Battalion Oil Corporation (BATL) Q4 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Halcón Resources Fourth Quarter and Full Year 2013 Earnings Conference Call. [Operator Instructions] As a reminder, this call is being recorded. I would now like to introduce your host for today's conference, Floyd Wilson, Chairman and CEO. Please go ahead, sir.

Good morning. This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday afternoon. Today, we are reporting on 2013, plus on some items geared towards 2014 and beyond. Last year, we grew production by over 250%, and we plan to grow production this year by over 60%. We sold $450 million of noncore assets last year, and we sold another $450 million this year, so far. These proceeds supplement liquidity and fuel growth. Organic reserve replacement of over 600% in 2013, organic reserve growth of over 60% -- organic reserve replacement is over 600% in 2013, organic reserve growth is over 60% in 2013. At year end, we estimate net unrisked resource potential of approximately 1.4 billion barrels of oil equivalent. We have decreased our budget expectation on spending for 2014 from what we reported late last year. This is despite -- and will absorb the divestment that we announced yesterday and despite delays due to the harsh winter up north. So again, we expect to grow production by over 60% in 2014 on a pro forma basis, and we reduced CapEx from our prior estimates by 35%. About 90% -- a little more than 90% of our drilling completion budget will be directed to our 2 derisked core plays. Those are in the Williston Basin and at El Halcón in East Texas. And importantly, we've increased our EU estimates -- EUR estimates in both plays based on performance, and especially performance from new frac designs. Today, also, we -- yesterday, we announced our TMS, Tuscaloosa Marine Shale position, greatly enlarged and focused on the eastern portion of the play. Within the next couple of weeks, we plan to start drilling wells on our newly acquired eastern acreage. And of course, we believe that acreage to be in the geological -- geologic core of the play. Company-wide, we currently have 29 operated wells being completed or waiting on completion. We're operating about 8 rigs today in the Williston, Ford, El Halcón, and we'll move a rig into the TMS in March and another in April. In the Williston Basin, our Bakken/Three Forks program is going great. We have production growth there in 2013 of 77%. This year, all of our rigs are drilling in the highest-return area at Fort Berthold. We expect to spend a little -- just barely less than half of our drilling and completion CapEx in 2014 in the Williston Basin. And we expect to draw 100% of our 2014 wells off pad versus a little less than 75% last year. We've increased the average type curves on our EUR estimates in all areas based on improved results related to drilling and completion modifications. One of the big improvements have been slickwater fracs. We started with those up in the Williams County area. They were very successful. We've started down in Fort Berthold with those, and they're meaningfully outperforming our new type curve. Our new type curve is 801,000 barrels of oil equivalent per well. For these new wells in the south, they're outperforming that type curve. That's an average type curve of the entire play, except for Williams County. We plan to complete all future wells in Williston Basin with slickwater fracs. Continued downspacing there has yielded real success and have the potential to more than triple our operated well inventory in the Fort Berthold, as events unfold. Cost reduction opportunities are available. We're working on them all of the time. Proppant type, pumping services, drilling efficiencies, rig days, full-scale batch drilling, electrification of much of our field. These all remain our focus, as we expect some decrease this year by -- on completed well cost by hopefully 5% or 10%. In East Texas, at El Halcón, production grew from a few hundred barrels of oil equivalent per day in January to an average of over 7,000 barrels per day in the fourth quarter of '13. We expect that trend to continue. We'll run 3 or 4 rigs there for all year. We expect to spend about 40% of our drilling and completion CapEx in 2014 in El Halcón. We've exceeded our goal of 100,000 Tier 1 net acres in the play. We are confident that all of our acreage is in core of the play. We've increased the El Halcón type curve EUR estimate by 22% to a little over 450,000 barrels of oil equivalent per well. This is based on wells that were spaced a minimum of 750 feet apart and completed with over 1,200 pounds of proppant per lateral foot. So what that says is we've been testing different completion designs, different spacing, and we're getting close to zeroing in on what we think is the most appropriate situation to drill these wells in. Testing is underway on a number of completion design variations to reduce costs and increase performance, and we're working to find the most economic completed lateral length. We spend a lot less money drilling shorter laterals and, sometimes, the longest lateral is not the answer because you lose a little efficiency on your frac job. The exciting thing that's going on there, it's all been exciting, but results from step-out wells drilled to the south towards the Burleson County look to be the best wells in the play. They're slightly deeper, slightly higher pressure, hopefully slightly more prolific. We expect well cost to continue to decrease at El Halcón. We've had some wells that were dramatically less money. We'll just have to see how that goes. We can say for sure that El Halcón is the real deal. Over to Mississippi and Far Eastern Louisiana. We talked about for the first time, publicly, our Tuscaloosa Marine Shale play yesterday. We've got over 300,000 net acres there. To us, the TMS is one of the most attractive emerging oil resource plays in North America. We've got some challenges with completion design, but we are pretty well comfortable with what those challenges have been and the workaround for those. Over 75% of our acreage has been what we believe to be the core of the play. That's over in Southwest Mississippi and the Louisiana Florida Parishes. A full exploration staff have been working in this play now for over a year. And in our prior history, we've worked at the play before as well. Our full drilling and completions team has also been working on this for over a year. So we have a lot of -- we bring a lot of talent to bear on the Tuscaloosa Marine Shale, and a lot of experience and success between all the men and women on these 2 teams. This is a large concentrated, highly-operated position with favorable lease terms, and these provide for efficient resource development. And it's been a great operating environment for oil and gas, as everyone knows, and access to the -- some of the better crude oil markets in the United States. We have data sharing agreements with all of the other operators. And as we've had in all of our prior successful plays, this would be a great benefit to all parties. We are exploring a joint venture idea for our entire acreage position. It's not necessary on a financial basis, more of a luxury, but it would ease the way. We would expect to finalize our thoughts on this in the second quarter of this year. Not too much of our budget, drilling and completion, will go towards the TMS, about 10%. And we're expecting almost no production from it this year because of the early stage. So all of our growth is going to come from our 2 existing core areas, which we made impressive improvements in recently. Mark, why don't you go through the actual details, and then we'll take questions.

Okay. Thank you, Floyd. I'll begin with a review of the full year 2013 results compared to our guidance, and also touch on a few of the fourth quarter financial metrics. Production for the year came in at the high end of our guidance, averaged just over 33,300 barrel of oil equivalent a day. Production in the fourth quarter averaged over 40,200 barrel of oil equivalent a day, which is about a 7% -- about 7% above Street estimates, despite any of the negative impact. A little over 1,200 BOE a day related to weather downtime in the Williston Basin. On the cost side, LOE came in at $11.44 per BOE in 2013, which is below the midpoint of guidance and about 20% lower than in 2012. This is due to efficiencies in the areas where we're operating in. After adjusting for some selected items, as we typically do in the press release, cash G&A expense came in at $8.99 per BOE for the year, which is just below guidance and about 43% lower than prior year. Looking forward, our G&A rate is expected to be closer to the midpoint of our guidance that we put out there, between $7 and $9. Taxes other than income came in at $7.28 per BOE for the year, which is within the low end of guidance. And then, the last item I can touch on before turning to liquidity and our 2014 spending is the noncash full-cost full-impairment charge that's taken in the fourth quarter for $239 million. You may recall we have a noncash charge in Q3 of about $900 million related to an evaluated property cost that were transferred into the pool, with little to no reserves associated with them. And in the fourth quarter this year, we had an additional noncash charge for $239 million. That brings the full year 2013 impairment to $1.1 billion. In October of last year, our borrowing base was increased to $850 million from $710 million, in conjunction with our regular fall redetermination. Subsequent to the redetermination, we executed on some noncore divestitures that closed in the fourth quarter. And that, combined with the $400 million of bonds that we placed in December, resulted in a reduction that yields our current borrowing base of $700 million. We ended the year with undrawn revolver capacity and cash on hand totaling right at $700 million. And then pro forma for the pending sale of the East Texas Assets and a related $100 million reduction to the revolver borrowing base that we expect, we had undrawn revolver capacity plus cash on hand of about $1.1 billion. Additionally, we're going to initiate our spring borrowing base redetermination next week. And we expect an increase based on the year-end reserve report. We do not expect to access the capital markets in 2014 based on our current business plan, as proceeds from the East Texas Assets sale, cash flow from operations and available borrowings under our revolver are more than adequate to fund our growth. With regards to 2013 drilling and completion CapEx, we spent just over $1.5 billion, which is over the high end of our $1.4 billion guidance. It does relate to additional drilling activity in El Halcón and the Bakken, but they're not budgeted for in 2013. This drilling did generate additional production to more than offset lost production due to winter weather conditions in the Bakken. With that said, we're extremely focused on capital discipline and improving capital efficiency in 2014. Although, we do have front-end loaded 2014 drilling program, we expect spending to stay within recently published guidance. And looking ahead, we provide first quarter 2014 production guidance. And we've reaffirmed full year production guidance in our earnings release. There's no changes have been made to previously published costs and drilling and completion CapEx guidance for 2014. And as Floyd stated earlier on the call, to put our 2014 production guidance into perspective on an equivalent basis pro forma for all acquisition and divestiture activity, we are projecting year-over-year production growth in 2014 of over 60%. The full year 2014 production guidance of 38,000 to 42,000 does account for production that was sold in the fourth quarter of 2013 and that relating to the pending sale of the East Texas Assets, and we expect to close in the first part of this year. And keep in mind that we do expect to generate this production growth in 2014 despite reducing our drilling and completion CapEx by about 35% year-over-year. Very briefly, I'll touch on our hedging program. We did continue to build out a hedged portfolio where we want to target about 80% of what we expect to produce over the next 18 to 24 months. Today, we have right at 26,500 barrels a day of oil hedged in 2014 at a price of $89 a barrel. We've got about 22,000 barrels a day hedged in 2015 at about $87 a barrel, and then we have 6,000 barrels a day hedged in 2016 at $88 a barrel. So while our hedging portfolio for 2014 is fairly complete, we're going to continue to layer in hedges in '15 and '16 to try to build to our target levels. With that, I'll turn the call back over to Floyd.

Thanks, Mark. So for 2014, we plan to deliver strong growth this year while spending less than we originally estimated. Our growth will be driven by production from improved wells and big wells in both Williston Basin and in El Halcón. We'll spend all of our 2014 budget in the sweet spots of those 2 core plays. The TMS is an early-stage play. We're not anticipating hardly any production from that for this year, but it'll build into '14 and '15. We expect to drive future production growth and achieve higher rates of return across our asset portfolio through our relentless focus on technological innovation, which is one thing that we've been known for. Lastly, we are comfortable with our liquidity position and have no plans to raise additional capital. Operator, we're now ready for a few questions now, if there are any.

[Operator Instructions] And our first question comes from Neal Dingmann from SunTrust.

Say, firstly on TMS, 2 quick questions there. First, what are you assuming on early well cost, and how do you think that changes? And then, just on the overall CapEx, I think you said about 10% allocated there. Is that fairly flexible this year based on some early success of these 10 wells, or do you want to keep that pretty straight?

Taking those in reverse order, we intend to stick to our budget for this year. Always subject to change, but our idea here is that we're going to ease into the play with a couple of rigs and get these completion practices honed and then enlarge as we go forward. The first part was what again?

Just on well cost, Floyd, early on versus what you can see those go to on the TMS?

Well, of course, we expect improvement in trying to dredge up some information. We are hoping to be able to drill the early wells for around $13 million or so. And that's trouble-free wells, but we'll see how that goes. The trends from peers seem to be that if you can drill a trouble-free well that you can get the cost down. We don't really have a low-end number to throw out there at this time. That comes more when you've had 10 or 15 wells under your belt and you've really got things zeroed down. But we don't have any expectations of drilling really cheap wells out of the box.

Okay. And then, on a JV there, how would you see it? Would that be -- any ideas this early? I mean, would it be more of just a drilling carrier? Any ideas how that would be structured?

Actually, we had a lot of interest in the concept where, as I mentioned earlier, it's more of a luxury than a necessity, given our liquidity situation. We're going to see how that plays out. It would be -- it's hard to anticipate. Let's just look at it simply regardless of carries or whatever to bring in a partner on something. They pay their way, we pay our way. They reimburse us for the already-spent money and we go ahead as partners. So we'll just see how that plays out. As you know, we have stayed away from JVs in the past. Our situation is slightly different now. That seems appropriate, so we're looking at it pretty hard.

Okay. And then, last, just over to El Halcón. On -- I see on your type curve, it's based on the 750-foot spacing. One, do you see more opportunities for tighter spacing in there? And then, two, in El Halcón, I mean, are you still stepping out or are most of these wells are still in that kind of that concentrated area?

Well, the exciting thing is we are still stepping out to the south. We've just drilled and tracked our first well in -- down to the south end of the play in Burleson County. And we have a lot of the acreage down there. And as I mentioned on the call, that area is slightly deeper, slightly higher pressure, still oily. I mean, you've got -- you don't even have 5% gas in this play. That's like the TMS, by the way. So we're not drilling in a concentrated area whatsoever, but we are doing pad drilling in a lot of the areas. So in that way, it is quite concentrated. We have -- we raised our type curve, our EUR estimates for the area based on what we would say would be our representative wells. And those are the wells that we described with a minimum of 750 -- with at least 750 feet between wells and over 1,200 pounds of proppant per lateral foot. I think our actual practice right now is about 1,500 pounds of proppant per lateral foot. Keeping in mind -- and this is probably too long an answer. But the spacing is largely dependent on your -- what you've arrived as your final frac design. Everyone's job is to see how complex a frac that we can create near the well bore so as to have an efficient sweep and perhaps a slightly higher recovery factor in the reservoirs. So we're -- as that's been going on with other plays, we're still solving for that. So as the frac technology or technique improves, spacing will change. But right now, we're comfortable with this new estimate based on a 750-foot spacing.

And our next question comes from Steve Berman from Canaccord.

Floyd, the -- I seem to remember you had a bigger position in East Texas. You're selling 83,000 acres. What do you still have there? And also, on the Utica, no mention of that in the press release or the presentation. Just your current thoughts on that play.

Well, we still have some acreage in the Far East Texas that is not part of the sale, and it is not part of our El Halcón play. And we don't have any plans to drill that acreage at this moment, at this time. We're too busy at El Halcón. El Halcón is basically beginning over at the river at Brazos County in the Eagle and going down in the Burleson County for our part in the play. So we're selling out of the Leon, Madison and Grimes and those counties between all that. And we're focusing down on the East Texas Eagle Ford section, which is much like the -- much like some of the -- part of -- some of the play in South Texas and much like the Tuscaloosa Marine Shale.

And the Utica?

Utica. We're -- not have any -- we don't have any plans to move a rig in there at this time. We've got a well flowing back and a well resting. And we're going to just wait and see what the results are there. They haven't been too wonderful in the far north part of the play, and we're just going to see how we come out with these couple of new wells. It's no part of our spending for this year at this moment, and it's no part of our production expectations at this -- for this year at this moment.

And a quick question for Mark. Interest expense was way up this quarter. I assume you're capitalizing a lot less. Can you just give us some thoughts on that going forward?

Yes. The reason for that is the -- you're probably aware of the capitalized interest calculation is based on your unevaluated asset cost. And we did transfer a significant amount of that this year to the full cost pool, and that's into [ph] that impairment this year. So since that number has gone down, the amount of interest in capital -- the basis for calculating your capitalized interest has gone down. And therefore, this caused the expense line item on the income statement to go up.

And what percent of total interest will be expense this year as opposed to capitalized? Just the ballpark.

I think, capitally -- last time I looked, I think it's going to be around 60% will be capitalized this year.

And our next question comes from Jason Wangler from Wunderlich Securities.

Just curious in the TMS, as you -- as you're looking at that and being in earlier stage play, Floyd, what the infrastructure looks like. Is it going to be something similar to what you've done in the past with kind of bringing your team in to build that out as you develop the play? Or what's your thoughts there?

It would be similar with its own very specific differences. Similar in the fact that we've got our Halcón Field Services group, which are highly adept at early stage and permanent solutions to infrastructure issues. Different in that there's very little gas, no licks to speak of, unless you find that it's profitable to process. Early stage, we can truck oil from here. And this is low 40s gravity oil, so we don't have the sort of the high-octane problems that we've had, that the industry's had in some areas in some plays. Over time, we expect a better solution than trucking and a profitable solution. But early stage, we can truck. So we don't anticipate any real infrastructure issues early on. And through the course of the play, we would expect them to be opportunities rather than issues in terms of if we can reduce transportation cost or get those barrels little closer to the very best market, although they're quite close already.

And our next question comes from Brian Corales from Howard Weil.

And another one at TMS. Can you talk about what you paid for that acreage? And then, did all of that close in the fourth quarter? Or how much is still -- or is some of that going to hit in the first quarter as well?

We have -- we've got a little cleanup leasing, and we don't really talk about what we pay until we're done. Our overall cost in the play, very attractive, less than $1,000 an acre. A lot of it was spent last year, and there's some this year but not that much.

Okay, so okay. And all that's going to -- was in kind of your land budget for 2014?

Yes. We have some expectations of timing and what not involved in that. And as that matures, if we have a reason to change things, we will. But at this time, that's in our -- wrapped into our expectations. And of course, if we do a JV, it'll kind of change the landscape for us a bit. And we'll see how that -- we need to see how that plays out as well.

And then, just one on the Bakken. We've seen downspacing from both you and other operators. What do you -- I guess, what ultimately do you see for the number of wells per drilling unit? And what is your thoughts on kind of these deeper benches, the prospectivity there?

Again, it boils down to frac jobs and, overall, area spacing and perhaps staggering locations in the little benches relative to stacking. We have extreme high confidence, of course, in the Middle Bakken and the first bench of the Three Forks. In several areas, large areas, we have extreme high confidence in the second bench. The third and fourth benches are viable. They're not our immediate targets. We'll do some testing in those, as some others are as well. But we have so many locations between the Middle Bakken and the first bench and second benches of Three Forks. It's -- it would be several years before we really get into any extensive lower bench work. We're going to let some of our peers in the play do a little bit more of that than we will, right now. We just don't have a budget set up to do that kind of drilling. We have so many locations to drill. And we still don't know if it's going to be 660-foot spacing. These slickwater fracs are a major change. We're hoping that they've created a more complex near-wellbore frac, which would allow for tighter spacing. But then, you have to prove all that through performance. And so, that's what we're doing right now. We're going to drill all of our wells down in the core of the play this year. And this type curve thing that we've moved up is very real. And all of our kind of our modern, newer wells are exceeding the type curve, these slickwater fracs down in the reservation. So outlook up there is really strong. We'll just have to say that the industry is going to have to do some work on those lower benches to make them an attractive investment relative to the Middle Bakken and the upper 2 benches.

And just to clarify, I guess, you talked about 16 wells per drilling unit. And -- so that's all with the Middle Bakken and first bench of the Three Forks?

First and second bench.

Okay. First and second, okay.

And our next question comes from Dan McSpirit from BMO Capital Markets.

Recognizing it's early innings in the TMS, well results operated by Goodrich Petroleum have been mixed, whether you measure those rates in absolute terms or on a per-lateral-foot basis. I guess, 2 questions for that statement. Are you comfortable with the explanations, given that the issues are may be more mechanical than it is about the rock itself? And then, two, how might Halcón-operated wells be drilled and completed differently from where the laterals landed in the zone to maybe the use of clay stabilizers to treating pressures?

Yes. I'd rather change your question a little bit, or answer something slightly different than your question, Dan. We -- this play does not have the benefit of having 215 rigs industry-wide drilling in it yet, it will. It doesn't have that. And that's when the avalanche of new data comes to everybody. You've had a couple of pioneers out there drilling wells, and with some tremendous success and with some mechanical issues. We're very familiar with the issues. We're very familiar with our thoughts on how to work around those. We're sharing data with the other significant operators in the area. And we would expect that everyone's ability to get these wells drilled will improve with experience. So we'd rather think about what we're going to be doing rather than about what someone else did or didn't do. We're very comfortable with what we've seen on the effective length of some of these laterals that have been drilled, where some of the length has been lost due to mechanical problems, with what those wells are putting out. So if you normalize that into a normal length of lateral, in our case, we hope to be about 7,500 feet, you'd come to the right answer. So the great thing about the play is it's not about any certain company. We feel like we can understand and explain all the issues and we feel like there's workaround with experience and activity for those issues. I don't know if that's helpful but...

Yes. No, it is. And sticking on the subject of the TMS, your latest corporate presentation provides great detail on the play, particularly clay content, specifically smectite comparison. Are there other rock qualities unique to the TMS that could either create challenges or enhancements to ultimate recoveries?

We've got an expert on that sitting at the table. Charles, what do you say?

The rock qualities here are very analogous, very similar to our El Halcón. And we're the leader drilled in over 40 wells there. So if you want take one analog, it's -- this is the Eagle Ford shale. It's just a slightly higher clay content just like El Halcón is. But like we show there, the smec type, the swelling clay is your problem. But good thing is, they're a little bit lower. Now if they're a little higher in one particular section, then you want to avoid that section. But the good thing about the TMS is that it's very, very high original [ph] placed throughout the entire core play. So it's very consistent overall properties. We're -- so we're very comfortable in identifying what makes it work and how we're going to attack it.

Great. And if I could, just 2 quick follow-up questions here. If you spent another dollar on leasehold acquisition, Floyd, where would you put it, Bakken, Eagle Ford or TMS?

Well, the Bakken and the El Halcón are really hard to buy land in, and certainly hard to buy land in at a price that is really, really attractive. Not impossible, but difficult. We have such a critical mass in both of those areas that we're always looking for very small bolt-on things, but they're kind of few and far between. We have such a great amount of acreage now in the TMS. Any future acreage is likely just to be kind of mop-up stuff and not significant. We just -- we have great acreage in 3 -- really of what we believe will be a third strong play to add to our other 2 really strong plays. So I have another dollar, I don't know. I don't know. I've never had another dollar. I've always spent it.

And then, lastly here, just turning to the balance sheet. Where do you see leverage sitting at year-end pro forma for the asset sales, and with or without a JV?

Mark, do you have general comments on that?

Yes. We're projecting leverage to turn down as we round up the year and go into '14. Maybe call it 0.5 turn, maybe a little more. It will be somewhere in that ballpark.

And our next question comes from Robert Bellinski from Morningstar.

In the TMS, I was just wondering if you could talk a bit about if there are any challenges to drilling that extra lateral length versus what the industry norm is. As then, as a follow-up, does the additional lateral length compound any challenges with the completions or drilling those frac plugs? And if so, how?

Yes. Charles, why don't you address that? I will just say that additional lateral length in any kind of trouble scenario does -- can compound challenges. But we've analyzed this for a long time and we believe we can work through it. Charles, what do you have to add to that?

Yes. We're comfortable with what we've laid out. There's quite a lot of wells drilled the play to 7,200 feet and longer. But our norm in El Halcón, 7,500 to 8,000 feet. We drilled several wells over 9,000 feet there. We drill 10,000 feet every day in the Bakken. So we're very comfortable with targeting 7,200 feet for lateral length.

Okay, that's helpful. And moving to the Bakken, can you give your thoughts on the volatility and price differentials we've seen recently? And kind of what options are you looking at to try and preserve your price realizations there?

There's not a really attractive basis hedge there. It's quite expensive. So we market our oil and we turn it over to people as close to the wellhead as we can. And we're going to be subject to the volatility up there. I don't know. Mark, is there anything really to add to that? I mean, we've been doing pretty good up there in terms of realizations.

Yes. And we have trended down a little bit as we rounded out 2013. But we have maintained close to 90%, and we'll continue to look for opportunities where we can lock in differentials. We've had a few thoughts here at the company, but we just haven't gotten to a point where we've executed on any of them. So -- but price realizations have remained still attractive for us.

Robert, any of these new -- in the Bakken, certainly not new, but this explosion of additional production in any of these plays, it creates quite a displacement in terms of transportation and refinery capacities, and that's continually moving around. And it's no different from other plays. So we'll work through this as best we can. The safest way to do that is to always drill better and better wells, keep your cost down as best as you can. And that's your best hedge against that volatility. And we're doing that side of it quite well.

And last one for me, for Mark. Operating expense was higher this quarter. I was just wondering if you could give some insight on what drove that? And maybe if you can map that, how we get from the $12 per barrel of LOE this quarter to the $10 dollar guidance for 2014?

Probably the only item that I would point out that would first come to mind would be the weather conditions. That does drive the cost higher that we've experienced up in the Bakken. And we've spoken a little bit about that in this call and, in fact, its impact on production as well. And then, of course, we published guidance for 2014 for CapEx and operating cost.

Some of that is a simple math of selling off our higher-cost properties as we move forward and rendering our sales down to the most efficient operating cost profile as we can.

And our next question comes from Ron Mills from Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Floyd, early on at El Halcón you talked about drilling down further, I guess, southwest into Burleson County through [ph] it, and there have been some really strong results down there. If you look at your 100,000 acres, how does your position -- how is it split between Brazos and Burleson? And if you look at the 3 to 4 rigs you plan on running in that play, will they move between those areas? Or do you plan on having a set amount running in each portion of the play?

Well, as always, it's probably not appropriate to use an exact county line. So as you get down dip in Brazos County, you got quite an opportunity set as well that's a little bit different from the up-dip portion where we started. If I would -- I would say it's going to be about half and half between rigs and between the areas that are slightly higher pressured. The great news for us is, and as it turned out in some of our prior activities, we think 100% of our acreage is in the core of the play. And the part that is up in the center and northern part of Brazos County is really good. And the part that's down to the south is really good as well. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Is it fair to assume that the type curves that you have, that you recently increased, that's primarily based on data from the up-dip portion? And is there potentially even upside for the down-dip portion just due to some greater depths, greater pressures and maybe even a little bit more gas to help?

Having only got 40 or I don't even know if it's 45 wells on production and room for 1,000 wells or some number like that, there's tremendous room for increases. We've had several wells that are going to be producing well in excess of 600,000 and 650,000 barrels. We've had some that are less. The type curve expectation that we have now is based on the data sweep that we've done so far. And it's based on a representative well with a representative length and spacing -- representative spacing based on data that we have today and representative propping, so much proppant per lateral foot. There is clearly room for all of those things to improve. Right now, we put out a type curve that the average -- our view of the average for our part of the play. Yes, you could -- it could evolve into something where you have a slightly different type curve to the south. But we haven't -- we or no one else has done enough drilling to suggest that just yet, but it could turn out that way. So early stage, and you got a bunch of smart people in the play, and we've got a bunch of smart people on staff, there's tremendous room for enhancement. I won't say improvements because it's pretty damn good already. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Right. And then to follow on, on one of Brian's earlier questions. As you look at the Fort Berthold area in the Bakken and the Middle Bakken upper and first benches, when you look at this year's program with all the activity in that area, are you starting to move to some full-pad development across all those zones? Or how does your 2014 plan look between the benches?

Charles, correct me. And we don't -- I mean, I'm not prepared to give an exact number. But I think we're drilling everything from pads. I think most of the drilling spacing units require a couple of pads, sometimes one on each end. And sometimes, you're drilling in 2 different directions from pads. And some of the layout there, we're even building east-west wells, which are working out just fine. I would say it's probably, overall, Charles, maybe 1/3 first bench, and 2/3 Middle Bakken with a few second bench wells thrown in. Is that fair?

Yes. That's pretty close. And it is 100% pad drilling right now on the reservation.

So wherever we can, it's also batch drilling and batch frac-ing. And as everyone else has experienced, you get a little bit of a lumpy month-by-month look over the year that evens out. And you have these huge surges of production coming from a newly-put-on-production pad with 3 or 6 or 7 or 8 wells on it. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then, on the TMS, you had the slide that has a lot of good information. The -- when you look at the lateral placement, the well-defined is what you talked about, your planned practice. Is the focus going to be in the lower portion of the TMS, which looks to be a little better rock quality and a little lower clay content, or maybe if it's similar clay, more smectite? And when you just go from current practice to what you plan, what were some of the drivers in that decision? And maybe, it's a Charles' question.

Yes. This is pretty much Charles' question. One thing that's for sure, our laterals will be positioned in the lower section, but the upper section contributes as well. And all of our estimates have really given no nod to contribution from the upper section versus what we think we can get out of the lower section. Charles, what do you have to say about it?

No, that's exactly right. We're going to target the lower 1/3 of the interval, and that is where the best rock properties are. And also is the interval that allows you to get the most efficient frac design and get the highest recovery factor. So... Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And should we assume those wells are spread kind of evenly over the remainder of the year? And am I correct in just the reverse engineering of the map that, on that position, you have roughly a 65%, 70% average working interest in the wells? So if I'm assuming kind of $13 million, $13.5 million well cost?

I don't know if we quite published an average. That could be about right. It's going to be a little bit over the board -- across the board. We don't really have agreements on every single location we planned quite yet. The first few are all figured out. I think those are about 70% to 72% average, the first several locations. After that, we'll just have to work through it and see what other operators are involved, and if there's any unleased interest, if they're going to be participating there, or if they're going to want to lease there. There's some -- the great news is we've got a very blocky group of leases, and we don't have a lot of -- I mean, the details of -- the devil is always in the details. But we don't have a lot of cleanup leasing to do. So we're going to get this thing off to a really good start this year. We'll look for huge impact in 2015. This year would be a bit of learning. There is learning going on and some positioning and so on and so forth. But it's an attractive way for us to build a high-growth year without any requirement of impact from this play at this time.

And our next question comes from Amir Arif from Stifel. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Couple of quick questions. First, just on the TMS. First off, it's going to start growing here in March. So I was just curious, are you bringing the second rig in at the same time? Or are you waiting till you'll get some results from your first well before you start picking up activity?

We'll bring the second well rig in, in April. We will be watching results as the year progresses. If we find some reason to change our outlook at just keeping 2 rigs running, we'll do that. We've got a great spot that we can move rigs around between El Halcón and the TMS, without a lot of trouble and not too large an expense. So we expect there to be some learning going on, but we'll watch our -- be watching our results really hard, and we'll react accordingly. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay. And, Floyd, in terms of early results. So for the first well, are we to expect results in May through the completion production -- the initial production results?

Charles, help me out here. But we got kind of 50 days of drilling projections, and another 30 to 60 days of frac-ing and getting online. Is that about right?

That's about right, yes.

We got a good 3 to 4 months -- between 3 and 4 months. Later on, you would expect that to get down to 60 days or 70 days. But early on, 3 or 4 months. So you've got a better well in March. You might be frac-ing it in what? June, early June? Is that right, Charles?

Yes. We'll be slowing back about then.

In early June. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: On June, okay. And then, just shifting to the Utica. I know you're not doing anything there. Well, you do have 140,000 acres. Any -- can you just let us know if any acreage explorations start hitting in '15, or just your thoughts? Are you looking to monetize that potentially down the road? Or are you going to be patient with that, given the lease terms?

We can be extremely patient. We don't have any significant requirements for payments or expiries at this time. A little over half of our land is held by shallower, more shallow production, anyway. So we're in a great position to be patient. There's some other great companies that have been drilling wells up there. We have been working to get all of the wells -- not all, we've only drilled like -- and some of the wells took a while to get on because of their distance from infrastructure. So we've been making sure to get them all on and making sure that we understand what we've got up there. So it's just not a key part of our planning at this moment. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay. It makes sense. And then, just final question. In 4Q, you sold 4,300 barrels a day. Just curious, how much of those volumes were in the 40,200 barrels that were reported? I think you sold them in 3 tranches during the quarter sometime.

No. Between the -- I think it was around -- and I think Steve might be in the room. Was it about 4,000 barrels a day, Steve?

The 3 noncore sales that closed in the fourth quarter were a total of about 4,500 a day BOE net. 2 of them closed in October and 1 closed right before Christmas. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay. So if I strip out, let's say, 3,000 from the 40,000, that would take me to about 37,000 as a run rate just for that sale. Is that fair?

Roughly. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay. So then, just -- how do you compare that to the -- to your 1Q guidance? Is it just natural declines and the delays of completions for the Bakken? From -- in terms of comparison, the 37,000 to the 30,000 -- the guidance you've given be for 1Q, the 34,000 to 36,000?

Well, we've had the opportunity to see delays from weather up in the Bakken, so that's played a factor. I prefer that we and you rely on our full year guidance and understand that there's moving pieces every single quarter. The important thing to us is that we didn't change guidance because of the sale that we anticipate closing early in the second quarter. And we didn't change guidance because of the weather-related issues. This is 100% due to expectations of continued higher IPs on the wells that we're drilling because of continually fine-tuning our completion practices and our drilling targets. And I think that should be the takeaway from all that rather than somebody thinking our guidance is lower, whatever. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Yes. I was just trying to understand the moving pieces in 1Q. But yes -- and so the 60% pro forma growth, if I just look at it year-over-year, is it roughly equal in the Bakken versus the East Texas? Are both areas growing roughly the same?

[indiscernible] basis the Bakken is just a larger piece of the puzzle. Steve, is there any way to give a good answer to that question or not? Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Are both areas growing roughly at the same 50%, 60% growth this year, year-over-year?

Well, the -- actually, the El Halcón, being smaller is going to grow.

Yes. Percentage-wise, El Halcón can grow by far the most.

And our last question will come from Andrew Coleman from Raymond James. Andrew Coleman - Raymond James & Associates, Inc., Research Division: I guess the last one that I had remaining that hasn't been asked already was you all talked about the Broadway, I guess, reentering the Broadway well. I guess where does that fall in the capital plans kind of with the big expansion of leasehold in the TMS?

It doesn't fall within another current plan for either '14 or '15. That could easily change if there's some other activity over there. But the acreage to the east is why we think the Broadway is viable. The acreage to the east is clearly in the oily core of the play, and we're going to focus a lot of our spending over there. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Okay. And then, I guess, did you mention earlier in your prepared remarks, at the beginning, any comments on timing of a potential JV or just...

We would expect to have our thoughts gathered on that towards the end of this quarter, and be in a position to either go or no go on the idea of a JV. We want to make sure it's attractive to us and, of course, to any partner. We want to make sure it's attractive to them. And we don't really need it. So we do have the luxury of being patient about it to make sure that we can find a like-minded partner that sees the opportunity as we do. And we'll discuss and see how it plays out. Listen, thanks, everyone, for joining. And if there's something that we didn't answer, just feel free to give us a call. Thank you.

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