in or around $100 for a few weeks to months now. When you think about the tail of the production curve when you make the ROR calculation, can you just give us a sense for the reserve life, kind of, I guess, how to think of the reserve life, at sort of a more modest commodity price environment, like, say, we're back looking at the $70 range for long-term prices?

Sure. We show a slide in our presentation that at, I believe it's at $60 oil, we still have a 40% rate of return in the Mississippian play. And so It's really all about costs. As you can control costs and be able to produce oil and lock in that oil at high prices, so we're locking in oil so we're between $90 and $105, there really shouldn't be any issue with the company going forward. So it's very simple strategy, is if you believe that service costs aren't going to go up, and you believe that you're finding your type curve on your production, you should hedge it and have some of the highest rates of return I've ever seen in my career. Noel Parks - Ladenburg Thalmann & Co. Inc.: Okay, great.

Our next question comes from Mike Breard with Hodges.

I was given the news this morning. Just one quick question. Is Occidental putting any pressure on you at all to produce more CO2 for their tertiary recovery?

Well, no. Well, there's no pressure for us. I think that Oxy and us look at this as a very long-term project, and I can't speak for them. But as of today, it doesn't make very much sense for us to drill gas wells. So we're looking forward to the time that it does for us or someone else to be able to drill in the Pinon Field.

And our next question comes from Thomas Ciccarillo [ph] with Commerce One Financial.

Yes, my question is for the derivatives contract. I noticed in your release that the realized impact per barrel had a negative impact of $7.50. And then in the adjusted earnings, there was a realized gain from out-of-period derivative contracts settlements. I was just wondering how that was -- how you arrived at that with the out-of-period versus the loss within the period.

Sure. That was -- the out-of-period is covering some natural gas hedges on, I believe, it's 42 Bcf of gas during the period. And our belief is that $4 gas prompt that -- that, that signifies that it may be not the low, but the risk-reward past that point is negligible. And we decided to take off the gas hedges during the quarter. So that was what the out-of-contract derivative gain was.

Okay.

Yes. In the period, that's simply the difference between our hedges, which were at about $87 a barrel, but they're probably closer to $100.

And there are no further questions at the time. I'll now turn it to Tom Ward, Chief Executive Officer, for closing.

Thank you, and thanks, everybody, for joining us. So we look forward to seeing you or talking to you in the quarters to come. Thank you very much.