Battalion Oil Corp (BATL) 2013 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Halcon 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're 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 non-core 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 was over 600% in 2013. Organic reserve growth was over 60% in 2013. At year end, we estimate net un-risked 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 we'll absorb -- the divestment that we announced yesterday. And despite delays due to 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 two de-risk core plays -- those are the Williston Basin and El Halcon in East Texan.

And, importantly, we've increased our [a-list] from its EUR estimates in both plays based on performance, especially performance from new frac design. Today also -- yesterday, we announced our TMS Tuscaloosa Marine Shale position greatly enlarged and focused on Eastern portion of the play.

Within the next couple 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 core of the play. Company-wide, we currently have 29 operated wells being completed or waiting on completion. We're offering about eight rigs today in the Williston Ford El Halcon. 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 -- that's Fort Berthold. We expect to spend a little less -- just barely less than half of our drilling completion CapEx in 2014 in the Williston Basin. We expect to drill 100% of our 2014 wells off pads versus a little less than 75% last year.

We've increased the average type curves, or our EUR estimates, in all areas based on improved results related to drilling and completion modifications. One of the big improvements have been slick water fracs. We started with those up in Williams County area and they were very successful.

We started down in Fort Berthold with those and they're meaningful outperforming our new type curve. Our new type curve is 801,000 barrels of oil equivalent per well of these new wells in the south are outperforming that type curve.

That's an average type curve for the entire play, except for Williams County. We plan to complete all future wells in Williston Basin with slick water fracs. Continued downspacing there has yielded real success and has 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. Profit-type pumping services, drilling efficiencies, rig days, full-scale batch drilling, electrification of much of our field -- these all remain a focus as we expect some decrease this year on completed well cost by hopefully 5% to 10%. In East Texas, at El Halcon, production grew from a few 100 barrels of oil equivalent per day in January, to over 700,000 barrels per day in the fourth quarter of 2013. Expect that trend to continue. Hold on three or four rigs there for all year.

We expect to spend about 40% of our drilling and completion CapEx at 2014 in the El Halcon. We've exceeded our goal of 100,000 tier 1 net acres in the play. We are confident that all of our acreage in the core of the play.

We've increased the El Halcon 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 prop and 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 cost and increase performance. And we are working to find the most economic completed lateral length. And 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 Burlington County look to be the best wells in the play -- they're slightly deeper, slightly higher pressure, hopefully slightly more prolific. We expect low cost to continue to decrease at El Halcon.

We've had some wells that were dramatically less money. We'll just have to see how that goes. You can say for sure the El Halcon is the real deal. Over in Mississippi and far eastern Louisiana, we talked about -- for the first time publicly -- our Tuscaloosa Marine Shale play yesterday, 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 had some challenges with completion design, but we are pretty well comfortable with what those challenges have been and the workaround for those. About over 75% of our acreage is in 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's going to be working this play now for over a year, and in our prior histories we've looked at the play before as well. Our full drilling and completion's 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 two teams.

This is a large, concentrated, highly operated position with favorable lease terms, and these provide for efficient resource development. And it's in a great operating environment -- [Pearl] oil and gas, as everyone knows, and access to some of the better crude oil markets in the United States.

We have data-sharing agreements with all the other operators and -- as we've had in all of our prior successful plays, and this will 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'll expect to finalize our thoughts on this during the second quarter of this year. Not too much of our budget, drilling and completion will go towards the TMS, about 10%. And we are expecting almost no production from it this year because of the early stage.

So all of our growth is going to come from our two existing core areas in which we've 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, then 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 oil equivalent per day, which is 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 $1,144 per BOE in 2013, which is below the midpoint of guidance, and about 20% lower than in 2012, just due to efficiencies in the areas that we're operating in.

After adjusting for 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 to touch on before turning to liquidity in our 2014 spending is the non-cash, full-cost full impairment charge that was taken in the fourth quarter for $239 million. You may recall we had a non-cash charge in Q3 of about $900 million related to unevaluated property costs that were transferred into the pool with little to no reserves associated with them.

And then the fourth quarter of this year we have an additional non-cash 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 $850 million from $710 million in conjunction with our regular fall re-determination. Subsequent to the re-determination we executed on some non-core 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 [against] a current volume basis of $700 million.

We ended the year with undrawn revolver capacity in 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 dollars.

Additionally, we're going to initiate our spring borrowing base predetermination next week and we expect an increase based on the year-end reserve report. We do not expect to have 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 at El Halcon in the Bakken that had not been budgeted for in 2013. This drilling did generate additional production that 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. While we do have a front end-loaded 2014 drilling program, we expect spending to stay within recently published guidance.

In 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 a equivalent basis pro forma for all acquisitions 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 sold in the fourth quarter of 2013 and that relating to the pending sale of the East Texas assets I would expect to close in the first part of this year. 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 do continue to build out a hedge portfolio where we look 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, and 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, if our hedging portfolio for 2014 is fairly complete, we're going to continue to layer in hedges in 2015 and 2016 to try to build to our target levels.

And, with that, I'll turn the 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 at El Halcon. We'll spend all of our 2014 budget in the sweet spots of those two core plays.

The TMS is a early stage play. We're not anticipating hardly any production from that for this year, but it'll build into 2014 and 2015. We expect to drive future production growth and achieve higher rates of return across our asset portfolio through a 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 ready for a few questions now, if there are any.

Thank you.

(Operator Instructions)

Neal Dingmann, SunTrust.

Good morning Floyd and Mark.

Floyd, on the TMS two quick questions there. First, what are you assuming on early well costs and how do you think that changes?

And then, just on 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 are you going 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 were 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 the well costs. Early on versus what you could see those go to on the TMS.

Of course we expect improvements, and I'm trying to dredge up some information. We're hoping to be able to drill the early wells for around $13 million or so, and that's a trouble-free well; but we'll see how that goes. The trends from Peters seems to be that if you can drill a trouble-free well, you can get the cost down.

We only 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. We don't have any expectations of drilling really cheap wells right out of the box.

Okay. And then on a JV there, how would you see it? Any ideas yet early? Would it be more of just a drill and carry, or any ideas how that would be structured?

Actually, we've had a lot of interest in the concept. As I mentioned earlier, it's more of a luxury than a necessity given our liquidity situation. Were going to see how that plays out. It's hard to anticipate.

If you just look at it simply and regardless of carries and whatever, to bring in a partner in something -- they pay their way, we pay our way. They reimburse us for the already-spent money, and we go ahead, as partners.

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, and it seems appropriate; so we're looking at it pretty hard.

Okay lastly, just over to El Halcon. I see on your type curve it's based on the 750-foot spacing, one. Do you see more opportunity for tighter space in there?

And then two, in El Halcon are you still stepping out? Or are most of these wells still in that concentrated area?

Well, the exciting thing is we are still stepping out to the South. We just drilled and fracked our first well down to the south end of the play in Burleson County. We have a lot of acreage down there. And as I mentioned on the call, that area is slightly deeper, slightly higher pressure, still oily.

You don't even have 5% gas in this play -- much 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, and that weight is quite concentrated.

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 we described with a minimum of 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 what you arrive at as your final frac design.

Everyone's job is to see how complex a frac that we can create nea the wellbore so as to have an efficient sweep and perhaps a slightly higher recovery factor in the reservoir. So we're [as synchronized] as going on with other places, we are still solving for that.

So as the frac technology or technique improves, spacing would change. But right now, we're comfortable with this new estimate based on that 750-foot spacing.

Great details. Thanks, Floyd.

Steve Berman, Canaccord Genuity.

Good morning.

Floyd, I seem to remember you had a bigger position in East Texas 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 Halcon play. And we don't have any plans to drill that acreage at this moment at this time. Were too busy at El Halcon.

El Halcon is basically beginning over at the river at Brazos County and then going on down into Burleson County for our part of the play. So we're selling out of the Leon, Madison and Grimes and those counties in between all that.

And we're focusing down on the East Texas Eagle Ford section, which is much like some of the play in South Texas and much like the Tuscaloosa Marine Shale.

And the Utica?

Utica. You know, we don't have any plans to move a rig in there at this time. We have a well flowing back and a well resting. And were 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 were 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 for this year at this moment.

And a quick question for Mark.

Interest expenses was way up this quarter. I assume you're capitalizing a lot less. Can you give us some thoughts on that going forward?

Yes. The reason for that, as you probably are aware, capitalized interest calculation is based on your unevaluated asset costs. And we did transfer a significant amount of that this year to the full-cost pool and took 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 has caused the expense line item on the income statement to go up.

And what percent of total interest will be expensed this year as opposed to capitalized, just a ballpark?

I believe last time I looked, it going to be around 60% will be capitalized this year.

Okay. That's it for me. Thank you, guys.

Jason Wangler, Wunderlich Securities.

Good morning.

Just curious in the TMS as you are looking at that being in another stage play, Floyd, what the infrastructure looks like.

And 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 are your thoughts there?

It will be similar with its own very specific differences.

Some are in the fact that we got our Halcon 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 liquids 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 high-octane problems that the industry's had in some areas of some plays. Over time, we expect there's a better solution than trucking in 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 costs or get those barrels a little closer to the very best market, although those are quite close are ready.

That's helpful. Thank you.

Brian Corales, Howard and Weil.

Hi, guys. Another one at TMS.

Can you talk about what you paid for that acreage? And then, did all that close in the fourth quarter, or is some of that going to hit in the first quarter?

We have a little clean-up leasing, and we don't really talk about what we pay until we're done. Our overall cost in the play is 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, and all that was in your land budget for 2014?

Yes. We have an expectation of timing and whatnot involved in that. And as that matures, if we have a reason to change things, we will. But at this time, that's wrapped into our expectations.

Of course if we do a JV, it will kind of change the landscape for us a bit. And we need to see how that plays out as well.

And then just one on the Bakken.

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

Again, it boils down to frac jobs and overall theory of spacing and perhaps staggering locations in the lower 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 will 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 bench of the Three Forks, it would be several years before we'd 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. Obviously, 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 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. This type curve thing that we've moved up is very real. And all of our kind of modern, newer wells are exceeding the type curve using these slickwater fracs down on the reservation. So [part of the cut] 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 two 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. Thanks, Floyd.

Dan McSpirit, BMO Capital Markets.

Thank you folks, good morning.

Recognizing it's early innings in the TMS, the oil results operated by Goodrich Petroleum have been mixed, whether you measure those rates in absolute terms or on per-lateral-foot basis. I guess two questions to that statement.

Are you comfortable with the explanations given that the issues are maybe more mechanical than it is about the rock itself? And then two, how might Halcon-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?

You know I'd rather change your question a little bit. Or answer something slightly different than your question, Dan. This play has not had the benefit of having 10 or 15 rigs industry-wide drilling in it yet. It will.

It just hasn't had that, and that's when the avalanche of new data comes to everybody. We've had a couple pioneers out there drilling wells and with some tremendous success. And with some mechanical issues.

We are very familiar with the issues. We're very familiar with our thoughts on how to work around those. Were 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 would rather think about what we are going to be doing rather than about what someone else there didn't do. We're very comfortable with what we've seen on the effective length of some of these laterals that have drilled, where some of the length has been los due to mechanical problems with what those wells are putting out.

So if you normalize that into a normal length of lateral -- and in our case we hope to be about 7,500 feet -- you come to the right answer.

So the great thing about the play, and it's not about any certain company, is we feel like we can understand and explain all of the issues. And we feel like there's workaround with experience and activity for those issues.

I don't know if that's helpful.

It is. And sticking on the subject of the TMS, your latest Corporate presentation provides great detail on the play, particularly clay content, specifically a spec-type comparison.

Are there other rock qualities unique to the TMS that could either create challenges or enhancements to ultimate recoveries?

You know, 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 Halcon, where we're the leader and drilled over 40 wells there. So if you want to pick one analog, this is the Eagle Ford Shale.

It's just a slightly higher clay content, just like how El Halcon is. But like we showed there, the [smag] type, the swelling clays are your problem; and the good thing, is that they're a little bit lower. Now, if they're little higher in one particular section, then you want to avoid that section.

But the good thing about the TMS is it's very, very high original and placed throughout the entire core of the play. So it's very consistent overall properties. 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 two quick follow-up questions here.

If you spent another dollar on leasehold acquisition, Floyd, where would you put it -- Bakken, Eagle Ford, or TMS?

The Bakken and the El Halcon are really hard to buy land in. And certainly hard to buy land in at prices that are really, really attractive. Not impossible, but difficult.

We have such a critical mass in both of those areas. We're always looking for really small quotes 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 acreages is likely to be just kind of mop up stuff and not significant.

We have great acreage in three really, what we believe, will be a third strong play then to our other two really strong plays. So if I had another dollar -- I don't know. I've never had another dollar. I've always spent it.

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

Mark? Do you have any general comments on that?

We are projecting leverage to trend down as we round out the year and go into 2014. Maybe call it half a term, maybe a little more. It'll be somewhere in that ballpark.

Okay great. Thanks again.

Robert Bellinski, MorningStar.

Good morning, everybody, and thanks for taking my call.

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

Charles, why don't you address that?

I will just say that additional lateral length in any kind of troublesome area 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?

We're comfortable with what we've laid out. There's been quite a lot of wells drilled in the play to 7,200 feet and longer. But our norm in El Halcon is 7,500 to 8,000 feet.

We've 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.

Moving to the Bakken, can you give your thoughts on the volatility and price differentials we've seen recently? And what options are you looking at to try and preserve your price realizations there?

You know, there's not a really attractive basis hedge there. It's quite expensive. We market our oil, and we turn it over to people as close to the wellhead is we can. And we're going to base that because of the volatility up there.

I don't know -- Mark, is there anything really to add to that? We've been doing pretty good up there in terms of realizations.

Yes. We have trended down a little bit as we rounded out 2013. But we have maintained close to 90%, and we will continue to look for opportunities where we can walk 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. But price realizations have remained still attractive for us.

Robert, any of these new --the Bakken is 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 it as best we can.

The safest way to do that is to always drill better and better wells to keep your cost down as best you can, and that's your best hedge against that volatility. We're doing that side of it quite well.

Good deal. Last one for me -- for Mark.

Operating expense moved 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 guidance for 2014?

Probably the only item that I would point out that would first come to mind would just be the weather conditions. That does drive cost higher than we've experienced up in the Bakken.

And we've spoken a little bit about that in this call and its impact on production as well. And then of course we've published guidance for 2014 for CapEx and operating costs.

Some of that's the simple math of selling off higher-cost properties as we move forward, and dwindling our sales down to the most efficient operating cost profile as we can.

Okay, I appreciate it, gentlemen. Thank you.

Ron Mills, Johnson Rice.

Early on at El Halcon, you talked about drilling down further I guess southwest into Burleson County. And there been so 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. As you get downdip in Brazos County, you've got quite an opportunity set as well. It's a little bit different from the update portions from where we started.

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, as it's turned out of some of our prior activities, we take 100% of our equities in the core of the play.

And the part that is up in the center, in northern part of Brazos County, is really good. And the part that's down to the south is really good as well.

Is it fair to assume that the type curves that you have that you recently increased, that's primarily based on data from the updip portion?

And is there additionally even upside for the downdip portion just due to some greater depths, greater pressures, and maybe even a little bit more gas to help?

No. Having only 40 -- I don't even know if it's 45 wells -- on production and room for a 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 600,00 and 650,000 barrels. The cut is under 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 propping per lateral foot. There's clearly room for all of those things to improve.

Right now we put out a type curve that's our view of the average for our part of the play. Yes, it could evolve into something where you have a slightly different type curve to the south that 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've 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 improvement because it's pretty damn good all ready.

And then to follow 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 whole-pad development across all those zones? Or how does your 2014 plan look between the benches?

You know, Charles, correct me. And 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 two different directions from pads. And some of the layout that we've been drilling, east-west wells, which are working out just fine.

I would say it's probably overall, Charles, maybe one-third first bench and two-thirds Middle Bakken with a few second bench wells thrown in Is that fair?

Yeah, 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 fracking.

And as everyone else has experienced, you get a little bit of a lumpy month-by-month look. Over the year it evens out and you have these huge surges of production coming from a newly put-on production pad with three or six or seven or eight wells on it.

Okay. And then on the TMS the side, that has a lot of good information. When you look at the lateral placement, the well defined is what you talk 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, a little lower clay content?

Or, maybe if it's similar clay more SNEK tight? And when you just go from current practice to what you planed, what were some of the drivers in that decision? And maybe that's a Charles question.

I think it's pretty much a 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 the contribution from upper section. Is what we think we can get out of the lower section.

Charles? What do you have to say about all this?

That's exactly right.

We're going to target the lower third of the interval, and that is where the best rock properties are. And also the area there allows you to get the most efficient frac design and get the highest recovery factor.

And should we assume those wells are spread evenly over the remainder of the year? And am I correct -- is this the reverse engineering on the map that on that position you have roughly a 65%-70% average working interest in the wells, if I'm assuming $13 million or $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 or 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 just have to work through it and see what other operators are involved and if there's any unleashed interest. If they're going to be participating, are they going to want to lease or there's some -- the great news is we got a very blocky group of leases, and we don't have a lot 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 will look for a huge impact in 2015. This year there will be a bit of 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.

Perfect. Thank you for all the info today.

Amir Arif, Stifel Nicholas.

A couple of quick questions.

First, on the TMS -- first of all, it's going to start growing here in March. I'm just curious. Are you bringing the second rig in at the same time, or are you waiting until you get some results from your first well before you start picking up activity?

We're putting the second rig in, in April. We will be watching results as the year progresses. If we find some reason to change our outlook of just keeping two rigs running, we will do that.

We've got a great spot that we can move rigs around between El Halcon and 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 be watching our early results really hard, and we'll react accordingly.

And, Floyd, in terms of early results -- for the first well, would you expect results in May through the completion production, the initial production results?

Charles, help me out here.

But you've got kind of 50 days of drilling projections and another 30 to 60 days of fracking and getting online. Is that about right?

That's about right, yes.

So you've got a good three to four months -- between three and four months. Later on, you would expect that to get down to 60 days or 70 days; but early on, three or four months. So we just got a well in March; we might be fracking it in -- what, June? Early June?

Is that right, Charles?

Yes, we'll probably pull it back about then.

Pull it back in early June.

Okay. And then shifting to the Utica. I know you're not doing anything there, but you do have 140,000 acres.

Can you let us know if any acreage expiration starts hitting in 2015? Or just your thoughts -- are you looking to monetize that potentially down the road, or can you be patient with it given the lease terms?

We can be extremely patient. We don't have any significant requirements for payments or expiries at this time. Well over half of our land is held by more shallow production anyway.

So we're in a great position to be patient for some other great companies that have been drilling wells up there. We have been working to get all the wells -- not all, we only drilled like 10. ¶

But some of the wells took awhile to get on because of their distance from infrastructure. So we've been making sure we get them all on and make sure that we understand what we've got it there. So it's just not a key part of our planning at this moment.

Okay. Makes sense. And 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 had sold it in three tranches during the quarter some time.

I think it was around -- I think Steve might be in the room.

Was it about 4,000 barrels a day, Steve?

The three non-core sales that closed in the fourth quarter were a total of about 4,500 a day, DOE, net. Two of them closed in October ,and one closed right before Christmas.

So if I stripped out, let's say, 3000 from the 40,000, that would take me to about 37,000 as a run rate, just for that sale? Is that fair?

Roughly.

So then how you compare that to your 1Q guidance? Is it just natural declines in the delays of completions from the Bakken? In terms of comparing the 37,000 to the guidance you've given 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 usually rely on our full-year guidance and understand that there are moving pieces every single quarter. The important thing to us is that we didn't change guidance because of this 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.

I was just trying to understand the moving pieces in 1Q. But so the 60% pro-forma growth, if I just look at year over year, is it roughly equal in the Bakken versus the East Texas? (Multiple speakers).

The Bakken is such a larger piece of the puzzle.

Steve, is there any way to give a good answer to that question?

Are both their lean [square] roughly at the same 50% to 60% growth year over year?

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

Percentage-wise, the El Halcon is going to grow by far the most.

Okay. Sounds good. Thanks for the color, guys.

Andrew Coleman, Raymond James.

Thanks for taking my questions.

I guess the last one that I had remaining that hasn't been asked already was, you all talked about re-entering the Broadway well. Where does that fall in the capital plans, with the big expansion of leasehold in TMS?

It doesn't fall within our current plan for either 2014 or 2015. That could easily change if there's another activity over there.¶

But the acreage to the east, is while 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 all of our spending over there.

Okay. Thank you.

Did you mention early in your prepared remarks at the beginning, any comments on timing of a potential JV or?

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, any partner would want to make sure it's attractive to them. 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 see how it plays out.

Okay. Great. Thanks a lot.

Thanks everyone for joining. And if there's something 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. [ Event Concluded ]