Battalion Oil Corp (BATL) 2012 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Halcon Resources' Third Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, and instructions will follow at that time. (Operator Instructions)

As a reminder, this call may be recorded.

I would now like to introduce your host for today's conference, Chairman and CEO, Floyd Wilson. You may begin.

Good morning, and thanks for joining.

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 disclaimers, see our earnings release issued this morning.

Well, we've worked hard over the last several months transforming a small E&P company with conventional production of about 4,000 barrels of oil equivalent per day into a formidable resource style oil company which will be producing over 25,000 barrels of oil equivalent per day by year-end.

We have amassed solid positions in our three core plays, those being the Woodbine/Eagle Ford, the Bakken/Three Forks, and the Utica/Point Pleasant, and we are planning on explosive growth in 2013 and beyond.

We have 14 operated rigs running in our oily resource plays, and we expect to add another six or seven by year-end, which would include the five rigs running on the acreage that we are acquiring in the Williston Basin, the new acreage there.

There are currently 18 wells being completed across our holdings. Going forward, we anticipate new wells coming online regularly in all three of our core plays.

I'll spend a few minutes this morning discussing the updated outlook for CapEx and production provided in the earnings release issued this morning. That is the updated outlook for 2013.

We recently wrapped up our 2013 planning and budgeting process. That process involves competition for drilling capital within the budget and a steady eye on the balance sheet and liquidity.

Important decision we make during this process really relates to how and where capital should be deployed. This topic is revisited often as new information or new properties become available, such as the pending Williston Basin assets acquisition.

Our previous guidance for drilling and completion in 2013 was for about $900 million. We have reset our 2013 drilling and completions budget to approximately $1.2 billion. This represents a reallocation of capital to our three core plays. These three plays will receive more than 90% of our 2013 drilling and completions budget.

Very little credit is being given to wildcat drilling. Adds from that category will be upside, if any, and we are looking for ways to shave this budget a bit without changing our outlook for production growth.

It's important to note that various factors, such as a resting period after frac jobs in the Utica/Point Pleasant, infrastructure challenges in that area and a few others, regulatory or permitting delays, and pad drilling all impact the timing of when new production goes online.

We are in a very good position now to make an accurate forecast of those factors for 2013. With that said, we continue to forecast an industry-leading production growth rate for next year.

Our three core plays are up and running. We've accumulated a premier position of more than 200,000 net acres in the Woodbine/Eagle Ford, and we are the most active operator in that play.

Operating efficiency in a culture that promotes creative thinking is crucial to the success of any oil company focusing on resource-style plays. I believe we have both of those factors.

In an effort to become more efficient at Woodbine/Eagle Ford, we have implemented pad drilling already, reduced the size of the intermediate hole from 9-7/8 down to 8-3/4, which has helped us eliminate [intermediate casing] in some areas of the play. On average, we are experiencing cost savings of approximately $1 million per well in the areas where these drilling efficiencies are applied.

We're in the process of utilizing micro seismic on a few of our Woodbine wells to gain a more thorough understanding of what can be done to optimize our frac jobs, and we're using pad drilling everywhere. Super fracs are also being implemented in some parts of the play.

Currently, we have 15 horizontal wells producing from the Woodbine; in Leon County, six wells being completed; and six wells are being drilled across our acreage in Leon, Madison, and Grimes counties. Two of those six wells being drilled will be completed in the Eagle Ford formation. All six -- two Eagle Ford and four Woodbine -- should be online by the end of the year.

Moving on to the Bakken/Three Forks, as you are aware, we announced that we entered into an agreement with Petro-Hunt and another affiliate to acquire approximately 81,000 net acres of producing and undeveloped land, prospective for the Bakken and Three Forks formations in North Dakota. We should close this about mid-December. This will take us up to over 135,000 net acres in the play, with eight operated rigs running. Again, five rigs are currently running on the property at Petro-Hunt -- that we're buying from Petro-Hunt.

We plan to direct about 40% of our 2013 drilling and completions budget towards our Williston Basin assets, most of which will be spent drilling wells in the prolific Fort Berthold area. By the end of the year, we'll shift two of the rigs from Williams County to that area.

Once the Williston Basin acquisition closes in mid-December, we'll have over 700 gross operated drilling locations prospective for the Bakken and our Three Forks. We have identified several operational improvements that can be implemented in relatively short order, and we intend to exploit this asset aggressively.

Production from our third core play, the Utica/Point Pleasant, is expected to contribute meaningfully in the second half of 2013. We recently spud our first two wells there. We have two rigs running in the play. In this area, permitting, infrastructure, and completion times are all challenges on estimating times.

The focus has been on positioning ourselves for a continuous drilling program, which we've done. We have drilling permits in hand and more in the works. We plan on adding a third operated rig in early '13 and a fourth operated rig by mid-'13.

We spud our first well in the Tuscaloosa Marine Shale during the third quarter, the Broadway 1H. We were able to get over 300 feet of core from the Tuscaloosa Marine Shale prior to kicking off the lateral. Preliminary core log results are very encouraging, and we are now in the process of drilling a 5 to 7,000-foot lateral. We expect to begin completion operations within a month or so. We will drill two more horizontal wells on our acreage before implementing a full-scale large-scale development strategy.

Mark Mize is here, and he'll now go over the financial results for the third quarter.

Okay, thanks, Floyd.

Before we get started, I'll point out that the third quarter results of operations represent two full months of activity related to GeoResources and the East Texas assets. Since both of those deals did close on August 1, the fourth quarter will be our first quarter to include the full impact of those two transactions, and we expect the fourth quarter to also include about a half month's worth of the contribution from the Williston Basin asset acquisition that we expect to close on or around December 13.

From a financing perspective, we've been busy here recently raising capital to finance the Williston Basin deal, as well as fund the Company's capital plans through 2013.

I won't repeat the details that were covered on the call that we had on the 22nd, but in summary, we have agreed to issue 750 million preferred shares to Petro-Hunt. That will automatically convert into approximately 100 million shares of common stock following a shareholder approval.

We also entered into a common stock purchase agreement with the Canada Pension Plan Investment Board pursuant to which they have agreed to purchase approximately 42 million common shares of Halcon, which equates to about a $300 million investment in the company.

Also, with the support of our top-tier banks, we were able to secure an increase in our borrowing base from 525 million to 850 million, and that does represent a combined reserve look at Halcon standalone plus the Williston Basin assets. That credit line will close into escrow and then the additional increase will be available to us upon the close of the deal in December.

And then, finally, we also closed on a $750 million high-yield bond financing this week, the proceeds of which will also be released from escrow upon the closing of the Williston Basin deal.

With regards to equity, we ended the quarter with just under $1 billion of liquidity pro forma for the finance transactions that I just mentioned, and this provides the company with the capital it needs to execute on its growth strategy through 2013, which has now shifted from an acquisition phase to drilling.

For 2012, we reiterate previously published guidance and believe we'll be within the guidance ranges provided, with the exception of G&A per BOE, which will be just over the high end of the range. We've also updated our production and capital cost guidance for 2013 to account for the acquisition of the Williston deal, as well as a revised drilling program on our existing assets.

We increased our production guidance and are now targeting an average daily production rate of 40 to 45,000 BOE a day in 2013, and we increased the drilling and completion budget to $1.2 billion. Both of these figures, as we typically have done in the past, they do not include considering divestitures.

From a cost perspective, we've increased our [seamed] LOE per BOE range by $1 in 2013, so it's now $6 to $8 of BOE, and we did the same for the production tax rate so it's now 5 to $6 of BOE. But we did keep the G&A cost range unchanged at 4 to $6. The increase in LOE and production taxes is primarily the result of increasing our operations and production mix in the Bakken/Three Forks resulting from the pending Williston deal.

Just to comment on the hedge program, we do continue to target a hedged portfolio of approximately 80% of what we expect to produce over the next 18 to 24 months. We still have a fair amount of additional hedging that we'll need to get done to get to those levels, and so we'll continue to layer those in as opportunities present themselves. Right now we have right at 9,000 barrels a day of oil hedged in '13 at an average price of just under $90 a barrel, and with the natural gas coming back a little bit, we've been keeping our eye on that, and right now, we have about 1.3 million cubic feet a day hedged at an average price of $4.18.

With that, I'll turn it back over to Floyd.

Thanks, Mark.

We are confident in our ability to deliver on our strategy in all respects. Like to remind everyone on the call that this is not our first rodeo, and I say that because we're down here in Texas. This management team has a pretty decent track record of building companies and a pretty decent history of creating shareholder value.

Operator, we're ready for questions, if there are any.

Thank you. (Caller instructions)

Brian Corales, Howard Weil.

A question on the oil realizations. I mean they look pretty strong for the quarter. Is there an asset you're getting kind of an uplift for oil prices?

Hey, Brian, this is Steve Herod. We rebid some of our oil production in the third quarter, and we got an uplift both in the Woodbine and in the Eagle Ford, and that may be some of it.

Okay. And on that same topic, as you add the additional Bakken properties, where do you see kind of that corporate oil realization going, I mean, if we look out towards '13 and beyond?

We haven't given that guidance. The realization there is slightly less than other areas, so that would have a bit of a muffling effect, I would assume.

Okay. And then one on the Woodbine. Have you all tested the Polk County acreage yet? And if not, do you plan to test it over the next couple quarters?

We have not yet. We're doing extensive research there. We've built a great acreage position over there, and we think the target is big and broad, but we're doing some additional research, acquiring some additional lands.

And as in several of our plays, we're actually doing some seismic work, so our intentions are at this time to try to get a rig on it in the first quarter of next year. Meanwhile, we'll just continue drilling our wells in the rest of the play, and as soon as that location -- a couple locations are ready over there, we'll move a rig in, but I doubt if it will be this year.

Okay, and then one final one. You've got your kind of three big core areas where most of the capital is going. Do you expect to buy into a fourth area, maybe a little bit more of a proven play, or are you going to stick towards more the exploration side?

We are hopeful that one of our wildcats will turn into a core area. We never know about that. I don't really see us buying into a fourth core area, to answer your question. It's not really on our radar screen right now. I think we have enough to do with our three. We have some drilling going on in our wildcats and some analysis going on, so we're hopeful about those, as well.

All right, Floyd. Thanks, guys.

Brian Singer, Goldman Sachs.

In the Utica, can you talk about any interpretations you may have from recent industry wells and how that applies to the prospectivity of your acreage? And then as you think about ramping up to four rigs there, is that contingent on the results from your first three wells, or is that kind of needed to hold acreage?

Well, anything that we do is contingent on results. So I don't care where we're drilling, it's always that way.

The first part of your question -- all the data points that we've gathered, and we probably have as many or more than anyone else in the play in our research database, have continued to verify our research and our mapping and our view of where the play is going, so we're highly comfortable with what we're doing.

Thanks. And then in the Tuscaloosa, you mentioned after logging the vertical section, you're seeing encouraging results from that first well. Can you just add some more color on what's driving that encouragement and whether it's just related to the [shows] you're seeing, the costs of the wells so far, or both?

Well, things that encourage us are things like oil in the samples and oil in the pits, a lot of smell. When you get your samples up, when you pull your core out, your core sections out, you can actually see with the naked eye some of the characteristics that you're looking for.

And then, of course, the logging. The log gave us the parameters that we were looking for in terms of processing and whatnot. So that's the encouraging part.

The rest of the encouraging news is that we feel like over time we'll be able to get these costs down under $10 million. These first few wells won't be there, but the profile of one of these wells is about the same as the Blackhawk well that we used to drill every day in South Texas, and in terms of total measured depth, frac stages, horsepower, fluid requirements, carrier fluids requirement. So we're pretty comfortable that the cost side of this equation for us and others in the industry will improve.

Thank you.

Neal Dingmann, SunTrust.

Floyd, just three quick ones. First, any idea when you'll give us a little more specific color on one of these undisclosed exploration plays? Will it be any time soon, or are you going still try to develop those out first?

We're going to continue to develop our acreage position and those that we've drilled -- well, if we drilled any early-stage reconnaissance wells, we'll continue to evaluate information that we've gotten through those from logs and cores. I think that our job is to assess those things quickly and continue to buy land, if we like our early results, our early research results, cheaply, so I don't think that we'll be talking about those too much this year. Next year for sure and perhaps earlier in the year, our focus, since we added this huge position in the Bakken/Three Forks play, is to create a platform that's not dependent on new discoveries for growth. We think we've done that.

So our three core plays will get over 90% of the funding for 2013 and probably about 75% of our thoughts in terms of improvements and whatnot, and that's a vague number but -- so I think that's the answer to that part.

Joseph Allman, JP Morgan.

Floyd, when you look at production for 2013, I think your core fields are going to grow, but will some of your non-core fields decline? And could you just talk about which fields, where you expect production declines?

You know, production declines normally occur just through the normal aging process of mature fields, and we have a little bit of that going on in some of the properties that we'll divest over the next couple of years.

In any of these resource-style plays, horizontal drilling, if you cut your rigs, you fix yourself up for a decline, whether it's right away or over the next foreseeable time. So what our objective here is to make sure that we have that right balance between capital outlay and production growth in the three large plays, and then we're really not counting on hardly any component of production from anything else in the company. We do have a nice base of stable, mature properties. I think those decline at 20 or 15, 18, 20% a year, and we are spending a little bit of money on those that don't require too much.

Okay.

So we're settings ourselves up that the active drilling in the three core plays will provide all of our projected growth and certainly not be looking at any declines with these kind of rig counts for some years, in our opinion.

Got you. So like if we take the production that you bought in the recent Bakken acquisition and just add it to the base production, you get to a number higher than your guidance. Is that because you're investing the capital in the core kind of growth projects; you're not investing the capital in the non-core projects, and those are going to be in decline?

Probably offline, we'd have to go through that math with you. I don't think that you just add our base properties that we reported on last quarter and add the Bakken and come up with quite that number, but the entire process does represent a reallocation of capital. It represents a better understanding in several of the plays of some of the delays we've had in terms of in the Utica/Point Pleasant. Early in the year, we expected to have rigs running in August. We got rigs running at the end of October. Now, we're steady there.

So I think that as your information and your database grows in each area, you're able to make much more studied improvements or projections.

Got you. That's helpful. And then the production from the assets you plan to sell, that production is still in your production guidance, right? And you only take that out once you've sold the remaining agreement to sell the assets?

Yes, we'll only remove those when we have a binding situation because you never know about divestitures or acquisitions for that matter. There's no good reason to include or not include those until something's firm.

Got you. And then, lastly, could you just update us on the sales process for the non-core asset sales?

You know, I think the big one for this year is Eagle Ford sale. That process is ongoing. We've had quite a few people look at it, and the rest of those, we're scheduled for a bit of that activity in the 2013 and a bit more in 2014.

All right. Very helpful. Thanks, everybody.

Steve Berman, Canaccord Genuity.

Just a follow-up to Joe's question on the Eagle Ford. Can you tell us what current production is so we can kind of get a feeling for what we will have to back out at some point here?

We haven't given production by region, and we're not doing that today.

Okay. Floyd, on the $1 million in savings in the Woodbine/Eagle Ford, in your recent presentations, you had a $6 million drill-and-complete cost in there. Is that $1 million in savings getting you down to that 6, or is that taking you even below the $6 million number?

You know, each well will be a little bit different The way that the leases are shaped in Texas allow for certain length of laterals in certain areas and maybe shorter laterals in some other areas. I would say it's about half and half that those improvements would be an improvement on that $6 million number, and the rest of it would be getting some of the wells down to that number.

Something that we haven't talked too much about, we've just drilled one well in 15 days top to bottom, and that's a major improvement over the 30 to 40 days before, and that didn't have that much to do with the hole size, so we're looking to make improvements in that play as much as you see in almost all of these plays.

Okay, and a question for Mark. Can you break down the $984 million in pro forma liquidity between cash and revolver availability?

Yeah, I mean when we -- if you roll forward what that number is, if you roll forward to December 13, when we expect to close on the Williston deal, the credit line is going to go from 525 up to 850, and there's cash embedded in that $1 billion number, under $1 billion, of about 135 million. Then you have the credit line and then we have the senior notes that are also going to be coming out of escrow.

So if you take all of those sources and then you net out the acquisition, the exact number we come to is about 984 million of liquidity.

All right, thanks. That's it for me.

Ron Mills, Johnson Rice.

Up in the Utica, I think where you're located, you're targeting more of the Utica versus the Point Pleasant than some of the industry results down south, but if you look from a technical standpoint, you know, porosity, thickness, [resistivity], do those compare pretty favorably to each other, which is why, based on your information's data set, you continue to remain so comfortable about that portion of the play?

Ron, we have, as you know, and others have lots of data points, both in the south end of the play and up in the north end from drilling that's been done over the years. Our opinion is that the section is all one unit. The member that is the Point Pleasant in the south is brighter and more attractive than the Utica in the south. Up in the north end -- and thicker -- up on the north end, the Point Pleasant thins and the Utica thickens and is brighter and more porosity and so on. So if you take the two as a net unit, they look about the same north and south to us.

Okay, good. And just to clarify what you were talking about in the Woodbine/Eagle Ford -- I want to make sure that between drilling and the completing wells, I get it right. Did you say that two of the six wells you're drilling right now are targeting the Eagle Ford, or were those on the completion side?

Two of the six wells that have rigs on them are drilling Eagle Ford laterals now, and the other ones are all scheduled to drill Woodbine, and I think upcoming, we've got at least two more Eagle Ford holes to be started this year, and most of the rest will be Woodbine this year.

And then of the six wells that are either completing or awaiting completion, are those also split between Eagle Ford and Woodbine?

I think there's two, one Eagle Ford -- I'm asking Robert here -- one Eagle Ford and five Woodbine. We're shooting some seismic on several of our plays, right? And so here in Madison County, Grimes, and Leon, we've got a large seismic project that we just kicked off. So we're concentrating our intensity up on the north end of the play in Leon County, where we have tons of places to drill wells and success with every attempt so far.

As we get a little bit more data from these kind of outpost wells we're drilling in the rest of the play and as we get information from the seismic, you'll see us moving more rigs to the south, but I think for the -- certainly for the first half of '13, 80% of the rigs are going to be up on the north end of the play.

And that's -- the primary target there is the Woodbine?

The upper Woodbine, yes.

Perfect. And then, lastly, just on the CapEx, just to make sure the 900 million of drilling in the old budget and completion versus the 1.2 billion, that 1.2 billion, it does include the Eagle Ford component, it sounds like from your press release, but in that D&C budget, is there also already been some reallocation to allow that increased focus toward the 90-plus percent on your three main project areas?

There's been a lot of reallocation within the 1.2. The Eagle Ford component, I can tell you, is about 100 million, so that would be a change. Chances are if and when that occurs, we probably won't reallocate those funds. We don't need to. We'll probably just spend a little bit less next year.

Okay, perfect, because it looks like from a capital efficiency standpoint, based on your guidance, it looks like that capital efficiency is showing a nice improvement, so congrats.

Thanks.

Mike Kelly, Global Hunter.

About the completion schedule going forward in the Utica, Woodbine, and Tuscaloosa, really how it progresses throughout '13.

You know, we're basically doing pad drilling everywhere, so the completion schedule is pretty much tied to when you have wells on a pad ready to be fracced and you've got the rig out of the way, so the results are somewhat lumpy. But over a period of a year, it should even out as if you were doing them one by one.

I'll just tell you that by the start of the year, it will be a pretty even process throughout all the three core areas in terms of all of them will be utilizing pad drilling, or 90% of the locations will be pad drilling, and we'll be fraccing two or three wells on these pads in every case. So we'll have -- hopefully, they'll just be -- it will become fairly steady, but we're certainly going to have some times when if you're taking a month to drill a well, you've got 90 days of just pure drilling. If you have a three-well completion coming up, then you've got a good 'nother month of completing three wells. So a pad with three wells on it could easily take you 120 days, whereas you could have been doing one well at a time in about 45 days or 60 days. So over time, it should even out in terms of the production response.

Okay, and then just focusing on the Utica, will you be ready at the beginning of the year there to really take that gas or wet gas? And what are your plans in terms of this shut-in period?

We have an ongoing and aggressive infrastructure strategy being worked for that area. We are making interim arrangements for deliveries. While we'll be doing some construction, we're still evaluating the options up there in terms of doing everything ourselves or joining with someone else that's in the same position that we are, so I think we're working on that.

We won't have any delays on this initial slew -- slug of drilling up there based on infrastructure. We might have some significant improvements that could take up to a year to install that would allow for better price discovery, but we don't plan on any delays.

Okay, and when we should expect really that first slug of wells and completion results out of that basin?

Yes, I didn't answer the other part of your question. It's become pretty clear that this -- whether they call it a resting period or a soaking period, it's become pretty clear that that's a valuable component of completions up there, so we're programming about 120 days from moving a rig in to having first production on wells using a 60-day kind of soaking period.

We have -- these rigs -- very quickly, they should be drilling wells in less than 30 days. We've got two rigs running right now. [We] had a rig in the fourth quarter and a rig in the second quarter, so add a rig in the first quarter of next year and a rig in the second quarter so you can -- whatever that math comes to is how we'll be doing.

Okay, thanks. And then just on the divestiture front, we all the Eagle Ford process is ongoing. Maybe you could just refresh us on the overall strategy there of divestitures and really what's on the table and the potential timeframe in '13?

Yes. The overall strategy is a strict focus on moving out mature no upside properties even though they might be nice moneymakers in favor of these newer properties where we have years and years of drilling to do.

So I would say that Steve will have some other property on the market by the middle of the year in 2013, and we're not sure which properties exactly yet, but we have a hit list of targets there, and depending on how that goes, we might sell some more in '13 or we might wait till '14.

We're trying to make sure that -- there's two factors there that we think about. One is all those properties that we acquired with a couple of the deals are good properties. They might be mature and all that, but they were all making money, and they all have production, so we don't want to lose that production until we can overcome that loss with this new drilling, so that's a major focus of ours is not to go backwards.

Okay, thank you.

Jason Wangler, Wunderlich Securities.

On Midway/Navarro, obviously, the first well looked good and you're testing the second. Do you have an idea of what the plans are rest of this year and obviously more importantly '13, or are you still kind of jury-out waiting to see what the two wells look like?

You know, on wildcats, the jury's always out, but up there, we're getting ready to complete the second well. We've got this first one on production just recently. We're shooting some seismic, so we've determined we're not going to do any more drilling until we have the seismic.

As we pointed out early, that play is not a -- the zones are a blanket, but you need a little -- you need to have the stratographic. The good part of the section needs to be on a bit of a regional feature, so we're going to wait and have the seismic.

I should say that this is in keeping with the entire budget for 2013. Anything that we get out of wildcats is going to be upside. Over 90% of the money is going to the three core plays, and 100% of the growth is coming out of the three core plays.

Perfect. That's all I had. Thank you.

Chad Mabry, KLR [Pruitt].

Guys, on the 2013 CapEx and activity, can you provide -- you mentioned 1.2 billion on the E&D CapEx. What's the acreage split in there, or would that be in addition to the 1.2?

If we acquire any acreage, it will be in addition to it. We made most of our significant acreage investments this year, so we don't feel like it will be a significant number in relation to the overall scheme of things. We'll report the actual expenditures every quarter as we do.

Okay, appreciate it. And looking at the, I guess, sort of the remaining 10% of the budget, should we expect that to be more or less spread across the other plays in the portfolio, or is there any one that could get more attention than the others?

Well, Tuscaloosa Marine Shale has certainly got the possibility of getting more attention depending on early results from the three wells that we plan to drill right now. We do have some Wilcox drilling scheduled, but frankly, we've pulled anywhere where we don't have lease capture issues, which we don't have those in so few places, we pulled all the capital and directed it toward the three core plays.

I appreciate it. Thank you.

Jeff Robertson, Barclays.

Floyd, I think you mentioned that about 40% of the drilling and completion capital was going to go into the Bakken. Can you provide the split for the Woodbine and the Utica?

We haven't done that. 90% of it's going to the three plays, and the Woodbine's just about the size of the Bakken. So if you think about 1.2 billion and you've got 80% of it going into the Bakken and the Woodbine.

Okay. And then in terms of the exploration plays, if you all have success in the TMS and decide to put more capital there, would that be incremental to the budget, or would you reallocate from any of the three core areas to put any money back into the TMS?

Hard to really speculate about that. It would be -- we're oil guys here, so if it was a staggering success, we'd try to figure out how to beef up the budget.

Right now, our plan would be to just reallocate away from plays where we don't have any expirations. We have an idea that we can try to shave the budget in 2013 rather than increase it, so we're working on that pretty hard.

Having said that, some really good success in any of these plays would kind of change the deck a little bit.

Okay. And then, lastly, on the -- you all have in the footnote for the capital the notion that you might put in a separate credit facility for Halcon Field Services. Does that partly depend on the direction you decide to go in Utica as far as how much capital you all will have to put out versus whether or not you team up with somebody else?

Chances are any teaming up we do would be in some area where another operator has the same logistical issue that we might, and so we're following the pattern that we did at Petrohawk. As soon as you can establish an outlook for some EBITDA from those sorts of assets, you can finance them separately from your main corporate activity, and I'm just saying that we intend to do that, as we did at Petrohawk.

Okay, thank you.

Follow-up question from Jason Wangler, Wunderlich Securities.

One more. Just was curious. Is there going to be a time with the Woodbine that you kind of give us an idea of the well results and whether it's specifically each well or an average as you've kind of gotten a handful now and as you get them out to production for 30, 60, 90 days?

Yes, right now, we're waiting on six wells to be fracced and flow back, and then we've got a few rigs that are nearly done drilling. We'll probably put out some sort of an operational update prior to the next quarter. We just haven't been in a position to have anything to talk about of substance. We do intend to continue to track 90-day rates on wells and see how that looks versus our type curve.

I saw a graph yesterday that on that 1,000-barrel-a-day well that we completed, I don't know if it's five or six weeks ago, first 30 days, it's outperforming the type curve dramatically, but we like to see about 90 days before we really call those.

But, yes, we'll put out information. As we've done in the past, though, we'll tend to put out a lot of information on everything at one time during a quarter and not put out single well results. It just doesn't -- it just isn't our style to hold our breath about one well every few minutes.

Sure. I just wanted to more understand as we get the slew of wells in. So you're thinking in the next couple months, you'll have enough wells and you'll have enough time to kind of give us that, call it, around end of this year, beginning of next year?

We'll have another 10 or 12 wells fracced and on production within a few more weeks.

Perfect. I appreciate it.

I'm not showing any further questions in the queue. I'd like to turn the call back over to Mr. Floyd Wilson for any further remarks.

Thanks for joining, everyone. We look forward to 2013 and the fourth quarter. Give us a ring if there's something that we didn't cover that you'd like to talk about. Thanks.

Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program. You may all disconnect. Everyone, have a great day.