Good day, ladies and gentlemen. Welcome to Halcon Resources Fourth Quarter and Full Year 2012 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded. I would now like to hand the conference over to Mr. Floyd Wilson, Chairman and Chief Executive Officer.

Good morning, and thanks for joining us today. This conference call contains forward-looking statement intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. For a detailed description of our disclaimer, see our earnings release issued this morning. We were busy during 2012 building this oil company. Today our focus is on developing our resource base and growing production reserves and cash flow. The balance sheet is healthy, and we are well positioned to execute our business plan. Currently we have 15 operated rigs running around our holdings, and we expect to add several more by year-end. Also we have 27 wells being completed or waiting on completion across the company. This will greatly add to our production base. We anticipate new well results from all of our core plays on a regular basis from this point forward, and operations are going quite well. The Bakken/Three Forks, one of our anchor plays, contributed approximately 50% of pro forma production in the fourth quarter of last year and accounts for approximately 45% of total proved reserves. We own over 130,000 net acres in the Williston Basin. This year and next we’ll spend the majority of our drilling and completion budget on the highest IRR locations, signifying that lease capture is essentially behind us. There are a number of drilling and completion modifications being implemented to improve the overall economics of the wells we’re drilling in the Williston Basin. On the drilling side we have begun full-scale pad drilling, including the addition of highly efficient skid capable drilling rigs. In conjunction with pad drilling, we are presetting surface casing on wells, on all the wells that’ll be drilled on the pad. We’ll implement batch drilling on intermediate and production intervals. We’ve modified our motor…

Okay. Thank you, Floyd. I’ll start the financial review with a look at fourth quarter and the full year results compare to guidance. Production for the three months ended December 31, of 2012 were 18,348 barrels of oil equivalent a day, which falls right in line with our guidance range of 17,000 to 20,000 barrels a day. And I’ll note that if you include the production that was divested out in South Louisiana then also adjusted for some gas flaring in the Bakken or fourth quarter and net daily production would just under 19,000 barrels a day. For the full year 2012 we produced 9,404 barrels of oil equivalent which compares to guidance that was between 9,000 and 11,000 barrels a day. And on the cost side, LOE for the year came in at $14.36 per Boe, if you exclude a non-recurring item that was included this year. And that was within our guidance range that was between $11 and $15 dollars per Boe. Taxes other than income came in at $5.59, which was slightly higher than guidance due to among other items, more production from North Dakota where production taxes are higher than some of our other operating areas. Cash G&A expense was $15.81 per Boe excluding some non-recurring items related to a lot of the activities that we’ve had this year, whether it be capital raises or merger activities. And that is slightly above the range of $11 to $15 per Boe. Also in G&A, we continue to build out office space for the company while we continue to build a pump in technical in the operational employee base here at Halcon. From a capital investment perspective, the company spent $758 million on lease hold acquisitions, $398 million on drilling and completion and $197 million on the infrastructure…

Thanks, Mark. This year will be just as busy as last for us here at Halcon. As I mentioned, our goal will, continues to be to grow production reserves and cash flow. Importantly though, while de-risking hundreds of thousands of acres, our portfolio management process has begun and we look to divest certain assets as production ramps up in our core areas. Information flow will increase substantially from us now that our core areas are all in development mode. Operator, we’re ready for questions if there are any.

Thank you. (Operator Instructions) Our first question comes from Leo Mariani of RBC. Leo Mariani – RBC: Hey, guys. Just curious, in terms of some of the other plays that you didn’t really mention, anything happening in the Mississippian, the Midway-Navarro or the Wilcox of late?

Yeah, Leo. The Mississippi line continues to be a hit and miss proposition for us, as I’ve mentioned before. A couple of good wells, a couple of bad wells and a mediocre well. We continue to evaluate our position there. We may drill a few more wells. It’s not a big piece of our budget by any means, last year or this year. Cat Springs area, the Midway-Navarro, we’re waiting on a 3D seismic to see if we can expand the footprint and afford to drill another well there. That’s coming out in the next month or so. The Wilcox, our activity down there has really picked. We’re just embarking as speak, on a four well drilling program and we’ll follow that up with some more wells later in the year. We own quite a lot of acreage down there. We’ve got a lot of seismic in hand now. It’s going to be a significant cash flow device for us later this year. Leo Mariani – RBC: All right, that’s helpful. And I guess, any update on what your plans are for the Eagle Ford?

The Eagle Ford divestiture down in Fayette and Gonzales County, the process is continuing and we’re just allowing the potential buyers to do their work. Leo Mariani – RBC: Okay, and I guess in the Woodbine, obviously, you guys have had some pretty good results this quarter with the drill bed. I think you’re up to somewhere around 235,000 acres at this point. I’m just trying to get a sense of how much that acreage do you guys feel has been de-risked from the drill bed, either by yourselves or by industry at this point?

Leo, it’s hard to put an exact number on that. There’s so many pay zones in the area. Clearly, the northern tranche of our acreage and the western tranche has been de-risked. That’s probably somewhat less than half of the acreage. Polk County has not been de-risked yet and neither has Madison County, the heart of Madison County. It might be 40 de-risked, 60 still waiting on the drill bit to de-risk but those are very round numbers. Leo Mariani – RBC: All right. That’s helpful. Thanks.

Thank you. Our next question comes from Brian Singer from Goldman Sachs. Brian Singer – Goldman Sachs: Thank you. Good morning. I wanted to see if you could touch on production guidance, if 40,000 BOE to 45,000 BOE a day still applies, what the trajectory of that might look like? And how important the Woodbine is as a percent of total, the total actual production for the year?

Brian, we, as we do every year, we continually evaluate our production guidance, which we’re in the midst of doing right now. If we decide there’s a reason to adjust that we’ll announce that. We haven’t given out a quarter by quarter analysis of that yet. We will do so sometime in the future. And we certainly haven’t given out an area by area breakdown of where that’s coming from. I think you should expect that the way that the budget is directed is sort of the way that production will come, though. Brian Singer – Goldman Sachs: Great. Thanks. And then do you see yourselves making additional acquisitions or asset sales beyond the potential Eagle Ford sale or the assets that we see here are the assets that we’ll probably get for this year?

Yeah, two separate subjects. On the acquisition side, we don’t have anything on the radar screen right now. We continue to be active lookers in our core areas for sure. On the divestiture side, we certainly have a significant group of properties that we intend to divest over time. They’re all good properties so there’s no rush for us. We’re going to guess we’ll do some divesting every year. This year and the next couple of years. Brian Singer – Goldman Sachs: Thanks. And if I could ask just one more, and this may be a little too early, but can you just put into context, if you can, what you have seen in the Utica from the shows in your wells and now I remember a couple of them are resting, and then what you’ve interpreted from some of the other operators in terms of the ability to target fracs and the extent of the wet gas or oily zone?

Yeah, I don’t think our research tells us we’re targeting fracs up there. Fractures in the formation. It’s a pretty quiet area. It’s pretty evenly dispersed. Our early stage data there tells us that we’re extremely pleased with where our lands are and with the content of the rock and the rock properties and what not. We’re just starting a soaking idea that seems to be so effective as you know just put it a little more delay in our results there. We’ll be releasing, we’ll be having results in April on our first two wells and the we’ll have results every month after that. Brian Singer – Goldman Sachs: Great. Thank you.

Thank you. Our next question comes from Neil Dingmann from SunTrust. (Operator Instructions) Neil Dingmann – SunTrust: Morning, Floyd. A question on your Bakken area, either in that Fort Berthol area or the Mormon area, trying to get an idea or a sense of, when you look at the middle Bakken or Three Forks locations, just an idea of what you plan on drilling, kind of through the remainder of this year. I mean is there still ample middle Bakken locations or will it be mostly Three Forks?

We have literally hundreds of middle Bakken locations to drill. And a lot of Three Forks locations to drill. Since the lease capture is essentially done up there we’re able to take all of our rigs and put them down on the in the Fort Berthol area and drill the very best of the best, first, and then we’ll, as we go about fine tuning our drilling and completion practices and as we branch out to the other areas we would hope to be able to improve results. And those are the other areas to make them competitive with the, sort of the core of the play. But for this year and next, our plans are focus right in the middle of the play and drill Three Forks and Bakken wells. Neil Dingmann – SunTrust: Interesting. And then, Floyd, either in that area, or even your Woodbine can you give us a sense of how big can you services this area? It looks like you’re certainly building that out like you did in prior company rather quickly. Try and give me a sense of how big that is now and how big that can be, maybe by year-end?

Are you talking about infrastructure? Neil Dingmann – SunTrust: Yes, sir.

Yeah, in the Bakken, it’s fairly mature up there, although this gas flaring business would tell you that it, there’s some lacking up there. We’re trying to utilize the services that are in place up there to a large extent. That’s going to be the quickest path towards getting our oil on, in pipe. So that during the mud season we’re not curtailed. And getting our gas flowing at pressures that can overcome the line pressures. And get all the saltwater production in pipe as well so that we’re not hauling any water. So some of the saltwater we’re doing ourselves. We’re trying to work with others on the natural gas and the oil piping. In the Woodbine we’re building our own system period. And it looks like it could end up being pretty lucrative. As you go to the south in the play, there’s a little more gas and a little more natural gas liquids, and there’s not a good market for rich gas in that area, so you make money by processing your gas. So, we’re going about setting our first processing plant down there right now. And it’s going to be an extensive system. It’ll be, I don’t know how many miles of pipe we anticipate, but we’re going to try to service all of our own wells with our own systems down there. It’ll be extensive. Neil Dingmann – SunTrust: Okay. And Floyd, staying with that Woodbine, just wondering, will you continue – is your thoughts are that the Brazos County wells, kind of like this last quarter you just reported, wells would be a little bit better there than what we’re seeing in, I know Polk you don’t, you mentioned you don’t know yet, but will the Brazos be likely better than Leon and Madison?

Actually the Leon County wells are among the best in the whole play and in the heart of that we’re clearly getting some wells in the 600,000 to 700,000 barrel range with our average well being in the 500,000 to 600,000 barrel range equivalent, mainly oil. I think 90% or 92% oil or something. So those – the Leon County wells are very good. We have drilled, there’s sort of a geologic feature up there, we drilled the edge of it and now we’re setting about drilling the core. So we do have a few smaller wells around the edge as we define the edge, as we typically try to do here. Brazos County, it’s going great over there. Madison County, we haven’t quite cracked the code, we’re waiting for some 3D seismic to see if that could help us avoid some hazards while drilling, faults and what not. So we’re still working that, but we don’t have very much of our budget for this year programmed for that area. Most of the budget’s heading for our Leon and Brazos County. Neil Dingmann – SunTrust: Got it. And the last one, if I could, just a little bit further on, on Brian’s question on the Utica. I know it’s early, but I know the thoughts are, just kind of what your thoughts what up there as far as pressure, or any comments you can make. I know there was early expectation that maybe the pressure wasn’t as good up there, but range said otherwise yesterday. So just wondering maybe any thoughts you had around that?

Listen, we’ve seen that the pressure regime up there is just what we expected it to be and we’re looking for a very, this reservoir is very energetic and again, we’re trying, as best we can, we’re trying to target that transition zone as you go from wet gas towards oil, as we’ve done in the past in certain other plays and I guess, time will tell on that. But we don’t have concerns over pressure. We found the appropriate amount of thickness in our first several wells that we’ve drilled. So we just have to get these wells on production and see what they do. Neil Dingmann – SunTrust: Got it. That’s a great update. Thanks, Floyd.

Thank you. And our next question comes from Jason Wangler from Wunderlich Securities. Jason Wangler – Wunderlich Securities: Morning. Just curious, in the Utica obviously you’ve got the two wells resting and a couple more waiting on completion. When do you think that you’d be able to get them on the sales? I know you’re working on the service part of it in the Midstream. Do you think you’ll be able to hook those up relatively soon after getting them tested? Or will that all be second half events?

Actually, if I just look at our first about half of the year drilling, we’ll drill ten or 11 wells or maybe even 12. But we’ll get ten – at least ten wells drilled by the middle of the year. We expect to have the majority of those all on pipe. So we’re working on that as we speak, at that same time. So we’ll have a few wells that’ll be waiting on infrastructure. And the main reason they’d be waiting on infrastructure, waiting to see what sort of production mix we have so we can size facilities. It’s very inefficient to run out and put in a giant facility for condensate or NGLs when you don’t quite have that production mix. So we’re trying to be judicious with the placement of our infrastructure dollars as best we can. But also trying not to delay production. So we’ll have the majority of our wells online as we drill them. Jason Wangler – Wunderlich Securities: Okay. I mean that obviously makes sense as far as putting what you need out there. And as far as – is the plan at least to kind of, as you get a couple of wells down or ten or 11, are the wells going to be pretty close together in terms of as you build that Midstream out that there won’t be large steps that you have to take out to get there? Will it be once a lot of the Midstream is in, you’ll be able to really start hooking up wells pretty quickly as you drill them? Or are you going to be kind of stepping out, like you said, delineating further out where we may have to wait a little while before we get those done?

Actually, you can go on our website and we have a map. And it shows that are wells are shockingly far apart, which speaks to our confidence in the reservoir and our research. Each specific area has a little different pathway for egress for the products and we’re working each one in that way. It may be that over time 60% or 70% of our acreage will get hooked up in one system and we’re building it with that in mind as a possibility. But the main thing we’re focused on is getting our gas to the best gas market and getting it processed before it gets to that market so we’re not giving away too much. And also, so the pipeline can take the gas. So... Jason Wangler – Wunderlich Securities: Okay. So – sorry. Go ahead.

We have some experience at this, and we’re sort of planning for two or three different outcomes in every area and we’ll be basically fast on our feet as events unfold. Jason Wangler – Wunderlich Securities: Sure so it’s more of a work in progress as well as far as which wells will go to what system. And you’ll hook those up as you see the best way?

Yeah, if you look at that map I mentioned, you’ll see there’s sort of three basic concentrations of acreage. And so each one will have their own sort of solution. The two that are more to the West we may end up hooking them up. There’s a good pathway to do that, if it makes sense. Probably the one that’s more to the East will always stay a separate system. Jason Wangler – Wunderlich Securities: Okay. That’s helpful. Thank you.

Thank you. And our next question comes from Ron Mills from Johnson Rice. Ron Mills – Johnson Rice: Floyd, a question on the, you talked about the Bakken and the drilling and completion enhancements you hope can drive 20% to 25% EUR increases and a similar amount of cost decreases. Is that something, are those metrics pretty similar to what you would hope to be able to achieve in the Woodbine as you refine the drilling and completion methods versus the prior operators of your wells?

Actually the Bakken area is so much more mature. The Woodbine area probably offers more opportunities for improvements over the first set of drilled wells than the Bakken does. In the Woodbine we’re still feeling our way through where you can afford to skip intermediate casing and where you really need to put it down where there’s an area that’s, with some faulting or some loss circulation zones that give you trouble. So I think the opportunity over time as you really go into full development mode would be to improve the numbers in the Woodbine more than the early numbers in the Woodbine more, than we can improve the Bakken. In other words, a significant amount in either case. Ron Mills – Johnson Rice: Right. And then when I look at the initial results, particularly up in Leon County, the 30 day rates versus the IP rates and compare it to the curve in your presentation that seems to be right in the wheelhouse. Did I hear correctly that some of those wells were drilled more on the edge of a feature? And if so does that mean as you move to the more essential part of the feature that it will also help drive even better performance?

We typically try to, early on, establish the boundaries of any of the production areas at Halcon and in our prior companies. It pays off in terms of planning. We’ve done that here. We’re doing it in Utica. We’ve done it in the Bakken already. Yeah, we drilled some wells that would be right on the edge of our map, best part of the field and those wells came in about like we might have expected, but you have to drill them, and the core of this area hasn’t even been drilled yet. We’re just embarking on our, I just find AFVs in the last couple of weeks in our first few wells right in the middle. We had some lingering curative issues on title and complaining issues and what not. So we certainly don’t expect our averages to go down in that area. They might go up, but I can’t really project that yet. We are in a position to drill longer laterals in part of the field than we have been here before. I think I signed an AFV for an 8,000 foot lateral just this week. So typically in these plays that’s a good thing for increased efficiency of your capital expense. Ron Mills – Johnson Rice: And you talked about most of your activity being in Leon and Brazos. Of the 70 to 80 wells you expect to drill in that area, do you have a break out of Leon versus Brazos versus the central Madison/Polk area?

We do, but we’re not saying. We’re still leasing and making deals here and there. Ron Mills – Johnson Rice: Okay, and just one more on the Utica, if I may be – one of the things that I know Range talked about happens in all these places, determining the best place for the lateral. It sounds like a lot of the operators up there are sharing information. Do you know in terms of the lateral placement of your initial slate of wells versus where ranges was or what characteristics you’re looking for in determining the lateral placement?

Well, I’m staring at those well board diagrams as we speak, and know exactly where they place their laterals and we placed ours. Keep in mind that we’ve always been at the forefront of these information sharing contortions. We’ve actually tried to originate those in several areas, including the Utica. Also keep in mind that Range is a very experienced driller of horizontal wells in these formations up in the Northeast part of the United States, and whatever they said on their call or in their press release, I would take it to the bank. If they said they needed to position it a little bit differently, I’d accept that totally because they’ve drilled, I don’t know, thousands of wells up here. Ron Mills – Johnson Rice: Okay, and then Mark, you talked about the production profile matching the CapEx profile, if we look at your, call it $1.2 billion plus or minus, drilling budget, how is that staggered through the year? Or is it pretty flat throughout the year?

Yeah, first off, Ron, that’s a rough approximation. The Utica is way back end loaded in terms of production response because of the soaking time and all of that. So a lot of that will carry over into 2014. However, I think that it’s roughly accurate. There was another part to your question, what was that? Ron Mills – Johnson Rice: It was just, I was just curious, you had talked about the production profile somewhat tracking the CapEx and I was just curious how the CapEx budget looks as you move through the year. It seems like you’re adding a couple rigs here and there in all the plays, but I was just curious if there was any particular quarter that was more heavily weighted or more flat?

Yeah, Ron, the third and the fourth quarter are going to be more heavily weighted than the first two. Ron Mills – Johnson Rice: Okay. Perfect, thank you.

Thank you. Our next question comes from Steve Berman of Canaccord. Steve Berman – Canaccord: Thanks, good morning. Just one question in the Williston, Floyd, on the 25% targeted cost reduction. Can you put that in perspective to the $10 million costs you’ve had in your presentation and maybe talk about how costs are running in the different areas for, Mormon, New Home, Montana.

Yeah, Steve, everyone knows I’m full of crap, right? So I’ve actually got people here at the company that are putting pen to these sorts of calculations as we speak. A lot of it involves the efficiencies gained through pad drilling. Those are enormous and they can be $1 million or $2 million per well, depending on where you are. You’re not moving most of your equipment, you’re not having to move pits so much, there’s just huge savings with pad drilling. I think that’s a goal that I hope we’ll achieve. We certainly haven’t got there yet, but on paper, we can get and it would be about the same on the cost side in all of the southern parts of our holdings, and not quite as much on the cost side in the northern parts, that being up in Williams County. But in Williams County it seems like there might be a chance for enhancements in productivity with different style completions, maybe some ceramic up there which we have tried on two wells so far that I know about and had decent results. So those are lofty goals but I think they’re – we wouldn’t talk about if we didn’t think they were feasible. Steve Berman – Canaccord: But is it over simplifying to think that you’re can bring cost down 25% from the $10 million? Or is it 25% from where they’re running now? Maybe some are higher than $10 million, some might be lower? Just trying to put that 25% into perspective relative to the $10 million.

Look, up in the north end of the play the costs are between $7 million and $8 million in a general sense. In the south end they’ve been running between $10 million and $11 million. I think the 25% is the goal off of those numbers. Steve Berman – Canaccord: Okay. No, that’s helpful. One other quick question. On the South Louisiana divestiture, was that something that was kind of reactive or proactive? Was it something you looked to do? Or did someone come to you? Maybe put a little perspective on that.

Hey Steve, this is Steve Herod. That was a property that was part of the GeoResources acquisition, and it was a non-op that we sold to the operator. Steve Berman – Canaccord: Got you. All right. Thank you, guys.

Thank you. Our next question comes from Jeff Robertson from Barclays. Jeff Robertson – Barclays: Thanks. Floyd, in terms of some of the efficiency gains you all are trying to achieve, are any of those potential savings or maybe production enhancements factored into the capital budget you talked about?

No. Not yet. Jeff Robertson – Barclays: Okay. So there’s a chance, depending on when they come, that you may be able to get a little bit more done for the dollars you spend?

Yeah. You can think of this theory pretty easily: If the improvements on cost, a lot of it’s on the drilling side, and as you end up drilling more wells you have more frac jobs so you don’t really spend less money. If the improvements are on the completion side that’s a net, net improvement because it doesn’t increase your rig – your drilling usage. One of the improvements has been just the fact that some dated frac contracts are just now running out, contracts that were signed a few years ago. In order just to get frac equipment into the area, frac jobs running $4 million back then are just a little bit more than half of that today. So there’s a whole smorgasbord of improvements and enhancements that we’re working on and we think all of these taken together give us a pretty beefy target to focus on in both production and reserves. And nothing, taking nothing away from the prior owners, it’s just a matter of the evolution of how these fields go and basically when you get away from the lease capture period, your planning takes on a whole different aspect. Jeff Robertson – Barclays: And then are there any similarities, Floyd, between the, your main three core plays, at least as they are today in terms of technology transfer? Are there any similarities enough in the reservoirs, that you can, if you learn something up in North Dakota, for example, you can export that to the other areas?

Well I tell you they’re quite, they’re really quite different. You do learn a lot just drilling horizontal wells and doing hydraulic fracturing in stages. And that certainly is transferrable. But the zones are so different. The Bakken, Charles, it’s a limey, sandy...

Dolomitic sandstone

Dolomitic sandstone. The Three Forks, it’s more of a...

That’s more of a shale play.

More shale. Woodbine’s a sandstone.

They’re all different.

The Utica – the shale. Probably a little bit more like the Eagle Ford than any one of those plays. So yeah, we learn a lot but they’re, it’s really a good question, and I don’t want to labor over it but, because of the differences in these areas we have business units that run each area that have their own technical staffing, all the way from geoscience down to completions and production engineering. And it’s really important that they focus on their area. We do get together and trade results and what not on a regular basis but we have to handle these quite differently. You’ve got different service companies and suppliers in each area. You’ve got different products that you need. You’ve got different weather patterns. Different regulatory environments. So we really have to run these as business units, so as such, each one is staffed independently in sort of a self-contained way. Jeff Robertson – Barclays: Thank you.

Thank you. Our next question comes from James Spicer from Wells Fargo. James Spicer – Wells Fargo: Hi, good morning. Given that you didn’t get the full quarter of Petro-Hunt contribution, can you provide us with the exit rate for the quarter and how much of that came from Petro-Hunt.

I’m trying to think. I think our exit rate was about what we said it was when we closed the deal, about 25,000 barrels a day. It was about, I think it was, how much was that gas?

About 15%.

15% gas, 80% oil and 5% NGL. That’s the exit rate for 2012. James Spicer – Wells Fargo: That’s helpful, thank you. And then, on the Field Services business, can you give us any sense as to how fast that’s growing, for the year? And just in terms of maybe cash flow contribution, thinking about the size and scale and value of that business embedded within Halcon?

The cash flow contribution is a negative contribution in the early days of that kind of business. You’re way out in front of the gathering fees or the processing fees that you collect from the wells. The real key there is the speed of hook up and the speed of getting your produced products out of a local market into perhaps, the more attractive market. So those are early stage goals. And then just as part of the process, and because of the way that the business is set up today, that ends up being a very valuable part of your business, as it has with us in the past. And it gives us a lot of flexibility in terms of financing. So in a simplistic sense, in the early year or so of these infrastructure build outs, the financing is just piggy backed off of our main credit line. And then, about a year into it, we’re far enough along to establish a separate stand alone credit line. And then another year few months or year and we’re into the position where we can exhibit future EBITDA and think of even different ways to finance that expense. We’re building out very large systems in the Utica and the Woodbine as we’ve done in a couple of our plays in the past and we expect those to be extremely valuable systems to us, or to anyone else. James Spicer – Wells Fargo: Okay, that’s helpful color. Thank you.

Thank you. Our next question comes from Chad Maybury from KLR Group. Chad Maybury – KLR Group: Thanks, good morning. A quick question on the Tuscaloosa Marine Shale. You commented in your earnings release that the zone was too thin for commercial production, can you expand on that? Maybe comment on what kind of thickness you encountered in the LandBright compared to the Broadway, and maybe how that’s influenced your leasing strategy?

Sure, in fact, Charles is sitting right here. He can give you the good answer on that.

Well, it’s quite a bit – it’s thinner than the Broadway and there’s pay there, but we just deemed it to be non-commercial pay.

It’s about 40.

It’s plus or minus 40 feet of pay, and there are some wells off not too far from that to the left of that, that look similar too. It was a little surprising to us, but it’s not unreasonable. Chad Maybury – KLR Group: And the Broadway had about how many feet?

Broadway’s over about 120 feet. I mean it looks like it should look. Chad Maybury – KLR Group: That’s great. Thanks, and then I guess to expand on that, have you entered into any data-sharing agreements with other operators in the play, and are you continuing to lease?

Yes, we have, like we do in all of our plays? Chad Maybury – KLR Group: Okay, great. I appreciate it, guys. Thanks.

Thank you. Our next question comes from Eliot Javanmardi from Capital One. Eliot Javanmardi – Capital One: Good morning, guys. I think you’ve in a way answered this question, but just for verification I wanted to know with the wells that were released, those results in the Woodbine this morning in your release, were those all taken into account and established 562,000 barrel equivalent type curve?

The 562 type curve that we published is for Leon County. We actually have different type curves for different areas. I think over in Brazos County we have about a 450,000 type curve. So there’s clearly a mixture in there. The great news is the that the wells come on and much the same way in terms of 30 day IPs, and the EUR is sort of the tail of the dog. The early couple of years of production is the dog itself, and that defines how well your well pays out, and so on and so forth. It really defines the economic success or unsuccess of a well, is that IP and how long it lasts before it gets into its sort of steady state terminal decline. Eliot Javanmardi – Capital One: Excellent. Okay, and that answers the question and just a follow-up then on the TMS. You talked about well costs being reduced and any idea where you kind of want to land there, where you expect you could land versus where you are today with well costs?

Well, the interesting thing there, and there’s always some data to be gleaned from anything you do. The dry hole that we drilled, the Strat test, we got down to the point of kick off and had it logged for less than $4 million. You could extract like from that a well that would run $10 million or less if you didn’t have any trouble in the well, but we didn’t have any trouble in that well. So it’s a great sign that’s within our own set of data that tells us that the costs are going to come down in the play for all the operators, and of course we had discussions with others and they’re all feeling the same way. Eliot Javanmardi – Capital One: That’s very helpful. Thank you.

Thank you. Our next question comes from Mike Kelly from Global Hunter Securities. Mike Kelly – Global Hunter Securities: Thanks. Good morning. Was hoping you could give us a range for what the 2013 leasing budget should look like.

A range of what? Mike Kelly – Global Hunter Securities: The CapEx for the leasing budget in 2013.

Yeah. We haven’t published that, and we’re not going to. We’ll report the exact numbers each quarter as we go. We don’t have any huge leasing ambitions. We’re not running any half a million-acre land plays right now. Mike Kelly – Global Hunter Securities: Okay. Thanks. And then on the Woodbine correct me if I’m wrong here, not looking at something that’s really apples-to-apples. But the 388 BOE per day, 30-day rate, does look to be under what you set out for the first month expectations as part of that 562,000-type curve. And I just wanted to hear comments on that. Maybe it has to do with drilling some wells more on the fringe of your acre positions or if I’m just off on that.

I think that the 388 is the mathematical average across all the wells and the producers, and the type curve is what we expect to achieve on average in Leon County, that particular type curve. So yeah, there’s a little bit of a disconnect there. You would expect that the average across the – all the wells to – the IP rate, if we’re correct, would increase over time. If we just slivered out the wells in the heart of the field in Leon County the IP rates are 1,000 barrels a day. Mike Kelly – Global Hunter Securities: Okay. Maybe just how much acreage do you think you have kind of core Leon County?

It’s a lot. I forget how many. We’re planning on – we don’t really – and we haven’t really given out our exact acreage distribution anywhere, but we’ve got a lot of drilling up there for the next several years. We’re still leasing here and there. So we’re a little reticent to say exactly where we own. Mike Kelly – Global Hunter Securities: All right. Understood. Thanks.

Thank you. And I would like to hand the conference back over to Mr. Floyd Wilson for any closing remarks at this time.

Hey, thanks a lot for dialing in. If there’s something we didn’t cover, just give us a ring and we’ll be talking to you soon. Thanks.

Ladies and gentlemen, thank you for participating in today’s conference. This concludes the program. You may all disconnect and have a wonderful day.