Battalion Oil Corp (BATL) 2013 Q2 法說會逐字稿

Good day, ladies and gentlemen, and thank you for standing by and welcome to the Halcon Resources second quarter 2013 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, today's conference may be recorded. It is now my pleasure to turn the floor over to Floyd Wilson, Chairman, and CEO. Please go ahead, sir.

Thanks. Good morning, everyone, and thanks for joining.

This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued this morning.

We had a pretty good quarter. And it continues. Currently we are producing about 35,000 barrels of oil equivalent per day, mostly oil. Our discovery well in Trumbull County, Ohio, in the Utica, the Kibler 1H, came in at 2233 barrels of oil equivalent per day, 75% oil and NGLs. This well is one of the top producers in the play, and we have room for about 500 wells in that area.

In the Williston Basin, we set another completion with the well at Fort Berthold, 3317 barrels of oil equivalent a day. At El Halcon, we are drilling ever longer laterals than most of our new wells coming in between 1000 and 1300 barrels of oil equivalent per day. We're becoming in more efficient in all of our core areas via modifications in both drilling and completion practices. And we are becoming a more concentrated producer through divesting, continued divesting of noncore assets.

Activity company-wide has increased over the past couple of months. In the third quarter, as a result in the third quarter, we'll put about 30% more wells on line than we did in the second quarter. Drilling wise, the front half has been front-end loaded and the first half has been front end loaded for us. That's the second time that at the present time we are running 11 rigs down from 16 last quarter. Part of the drop in rig count can be chalked up to efficiencies with rigs, fewer rig days per well, and the other part can be watched by us watching our capital budget and our spend. We will begin to add rigs to prepare for 2014.

As to our core plays, in the Williston Basin we have completed the process of transitioning our rig fleet to a modern fleet of rigs suitable to support full scale pad drilling. The primary driver for improvements and production we're achieving across our assets in the Williston Basin have to do with modifications in well design and fracs.

In Williams County, we have settled on using slick water fracs. We think this is a game changer. Results suggest that IRRs on those wells can more than double from what they used to be. We are seeing an average increase of over 80% on IP rates using slick water fracs in Williams County. We operate over 75,000 net acres in Williams County, which is very lightly drilled. We are very excited by the potential up there.

At Fort Berthold, we continue to set record IPs almost weekly. We have increased profit and concentration, saved the density, changed the fluid design, and gone to plug and perf on all of the wells. Based on our recent success in Williams County, we are trying our first slick water frac at Fort Berthold this month.

We are conducting down spacing tests at Fort Berthold and expect results by year end. We expect to gain a better understanding of efficient drainage in the middle Bakken and the different Three Forks benches to our efforts as well as through our working interest in other down-station spacing tests in the region.

We have redirected capital in east Texas from the Woodbine to El Halcon for the remainder of this year. Activity in the Woodbine may pick up early next year when we receive the data from our large 3-D seismic shoot. We hope that data will help us identify additional sweet spots and avoid hazards in this complicated area.

At El Halcon, we continue to make progress towards our goal of over 100,000 net acres. We recently set a company record at El Halcon by hitting a target -- by hitting target depth in the well in less than 11 days. This sort of improvement has a major impact on economics.

Up north, we are really excited about our Utica/Point Pleasant asset. Our delineation drilling is complete, and we made our decision as to where we will focus our capital in the play for the next couple of years.

The test result for the Kibler 1H in Trumbull County, Ohio and the Allam 1H in Venango County, Pennsylvania were excellent. The Kibler 1H test results compare favorably with the better wells in the entire play, north or south. The well tested better in all but 10 across the entire play. We have significant holdings in Trumbull and Mahoning counties with the potential to drill hundreds of wells the that area.

The Allam 1H is one of the more important wells in the plays, as far as I'm concerned, proving that the play can be commercial far to the northeast. We recently reinitiated our leasing efforts in very specific areas and we continue to be focused on building an inventory on permitted multi-well pads in preparation for full scale development. This year we will keep at least one rig active up there, that will be drilling in the Kibler area.

Also up north, Halcon Field Services is moving forward with our infrastructure plans. HFS has entered into an exclusive arrangement with the Ohio Commerce Center, which is a mixed-use industrial site, located in Lawrencetown, Ohio to develop an oil storage and rail loading facility. HFS and OCC have obtained the permit to build the facility. OCC has over 12,000 feet of recently installed rail, and access to multiple class one rail carriers, making it an ideal location for low cost rail services to support the rapid production growth in Trumbull and Mahoning counties.

We'll build the terminal in phases, the first of which will go into service by the end of the year. At scale, the facility can accommodate unit trains at the rate of 140,000 barrels per oil or condensate per day. The project is on track for environmental clearance and permits and internal approvals within several weeks.

In addition, Halcon Field Services continues engage in discussions for potential joint ventures, to develop pipe pressure, rich gas gathering systems, and cryogenic processing in Ohio and Pennsylvania. These potential joint ventures would provide for third party volumes and shared capital cost for build out in the play.

Mark will now go through the financial results for the quarter.

Okay. Thank you, Floyd. For the current quarter we did close to the public offering of 5.75% cumulative actual convertible preferred stock, which yielded net proceeds to the company right at $335 million we used to repay a portion of the outstanding indebtedness under our senior secured bank credit facility.

With regards to liquidity at quarter end, we had just over $500 million of undrawn capacity on our bank line. And as a result of the Eagle Ford property sale, for $144 million, the borrowing base was reduced by $40 million. So it was $850 million, it currently is at $810 million. The next borrowing base redetermination will be in October of this year, and we do expect an increase at that time.

As mentioned in the earnings release, our oil and midstream subsidiary, Halcon Field Services is moving forward in the Utica Point Pleasant. And as such, we formally kicked off a process to establish separate borrowing capacity for this business. And we are going to look to have that in place with conjunction with the fall redetermination. Since this business is becoming more valuable and material to HK, you will notice we have broken out gathering expense for the first time on the face of the income statement.

We produced an average of 29,165 barrels of oil equivalent a day, which is 12% higher than the first quarter of 2013, our first quarter production rate, and that was also above the high end of our guidance range of 27,000, to 29,000 BOE a day.

From a cost perspective, taxes other than income were $7 per BOE for the second quarter. Which was at the low end of our guidance range, and was down slightly from the $7.44 per BOE level in the first quarter of this year.

Lease operating expense declined significantly when compared to prior year by about 45%. It came in at $11.99 per BOE in the second quarter. And although it was over the high end of guidance, due to an increase in the cost of electricity, fuel, and water handling, which was mainly in the Bakken due to weather conditions.

Second quarter adjusted G&A expense of $10.79 per BOE was 8% lower than the first quarter of this year. But was over the high end of guidance due to some nonrecurring M&A costs as well as some additional staffing and professional service fees as well. We generated adjusted cash flow from operations before changes and working capital of $123 million in the second quarter, which is 15% increase over the first quarter of this year.

Looking forward guiding to a full year, 2013, average production rate of between 30,000 and 34,000 BOE a day, which represents growth rate of approximately 45% over the pro forma 2012 production rate.

Our full year CapEx guidance is now set at $1.375 billion, with the majority of that being focused on Bakken and the El Halcon areas. We expect production and cash flow to continue to improve for the remainder of the year, as we execute our drilling program, grow production, and continue to improve on our operating expenses.

We are projecting taxes other than to be between $7 and $8 per BOE for the rest of the year, and LOE per BOE to be between $11 and $13. We are now guiding full year 2013 cash G&A expense to be between $9 and $11 per BOE.

We also expect to see some improvement in our LOE per BOE after we complete the divestiture of noncore asset package, simply due to the cost of operating conventional assets compared to our core assets. Most of this improvement will likely be seen in 2014, as we expect this divestiture to close in the fourth quarter of this year.

To touch on the hedge program which has always, we simply utilized to protect cash flow, and the funding of our drilling program, we continue to target the hedge portfolio where we hedge approximately 80% of what expect to produce over the next 18 to 24 months. We opportunistically have hedges, have layered in a meaningful number of hedges over the past few months. Today we have just over 25,000-barrel as day of oil hedge for the remainder of 2013 on an average floor price of right at $91 a barrel. For 2014, we have 20,000 barrels per day hedged on an average floor price of just under $90 a barrel. On the gas side, we currently have about 27 MMBTU a day hedged for the remainder of 2013, and that average price of about $3.77 and then we have 25 MMBTU a day hedged in 2014, at an average price of $3.90.

With that I will turn the call back over to Floyd.

Thank you, Mark. Well, we are making great wells and meeting our growth objectives, moderating spending and focusing on our core areas. We have set Halcon up for an exciting second half 2013, and even more exciting 2014.

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

Thank you, sir. (Operator Instructions). Our first question in queue will come from the line of Neal Dingmann with SunTrust. Please go ahead, your line is now open.

Congrats on that Kibler well. Say, question on that Utica -- Floyd, you mentioned you delineated most of that play. What's your thought when you look at -- you have obviously had that successful well in south Trumbull County, when you look at that versus Crawford, versus Venango and Mercer, your thoughts on the different regions?

We have a large area that's been proven to be productive in Venango and Mercer counties. We have a very large area down in Trumbull and Mahoning counties that is going to be productive. In Venango and Mercer it looks a little bit more gassy, more much more oily down in Mahoning and in Trumbull.

There's some areas in between that are still have some work to be done. We are just now getting some of those newer wells on production. The area up north, probably not perspective, I would call it goat pasture.

Got it. And then one of your peers mentioned about a lot of processing coming on, pretty near your area, about 200 coming on, another 200 next quarter, and then another 200 in the second quarter, what is your process situation? Seems like you are in good shape as far as you bring these wells on, you're timing them rather quickly. I'm just wondering as far as the processing coming on that you see.

Yes. Now the tie-in of the wells up in the northeast part of the play is taking a bit longer. There's some -- there is just lack of pipe up there and infrastructure. Now, down in the southern end of our operations in Mahoning and Trumbull, we will get these wells hooked on very quickly, and get them right to processing almost immediately. The processing may not be the most efficient processing on day one, but it will quickly get into cryogenic processing.

Okay, and Floyd, what are these Utica wells currently running?

In terms of what?

Just all-in cost, I'm sorry.

Probably spending on average about $10 million these days, but we are looking to gravitate towards an $8 million cost as we get a little bit better at it and figure out a few of the efficiencies up there. We have been drilling -- we drilled nine wildcat wells up in the north end of the play. Every one was high science, every single one was fully equipped like a major company would, as we do most of our stuff. So we expect the cost to really come down over time.

Very good, and the last question if I could, in the El Halcon, you mentioned now you have determined about the limited sweet spot where you can hit the laterals, hit the zone a little bit better, or land in the zone. Can you talk a little bit about what, gives you now the increased confidence? Is that now for the remainder of the play, or just certain parts of El Halcon?

You know, we are just drilling our first wells far to the south of where our initial wells have been drilled, so interestingly the landing zone is about in the same spot, geologically speaking. However, we don't know if it is quite as important down there yet.

The issue up north, not north, but in Brazos County there's a fairly small landing window, but it is plenty big enough for us. If you're not right in it, you can't get all of your frac stages initiated. It is pretty tight, if you try to initiate a frac outside of that zone. So we aren't having any trouble any more, just one of those things you find out in the early stage of any play.

Perfect, thank you, Floyd, and congratulations again on that Utica well.

Thank you, sir. Our next question will come from Jason Wangler with Wunderlich Securities. Please go ahead with your questions, please.

Thanks, good morning. As far as the Bakken with the two areas what are the rig counts going in to look like as we go throughout the rest of the year, do you think, between the two?

We have more rigs running in the south part of the play. Charles can help me here, I think if we have five rigs running it is two north and three south? That's what it looks like right now.

Four south.

Two north and four south, right now.

Okay. And then just maybe real quick, as far as the sale on the Eagle Ford, obviously that will be added to the liquidity at the end of the $500 million liquidity? I just want to make sure that's the right number. So it is around $650 for you pro forma that.

Yes, the $500 million that I mentioned is what we had drawn on the credit line at the end of the quarter, and then we had subsequently sold the Eagle Ford for $144 million.

Perfect. That's all I had, thank you.

Thank you, sir, our next question will come from Steve Berman, with Canaccord Genuity. Please go ahead, your line is open.

Thanks, and good morning. Just to continue that last question, the $40 million reduction in the borrowing basis is not part of the June 30. It's not pro forma for that. So we would have to back that out as a pro forma liquidity number as well. I just want to be clear on that.

Yes, that is correct.

Okay. And then another housekeeping question, the 4500 BOE a day of conventional production you are looking at divesting, is that 4500 still in the guidance both for Q3 and the full year? You haven't backed that out have you?

No, it is still with the guidance. We don't back out divestitures until they happen.

I didn't think so, just wanted to be clear on that. And then the Wilcox, Floyd, no mention of it in the press release, are you doing anything there now? Any plans for the balance of the year?

We're just in the midst of completing about three wells. We are doing fine down there. Just not as big of a focus for us. We don't have any plans today to drill another well there this year, but that could change. That's a nice play, but it's just not -- doesn't have near the scope or running room that everything else that we do has.

And it's a structural play generally speaking, which speaks to repeatability, so what we look for is rate. Rate growth, repeatability, and running room, and if you are going to be drilling structural highs only, that it just doesn't lend itself to the profile that we are creating here. It's a good play.

Got it. Last one from the current well cost in the Williston Basin?

The well cost -- I think in the north are about $1 million less than in the south. However, overall our well coasts have gone up a little bit from say start of the year, because we are using ceramic almost everywhere, and pumping bigger frac jobs. That's been offset by fewer rig days, and just the beginning of pad drilling, so I think you would still need to use about $10 million in the south end of the field, about $9 million in the north end. We expect for those to go down $1 million or $2 million over the next six to 12 months.

Perfect, thank you.

Thank you, our next question will come from the Brian Corales with Howard Weil. Please go ahead, your line is now open.

Good morning. Just back to the Utica, can you talk about how much acreage you all have in Trumbull and Mahoning, as well as Venango and Mercer.

Well, we don't disclose that.

Roughly.

It's very competitive we are still leasing. Up have in Venango in the area we have defined as being likely, similar to the Allam well, we have a room for 100, 150 wells or something like that, and we are adding a little bit of acreage up there. Down south, we have more acreage, again, we aren't saying exactly how much, because we are adding. But we have room for about 500 wells down there now.

And that's if you think about it, it is 160-acre spacing and it's talking gross wells not net. So again, we would have a lot of 100% wells down there. But again, we don't really get into those exact numbers this early in the stage of things.

The next couple of years we will spend all of our money in the Kibler area. Except maybe late next year, we will start drilling more in the Allam area. We have long term leases, or HBP leases, everywhere up there. So we are under no pressure, so we will let economics drive our decisions. Where it has taken longer to build infrastructure up in the north end, around Venango, permitting and whatnot is difficult, and time consuming up there. So generally speaking our spend is going to be down around the Kibler area for the next 12-18 months for sure.

Okay. And maybe -- can you talk about the $1.375 billion on D&C CapEx. Can you talk about what you spent on the first half of the year?

You know, Mark has that number in the document. I think it's -- $800 some odd million. We dropped a few rigs, and although we are still completing a lot of wells that were drilled in the front half, so we are moderating spending dramatically in the back half. And we'll start adding a few rigs towards the end of the year to get ready for 2014. Right now that's our best guess, $1.375 billion.

Okay, thank you, guys.

Thank you, Brian. Our next question will come from Ron Mills with Johnson Rice. Please go ahead, your line is open.

Good morning, Floyd. Just as it relates to the Kibler area, Mahoning and Trumbull counties -- can you give us some sort of lay of the land of other industry activity in that area? Between guys like BP, CNX, Hill Corp, et all? Just -- it's an area we don't hear as much about, so just curious what the industry activity looks like.

Well, not to talk specifically about any peer or competitor in any area, we have the largest concentration of land in and around the Kibler area. We have drilled four wells down in that region. Roughly, four of our nine wells stretch across about a -- I don't know, 30-mile stretch, 30 or 35-mile stretch down there. And uniformly good logs and core results. I think a couple of the companies you mentioned one of them is more north of there, and one of them is a little more east. And one of them is kind of right in around where we are.

We are the company that's drilled the most horsetail wells in the north end of the Utica/Point Pleasant play. Some of the majors have just getting started and seem to be drilling more vertical wells right now. I'm sure that will segue into horsetail drilling pretty quickly.

And obviously, what you saw -- what you have seen, at least, has helped drive your decision to invest in the oil storage in railroading facility. Can you talk about what phase one is or what will be running by year end which is phase one of that program and the benefits of phase one?

We are talking about high gravity oil, or condensate. We are going to have to stabilize, as to make the economics as best as they can. We are going to have to store centrally, so we aren't running trucks all over the land with small tanks. And we need (inaudible) it out of the local market, as fast as we can, for price discovery to refineries and price points that are better than just the local trucker.

I think our first phase would be 40,000-barrel a day or so. And it is going to be open to other companies as well. We have had a lot of interest in what we are doing there.

Okay, great. And just moving over to the Bakken, the early results have been very strong in really both northern and southern areas. Has anyone used slick water down to the south? I know it has worked very well up in the north, and it is starting to gain at least stature, or interest in the industry. Can you describe what some of the applicability would also be in the southern area?

Well, I don't know personally of anybody that has used slick water fracs down at Fort Berthold. There has been extensive use of it. Extensive means ten wells or so by now, 15 wells, south of our holdings in Williams County quite a few wells right in there, which is how we became interested in the whole concept. And as you know, you don't have to go very far south there. You have a lot of great operators with large positions. So I don't know about down in the thicker part of the basin.

I'm certain that others will try it, sometime, and of course we are going to try it -- we are trying one right now. We'll judge based on that. We are having great results with it up north, though.

And then you've -- you've brought a couple, three or four wells online that appear to be producing pretty well as well. Are those just from the upper Three Forks? Are you also -- are you taking cores down through all benches of the Three Forks? How do you look at the Three Forks opportunity as it underlies both your southern and northern acreage?

Ron, as you know, there's -- for an area that has I don't know, 6,000 wells or something, they have been relatively few cores taken by the industry. We take cores in every area of concentration, acreage concentration we have. We have taken cores down there, so far all of our completions have been in the upper Three Forks. We are quite interested to find out about either separation or drainage in some of the other benches and we are participating in several of those down-spacing tests and drainage tests. So I think in a general sense over the next 12 months you will see a ton of information coming out of the industry on what is going on, and how effective all of that is.

We are hopeful that it is going to be very effective, and economic. It's just early days in that process right now. The industry in general is just barely gotten out the lease capture phase, just within the past year or so.

Did you say the six rigs you have running now are all moderns? Are they all walking rigs capable of pad development, have you transitioned that whole rig program over?

Yes.

All right. That's all I have, thank you.

Thank you, sir. Our next question will come from the line of Kyle [Rowe] with RBC Capital Markets. Please go ahead, your questions please.

Hi, guys. You have provided three well results from your Utica. I think in your press release today, you said you have tested five. I was just wondering if you can provide other color on the other two wells. Maybe the Brugler 1H, and any other well as well.

I think the other would be the Yoder. Both of those wells had limited test periods. We were constrained with flaring, and whatnot, and infrastructure wasn't too far away. So we tested those wells. In terms of quality, they will be better than the Phillips but not as good as the Kibler, and we will have to get them on line to really understand that. They are oily, and we just -- they are basically shorter lateral wells that were drilled as part by delineation, so we could get cores. We didn't have large units formed to make 7,000 and 8,000-foot lateral links, which is our current style of drilling everywhere we are drilling.

So I -- the middle area if I can say the middle area, kind of in between the Kibler area, and the Allam area, it needs some work. We'll get those wells online, and report as soon as they are online.

Okay, thanks for that. And then just moving over to the TMS, there's been some momentum in the play, with a few good results, albeit the east of your acreage. I'm just wondering how you guys are thinking of that play going forward.

We have not lost interest whatsoever. As we reported early on, our Broadway had the thickness and organic content and all of the basic reservoir characteristics we like to see in a shale well very similar to what they are getting east of there. So we had some completion problems there, lost the well, essentially. We are not playing on anything there this year, we have plenty of lease term. But we are very interested and hopeful that the play is going to turn into a money maker for the industry, and including ourselves.

Did you guys look at the Devon acreage at all?

We looked at everything, in any area, but we didn't really pursue it. We have got quite a bit of acreage over there now.

To the east.

Pardon me?

To the east, you said? Do you have acreage over there to the east?

The acreage block is expansive in the area. I think we have close do 100,000-acres in leases and options. Some number about like that -- 90,000 acres or 100,000 acres. I don't know.

Great, thanks, Floyd.

Thank you, sir. Our next question will come from the line of Jeff Robertson.

Thanks, Floyd, a question on El Halcon, the sweet spot you all have identified for landing is that pretty easily mapped? And then secondly, I would assume the 3-D seismic that you get toward the end of this year will be beneficial in drilling longer laterals and staying in the zone. Is that accurate?

Yeah. Now, again, I will point out we are not really having any trouble staying in zone. Now that we figured out that that landing spot was so critical to initiating frac jobs. We fracked out of that landing zone into the rest of the formation, but the rest of the formation is just -- it's tighter than that landing zone, and it is hard to initiate the frac. So you have these treating pressures that get too high for your casing ratings and your surface equipment ratings. If you don't figure out a way to drill in an area where you can initiate your frac job.

The whole section is contributing and loaded with crude. So, yes, the seismic help will help with that. But again, we aren't really having any trouble with it right now. We had trouble in a couple of wells because we didn't really understand how super critical it was, but we do now.

The second question, I apologize if you talked about this earlier, but Mark, can you talk about how much borrowing base is associated with the conventional assets that you all hope to sell? And then secondly, do you anticipate this the drilling and PDP reserves you develop will offset that borrowing base when you have your redetermination?

Let me answer your part two. We hope so, but we don't know.

Okay.

We will shoot for that, and that would be quite a feat if we can do that. But we would like to do that. Go ahead, Mark.

As far as the impacts for the borrowing base, we could be looking at anywhere from $125 million up to $150 million, somewhere in the that ballpark. We have gotten some back of the envelope with JPMorgan, so it there will be somewhere in that range.

Thank you.

And I will say, also, we did have an acquisition this quarter, it was kind of on the small side for us, but it is going to offset partially, at least, the reduction that we are going to take related to the conventional assets sale.

That's the New Home deal.

Yes.

Okay. Thank you very much.

Jeff, keep in mind that the timing of the closing of that sale will be -- early fourth quarter, middle fourth quarter, something like that. So it is really a 2014 kind of an impact for the company.

Thank you.

And the rest of the impact will be measured in reduced operating cost, because of the mature fields, sometimes the operating costs on them is three or four times as much as a new shale well.

Thank you, sir. Our next question will come from Robert Bellinski with Morningstar, please go ahead your line is open.

Good morning and thanks for taking my call. I was just wondering. What's the -- with Williams county acquisition, what does that take your working interest to? And then second, I know it is still early days, but do you have any additional details on your well testing space in the Bakken? Thanks.

We don't have anything -- any results to put out yet as far as the down spacing test in the Bakken. Charles, what specifically are we doing there? We have how many well?

We have one unit that will have seven wells in it with some 660 space in between them that we just finished drilling.

So we will be fracking all of those, bench fracking all come on within six weeks from now, or thereabouts.

Okay.

We will have information on that pretty soon. In terms of Williams county, I think it doubled our working interest, up to 75% or so.

That's great, thanks, guys.

Thank you, sir. Our next question will come from Mike Kelly, with Global Hunter. Please go ahead, your line is open.

Hey, good morning. I was hoping you could talk about the consistency of your acreage, in El Halcon, and really just trying to get a gauge on what you expect from variability there? If you do build up to the 100,000, 150,000 acres this year, thank you.

Our target is 100,000 to 150,000. I am sure we will hit that range somewhere, but it is very competitive now. A lot of interest in this kind of newly energized area for the Eagle Ford shale. So far, it's very consistent. That can change. There's not a comprehensive 3-D survey available through this area. So far it's very consistent. Thickness, and quality, very consistent.

We do have a lot of -- quite a few logs that go through the section, drilling down to the boot and other zones so we have a pretty good handle on this. But you are drilling these wells and over time, in very close proximity, so the -- you know it is going to be very consistent from well to well.

Okay, thank you. And on the liquidity front, just hoping to get your higher level thoughts here on how you move forward. Obviously you guys are in rapid growth mode. But just dealing with the liquidity, with that level of spend, how do you do it? What really is going to be the major funding mechanism to get through the second half of this year, and into 2014? Thank you.

Well, as you might note from our production growth, our revenue is growing dramatically as well. We have significant proceeds this year from divestitures and our borrow basis is growing. We have raised a little money right along, so we are in great shape.

Thank you.

And the infrastructure business as we move that away from our kind of parent borrowing base, will free up some capital there as well.

Thank you, sir, we do have time for one final questioner. Our final question will come from Brian Velie with Capital One. Please go ahead, your line is open.

Good morning, everyone. Just a quick question on the two wells well, two wells that are being tested and another two that are resting right now in the Utica. Can you say which counties those are there? And when we may expect some test results?

Well, we've got essentially three more wells in the general area of the Kibler that will be coming on in the next weeks and months or so. We have a couple wells that are waiting on pipeline, a little more north of there. And there's a well drilling up in, we drilled up in Mercer County. And there's one to the far north. The Stockwell, that we are just now getting on -- just now turning it on. To the majority of what we are bringing on right now is down around the Kibler area.

That's helpful, that's all I have.

Everyone thank you for joining and if there's something we didn't cover, give us a call. Thanks.

Thank you presenters and thank you, ladies and gentlemen. This does conclude today's call. Thank you for your participation and have a wonderful day. Attendees you may disconnect at this time.