Battalion Oil Corp (BATL) 2012 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Halcon Resources' fourth-quarter and full-year 2012 earnings conference call. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session, and instructions will be given at that time.

(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 statements 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. Operations are going quite well. The Bakken/Three Forks, one of our anchor plays, contributed approximately 50% in pro forma production in the fourth quarter of last year, and accounts for approximately 45% of total crude 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, and in conjunction with pad drilling, we are pre-setting surface casing on wells, on all the wells to be drilled on the pad. We'll implement batch drilling on intermediate and production intervals; we've modified our motor and bit configurations in the curves and laterals, and we're utilizing geosteering more in those laterals for better targeting. On the completion side, we have begun our optimization process. We've developed a petrophysical model to aid in optimizing our completions. We're increasing profit per stage to 120,000 pounds from 100,000 pounds, we changed the fluid design by going to a slightly lighter fluid, a lighter gel.

We've increased frac stage of density to 30 from 25, we've eliminated completions using -- utilizing blast joints in favor of completions utilizing swell packers or plug and perf-style completions. And we've incorporated frac strings in our completions for improved safety and flow back. Our goal in the Williston Basin is to increase recoveries by up to 25% while lowering costs by about that same amount. As referenced in the earnings release, we are currently flaring approximately 6 million cubic feet of gas per day in the Williston Basin due to infrastructure constraints. We expect to have a solution in place for most of this flaring by the end of this year.

In another of our core areas, the Woodbine in East Texas, our enthusiasm continues to grow. We are the most active operator in that play and we own approximately 235,000 net acres. We plan to spud between 70 and 80 wells this year there in East Texas, and we'll keep about 6 operated rigs running all year; we'll focus on our acreage in Leon, Madison and Brazus counties. We also expect to drill several wells in Polk County this year, an exciting area for us, the first of which will spud in the second quarter. We began modifying our Woodbine drilling completion techniques a few months ago, and the process continues today. Today, we have tightened the curve in all of our wells and eliminated intermediate casing in most, which results in a well cost reduction of over 15%.

Notably, we have drilled several Woodbine wells recently in this area in less than 20 days. We've increased the amount of profit placed while decreasing the total volume of fluid in -- and that allows an associated pump time that's less horsepower requirement. We also continue to adjust our cluster configuration and cluster count area by area. We're putting new wells on artificial lifts sooner than we did before, and initial results are encouraging. Looking ahead, we anticipate lifting costs to continue to decline as we exploit opportunities for batch drilling and as we bring in electric power to more of the area.

Up north, we'll have well results in Ohio and Pennsylvania soon. The first two wells will begin flow back in April with more wells following each and every month. We are in the process of delineating our 130,000 net acres in the Utica/Point Pleasant play. During the first half of this year, we'll drill 10 or 12 wells across our holdings in the play in this delineation exercise we're involved in. Currently, we have two wells resting after completion, we have two wells being completed and two wells being drilled. We remain highly confident that our research has pointed us in a good direction in this great new play.

Outgoing field services continues to identify and implement or plan infrastructure solutions in the Utica/Point Pleasant. Third party infrastructure solutions will be utilized, if available and competitive. However, consistent with our strategy, infrastructure ownership is our goal wherever practical, and a multimodal approach to transportation to the best markets is planned. A complete infrastructure solution in this complicated area is a year or more away; we're well down the road though towards that solution. Information flow out of the Tuscaloosa Marine Shale has picked up recently; well results continue to improve within the industry, longer laterals and enhanced completion designs are the reasons, and costs are coming down.

Our initial well in the Tuscaloosa Marine Shale, the Broadway 1H in Rapides Parish, Louisiana was drilled with a 5,200 foot lateral. Core and log reserves from this well are encouraging; the well is currently being completed, and we expect first production soon. Our second TMS well, the [Landbrite] in Rapides Parish was drilled as a vertical strat test. This well was located 16 miles northwest of the Broadway on the western-most edge of our lease area. At that location, the shale is too thin to be commercial. We'll react to production results from the Broadway in deciding where to drill next in the TMS. Mark Mize will now go through the financial results, and then we'll have a few minutes for questions.

Okay, thank you, Floyd. I'll start the financial review with a look at how 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. I will note that if you include the production that was divested out of the south of Louisiana, and then also adjusted for some gas flaring in the Bakken, our fourth quarter [commit] daily production would have been 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. On the cost side, LOE for the year came in at $14.36 per Boe, if you exclude a nonrecurring item that was included this year, and that was within our guidance range that was between $11 and $15 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 nonrecurring items related to a lot of the activities that we've had this year, whether it be capital race -- raises or merger activities. 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 upon the technical and 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 incompletion and $197 million on infrastructure and seismic. And additionally, Halcon invested $3 billion to fund a cash consideration for the GeoResources deal, the East Texas assets, Williston Basin asset and then a property deal earlier in the year at Utica/Point Pleasant.

Our 2013 drilling and completion budget is $1.2 billion, and you'll note that 90% of the budget is going to be spent on the core areas. Specifically, about $490 million will be directed toward the Woodbine, $475 million toward the Bakken/Three Forks and $200 million to the Utica/Point Pleasant. As Floyd had indicated, this past year was active operationally and from a financing perspective, as well. During the past year, we raised $2.7 billion of equity, $2.1 billion of high yield bonds. These financings allowed us to build a substantial oil company and have ample liquidity to fund the growth of the Company into 2014. We're fully aware and comfortable of current debt metrics. We continue to target a leverage ratio of 2.5 to 3 times over the long -- longer term, which we believe is attainable over the next 12 to 18 months based on the current model that we have.

As of the end of the year, December of '12, pro forma for the $600 million note offering that we completed last month, we have liquidity of $1.2 billion, and that is consisting of cash we have on hand at the end of the year plus a fully undrawn credit line of $850 million. Finally, we're going to continue to target a hedge portfolio in which approximately 80% of our anticipated production is hedged for the next 18 to 24 months. Over the past few months, we've been fairly active layering in [costals] collars for oil; we've also added some collars for gas in 2014. We currently have just over 22,000 barrels of oil per day hedged in '13, at an average price of right at $91, and we have about 17,000 barrels hedged at '14 at a price just under $90 a barrel. On the gas side, we have about 8.8 million cubic feet a day hedged in '13, and 25 million cubic feet a day hedged in '14, at prices just under $4 in Mcf. As we've historically done, we'll continue to be opportunistic about layering in hedges to protect the capital program. And with that, I'll turn it back over to Floyd.

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 from RBC.

Hello, 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?

Yes, Leo. The Mississippi Lime continues to be a hit-and-miss proposition for us, as I mentioned before. A couple good wells, a couple of bad wells and a mediocre well. We continue to have 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 are 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, activity down there has really picked up. We're just embarking, as we 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.

That's helpful. And 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.

Okay, and in the Woodbine, obviously, you guys had pretty good results this quarter with the drill bit. Think you're up to somewhere around 235,000 acres at this point. I'm just trying to get a sense of how much of that acreage do you guys feel has been de-risked from the drill bit, either by yourselves or 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 of our acreage has been de-risked; that's probably somewhat less than 50% 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.

All right, that's helpful. Thanks.

Thank you. Our next question comes from Brian Singer from Goldman Sachs.

Thank you. Good morning. I wanted to just see if you could touch on production guidance. The 40,000 Boe a day 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 -- of the total potential production for the year.

Brian, we, as we do every year, we have -- 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 this yet; we will do so sometime in the future. And we certainly haven't given out a -- 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 the way that production will come now.

Great, thanks. And then do you see yourselves making additional acquisitions or asset sales beyond the potential Eagle Ford sale, or is it the assets that we see here are the assets that we'll probably get for late this year?

Yes, 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.

Thanks. 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? I know a number are - 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.

Yes, 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 here tells us that we're extremely pleased with where our lands are, and with the content of the rock and the rock properties and whatnot. We're just [starting] -- soaking idea that seems to be so effective is just put a little more delay in our results there. We'll be releasing -- we'll be having results in April in our first two wells, then we'll have results every month after that.

Great, thank you.

Thank you. Our next question comes from Neal Dingmann from SunTrust. Pardon me, your line's open. If you have your phone on mute, can you unmute your phone, please?

Sorry about that. Good morning, Floyd. Floyd, question to your Bakken area, either in the Fort Berthold or the Marmon 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 through the remainder this year. 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 Berthold 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 where we would hope to be able to improve results in those other areas to make them competitive with the core of the play. But for this year and next, our plans are to focus right in the middle of the play and drill Three Forks and Bakken wells.

Interesting. And then Floyd, either in that area or even your Woodbine, can you give us a sense of how can your services area -- it looks like you're certainly building that out like you did in prior company rather quickly. Trying to 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?

Yes, sir.

In the Bakken, it's fairly mature up there, although this gas flaring business would tell you that there's some lacking up there. We are trying to utilize the services that are in place up there to a large extent. That's going to be the quickest path towards meeting our oil 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 it -- 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 will be -- I don't know how many miles of pipe we anticipate, but it's -- we're going to try to service all of our own wells with our own systems down there. It will be extensive.

Okay, and Floyd, staying with that Woodbine, just wondering will you continue -- is your thoughts are that the Brazos County wells, like this last quarter you just reported, wells will be a little bit better than what we're seeing in -- I know, Polk, you don't -- you've 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 barrel range to 700,000 barrel range. With our average well being in the 500,000 barrel range 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 a geologic feature up there; we've 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've defined the edge as we typically try to do here.

Brazos County, it's going great over there. Madison County, we hadn't quite cracked the code. We're waiting on some 3D seismic to see if that could help us avoid some hazards while drilling faults and whatnot. 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 Leon and Brazos County.

Got it. And the last one, if I could, just a little bit further on Brian's question on the Utica. I know it's early, but I know the thoughts are -- just what your thoughts, Floyd, up there as far as pressure. Any comments you can make? I know there was really 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 expect it to be, and we're looking for a very -- you know, this reservoir is very energetic. And again, we're trying to -- as best we can, we're trying to target that transition zone as you go from light gas toward 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 any -- we don't have concerns over pressure. We found the appropriate amount of thickness in our first several wells that we drilled, so we just have to get these wells on production and see what they do.

Got it. That's a great update. Thanks, Floyd.

Thank you. Our next question comes from Jason Wangler from Wunderlich Securities.

Morning. Just curious in the Utica, obviously, you have 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 sale -- I know you're working on the service part of it in the midstream. Do you think you'd be able to hook those up relatively soon after getting them tested, or will there be -- will that all be second half events?

Actually, if I just look at our first front half of the year drilling, we'll drill 10 or 11 wells, or maybe even 12. We'll get 10 -- at least 10 wells drilled by the middle of the year. We expect to have the majority of those on pipe; we're working on that as we speak at that same time. But we'll have a few wells, it will be waiting on infrastructure. And the main reason they'd be waiting on infrastructure, waiting to see what 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.

Okay. I mean, that obviously make sense as far as putting what you need out there. And as far as -- is the plan at least to -- as you get a couple of wells down, or 10 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 stepping out, like you said, delineating further out where we may have to wait while before we get those done?

Actually, you can go on our website, and we have a map, and it shows that our 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 -- by 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 --

Okay. Sorry, go ahead.

We have some experience at the this, and we're planning for two or three different outcomes in every area, and we'll be basically fast on our feet as events unfold.

Sure, so it's more of a work in progress, as well, as far as how -- which wells will go to what system, and you'll hook those up as you see the best way.

Yes, if you look at that map I mentioned, you'll see there's three basic concentrations of acreage, and so each one will have their own 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.

Okay, that's helpful. Thank you.

Thank you. Our next question comes from Ron Mills from Johnson Rice.

Floyd, 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 offers probably more opportunity 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 some faulting or some lost circulation zones that give you trouble. So I think the opportunity over time is you really -- 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.

Right. And then when I look at the initial results, particularly up in Leon County, the 30-day rates versus the IP rates, and compared to the curve in your presentation that seems to be right in the wheel house. Did I hear correctly that those -- some of those wells were drilled more on the edge of a feature, and if so, does that mean that as you move to the more central part of the feature, that 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 at 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. Yes, we drilled some wells that would be right on the edge of our map, best part of that -- part of the field. 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 signed AFEs the last couple of weeks on our first few wells right in the middle. We had some lingering curative issues on title and planning issues and whatnot, so we're -- 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 heretofore. I think I signed an AFE 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.

And you talked, though, most of your activity being in Leon and Brazos, of the 70 wells to 80 wells you expect to drill in that area, do you have a breakout of Leon versus Brazos versus the Central Madison/Polk area?

We do, but we're not saying. (laughter) We're still leasing and making deals here and there.

Okay, and just one more on the Utica, if I may be -- one of the things that I know Range talked about and happens in all of 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 Range's 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 we 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 chain consortiums. 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 sNortheast part of the United States. And if -- 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 a little bit differently, I'd accept that totally because they've drilled -- I don't know, thousands of wells up here.

Okay, and then Mark, one. 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, is that -- how is that staggered through the year? Or is it pretty flat throughout the year?

Yes. 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 that would -- a lot of that would carry over into '14. However, I think that it's roughly accurate. There was another part to your question. What was that?

It was just -- I was just -- you had talked about the production profile, somewhat tracking the CapEx. 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 it was more heavily weighted or more flat.

Yes, Ron, the third and the fourth quarter are going to be more heavily weighted than the first two.

Okay, perfect. Thank you.

Thank you. Our next question comes from Steve Berman from Canaccord.

Thanks, good morning. Just one question on -- in the Williston, Floyd, on the 25% targeted cost reduction. Can you put that into perspective to the $10 million costs you've had in your presentation? Maybe talk about how costs are running in the different areas for Berthold, Marmon, New Home, Montana?

Yes, Steve, everybody knows I'm full of crap, right? So I've actually got people here at the Company that are putting pen to these calculations as we speak. A lot of it involves the efficiencies gained through pad drilling. Those are enormous, and there can be -- 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, 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 there. 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 part, 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've 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.

But is it oversimplifying to think that you're going to -- you can bring costs down 25% from the $10 million, or just -- 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.

Okay, no, that's helpful. One other quick question. On the South Louisiana divestiture, was that something that was reactive or proactive? Was it something to looked to do, or did someone come to you? Maybe put a little perspective on that.

Hey, Steve, it's 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.

Got you. All right. Thank you, guys.

Thank you. Our next question comes from Jeff Robertson from Barclays.

Thanks. Floyd, in terms of some of the efficiency gains you all are trying to achieve, is -- are any of those potential savings, or maybe production enhancements factored into the capital budget you've talked about?

No, not yet.

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 or --

Yes, if the -- you can think this through pretty easily. If the improvements on cost are -- a lot of it's on the drilling side, that means 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 rig 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 more than 50% of that today.

So there's a whole smorgasbord of improvements and enhancements that we're working on. We think the -- 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.

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 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 a transferable, 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 over there.

More shale. Woodbine is a sandstone.

They're all different.

You know, the Utica's a shale. Probably a little more like the Eagle Ford than either one of those plays. So yes, we learn a lot, but they're -- that's really a good question, because -- 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 whatnot 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 a self-contained way.

Thank you.

Thank you. Our next question comes from James Spicer from Wells Fargo.

Hello, 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.

Okay --

It was about -- I think it was -- how much was that gas? 15% gas, 80% oil and 5% NGL. That's the exit rate for 2012.

All right, 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? And 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 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 hookup and the speed of getting your produced products out of a local market into perhaps a more attractive market, so those are our 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. Then about a year into it, we're far enough along to establish a separate, stand-alone credit line. Then another few months or year, 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.

Okay, that's helpful color. Thank you.

Thank you. Our next question comes from Chad Mabry from KLR Group.

Thanks. Good morning. Quick question on the Tuscaloosa Marine Shale. You commented in your earnings release, the zone of too thin for commercial production. Can you expand on that, maybe comment on what thickness you encountered in the Lambright compared to the Broadway, and maybe how that has 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 it's -- we just deemed it to be noncommercial pay.

About 40.

It's plus or minus 40 feet of pay. And it's -- there are some wells off not too far from that, to the west of that, that look similar, too. It's a little surprising to us, but it's not unreasonable.

And the Broadway had about how many feet?

Broadway is over about 120 feet. It looks -- I mean, it looks like it should look.

That's great. Thanks. 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 --

Yes, we have, like we do in all of our plays.

Okay, great. I appreciate it, guys. Thanks.

Thank you. Our next question comes from Elliot Javanmardi from 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 in 562,000-barrel equivalent-type curve?

The 562,000-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 barrel-type curve, so there's a -- clearly a mixture in there. The great news is that the wells come on in -- at much -- in much the same way in terms of 30-day IPs. And you know, the EUR is the tail of the dog. The early couple 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 not -- or unsuccess of a well, is that IP and how long it lasts before it gets into its steady state terminal decline.

Excellent, okay, and that answers the question. Just a followup, then, on the TMS. You talked about well costs being reduced, and any idea of where you 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 that you do. The dry hole that we drilled, the strat test, we got down to the point of kickoff for -- and log -- and had it logged for less than $4 million. That would -- you could extrapolate from that a well that would run $10 million or less, if you didn't have any trouble in the well bore -- we didn't have any trouble in that well. So it's a great sign that is 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 have discussions with others and they're all feeling the same way.

That's very helpful. Thank you.

Thank you. Our next question comes from Mike Kelly from 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?

The CapEx for the leasing budget in 2013.

Yes, 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 0.5 million acre land plays right now.

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've 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 in the fringe of your acreage 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 yes, there's a little bit of a disconnect there. You would expect that the average across the -- all of the wells to -- the IP rate to -- 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.

Okay, and maybe just how much acreage do you think you have, core Leon County?

It's a lot. I forget how many we're planning on. We don't really get -- 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.

All right, understood. Thanks.

Thank you. 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. 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.