Battalion Oil Corporation (BATL) Q2 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by, and welcome to Halcón Resources Second Quarter 2013 Earnings Conference Call. [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. Thanks for joining. This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued this morning. Well, 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 2,233 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 company record completion with the well at Fort Berthold, 3,317 barrels of oil equivalent per day. At El Halcón, we're drilling ever-longer laterals and most of our new wells come in at between 1,000 barrels and 1,300 barrels of oil equivalent per day. We're becoming more efficient in all of our core areas via modifications in both drilling and completion practices, and we're 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 online than we did in the second quarter. Drilling-wise, the front half has been front-end loaded -- the first half has been front-end loaded for us. At the second time -- 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 another part can be watched -- by us watching our capital budget and our spend. We will begin to add rigs towards the end of the year 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 in production we're achieving across our assets in Williston Basin have to do with modifications in well design in 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're very excited about the potential up there. At Ford Berthold, we continue to set record IPs almost weekly. We have increased profit in concentration stage density, changed the fluid design and we've 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're conducting downspacing tests at Fort Berthold and expect results by year-end. We expect to gain a better understanding of efficient drainage in the Middle Bakken in the different Three Forks benches through our own efforts, as well as through our working interest in other downspacing tests in the region. We have redirected capital in East Texas, from the Woodbine to El Halcón, for the remainder of this year. Activity in the Woodbine may pick up early next year, when we receive the data from our large 3D seismic shoot. We hope that data will help us identify additional sweet spots and avoid hazards in this complicated area. At El Halcón, we continue to make progress towards our goal of over 100,000 net acres. We recently set a company record at El Halcón by hitting the target -- by hitting target depth in a well in less than 11 days. This sort of improvement has a major impact on economics. Up north, we're really excited about our Utica/Point Pleasant asset. Our delineation drilling is complete, and we made our decision as to where we'll focus our capital in the play for the next couple of years. The test results 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 than all but 10 wells across the entire play. We have significant holdings in Trumbull and Mahoning counties with the potential to drill hundreds of wells in that area. The Allam 1H is one of the more important wells in the play, as far as I'm concerned, proving that the play can be commercial for us in [ph] the northeast. We recently reinitiated our leasing efforts in very specific areas, and we continue to be focused on building an inventory of permitted, multi-well pads in preparation for full-scale development. This year, we'll keep at least 1 rig active up there that'll be drilling in the Kibler area. Also up north, Halcón Field Services are 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 Lordstown, Ohio, to develop an oil storage and rail loading facility. HFS and OCC have attained a permit to build the facility. OCC has over 12,000 feet of recently installed rail, and access to multiple class one rail carriers make it an ideal location for low-cost rail services to support the rapid production growth expected 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 could accommodate unit trains at the rate of 140,000 barrels of oil or condensate per day. The project is on track for environmental clearance and permits and internal approvals within several weeks. In addition, Halcón Field Services continues to engage in discussions for potential drilling ventures to develop high pressure, rich gas gathering systems and cryogenic processing in Ohio and Pennsylvania. These potential joint ventures would provide for third-party volume and shared capital cost of our buildout 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 a public offering of 5.75% of cumulative perpetual convertible preferred stock, which yielded net proceeds to the company and brought out $335 million and were 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 sell for about $144 million, the borrowing base was reduced by $40 million. So it was $850 million, and currently it 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, [indiscernible] our midstream subsidiary Halcón Field Services is moving forward in the Utica/Point Pleasant play, and as such we formally kicked off the process to establish a separate borrowing capacity for this business. We're going to look to have that in place in conjunction with the fall redetermination. Since this business is becoming more valuable and material to HK, you'll notice, we've 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 per day in the second quarter, which was 12% higher than the first quarter of '13 -- first quarter of '13 production rate, and it 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 is 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 is 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 some additional staffings, some professional service fees as well. We generated adjusted cash flow from operations before changes on working capital of $123 million in the second quarter, which is a 15% increase over the first quarter of this year. Looking forward, we're guiding to a full year 2013 average production rate of between 30,000 and 34,000 BOE a day, which represents a 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 Halcón areas. We expect production and cash flow to continue to improve for the remainder of the year as we execute on our drilling program, grow production and continue to improve on our operating expenses. We're projecting taxes other than incomes 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're now guiding full year 2013 cash G&A expense to between $9 and $11 per BOE. We also expect to see some improvement in our LOE per BOE after we complete the divestiture of the noncore asset package simply due to the cost of operating conventional assets compared to our core assets. Most of the 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 as always we simply utilize to protect cash flow and the funding of our drilling program. We continue to target a hedge portfolio where we hedge approximately 80% of what we expect to produce over the next 18 to 24 months. We opportunistically add hedges and have layered in a meaningful number of hedges over the past few months. Today, we have just over 25,000 barrels a day of oil hedged for the remainder of 2013 at an average floor price 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 GAAP [ph] side, we currently have 27 MMBtu a day hedged for the remainder of 2013 at an average price of about $3.77 and then we've had 25 MMBtu a day hedged in 2014 at an average price of $3.90. I'll turn the call back over to Floyd.

Thanks, Mark. While we're making some great wells and hitting our growth objectives, we're moderating spending and focused on our core areas. We set up -- we have set Halcón up for an exciting second half 2013 and even more exciting 2014. Operator, we're ready for questions now if there are any.

[Operator Instructions] Our first question in queue will come from the line of Neal Dingmann with SunTrust.

The question on that Utica, Floyd, as far as you -- you've mentioned that you've delineated most of that play. Just what's your thoughts when you look at -- you've obviously had that successful well now in South Trumbull County. When you look at that versus Crawford versus Venango and Mercer just your thoughts in 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. It is going to be productive. Up in Venango and Mercer, it looks a little bit more gassy, 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've just now getting some those newer wells on production. In the area up north, probably not prospective. I'd call it go-pasture.

Got it. Got it. And then one of your peers just mentioned about a lot of processing coming on pretty near your area, about 200 coming on currently, another 200 next quarter and then another 200 in the second quarter. What is your process situation? It seems like you're in pretty good shape as far as you bring these wells on your tying them in 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 is some -- there's just lack of pipe up there and infrastructure. Now down on the southern end of our acreage in Mahoning and Trumbull, we'll get these wells hooked on very quickly and get a route to processing almost immediately. The processing may not be the most efficient processing on day one, but it'll 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're 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've been drilling -- we drilled 9 Wildcat wells up in the north end of the play. Everyone 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 last question, if I could. Just on the El Halcón, you mentioned you hear about now that you have determined about the limited sweet spot where you can hit the laterals or hit the zone a little bit better or landing the zone. If you do talk a little bit about that, what gives you now the increased confidence. Is that now for the remainder of the play? Or just certain parts of El Halcón?

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

Our next question will come from Jason Wangler with Wunderlich Securities.

As far as the Bakken, with the 2 areas, what are the rig counts going to look like as we go throughout the rest of the year, you think, between the 2?

We have more rigs running in the south part of the play. Charles can help me here. I think if we have 5 rigs running, it's 2 north and 3 south? That's what it looks like right now.

4 South -- 2 north, 4 south.

2 north, 4 south right now.

Okay. And then, just maybe real quick, as far as the sell on the Eagle Ford. Obviously that's going to be added to the liquidity at the end of the -- the $500 million liquidity. I just want to make sure that that's the right number, so it's around $650 million if you pro forma that?

Correct.

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

Our next question will come from Steve Berman with Canaccord Genuity.

Just to continue that last question, with the $40 million reduction in borrowing basis is not part of the June 30 note, it's not pro forma-ed for that so we'd have to back that out of 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 4,500 BOE a day of conventional production, you're looking to divest it. Is that 4,500 still in the guidance for Q3 and the full year. But you haven't backed that out, have you?

No. It's still in the guidance. We don't back out divestitures until they happen.

Okay. I 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 3 wells. We're doing fine down there. It's just not as big 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 -- it 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're going to be drilling structural highs only, that just doesn't lend itself to the profile that we're creating here. It's a good play.

Got it. Okay. And last one for me, current well cost in the Williston Basin?

The well cost, I think in the north, they're about $1 million less than in the south. However, overall, our well costs have gone up a little bit from say, start of the year, because we're 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'd still need to use about $10 million 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 6, 12 months.

Our next question will come from the line of Brian Corales with Howard Weil.

Just back to the Utica, could you talk about how much acreage you'll have in Trumbull and Mahoning as well as Venango and Mercer?

Well, we don't disclose that. It's very competitive and we're still leasing. Up in Venango, in the area that we've defined as being likely similar to the Allam well, we have room for 100, 150 wells or something like that, and we're adding a little bit of acreage up there. Down south, we have more acreage. Again, we're not saying exactly how much because we're adding, but we have room for about 500 wells down there now. So -- and that's -- if you think about it, it's 160 acres spacing and I'm 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'll spend all of our money in the Kibler area except maybe late next year, we'll start drilling a little bit in the Allam area. We have long-term leases or HBP leases everywhere up there so we're under no pressure. So we'll let economics drive our decisions. We are -- it's 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 could 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?

I don't -- Mark has that number in the document. I think it's 800-and-some-odd million dollars. We dropped a few rigs, and -- although we're still completing a lot of wells that were drilled in the front half. So we're moderating spending dramatically in the back half, and we'll start adding a few rigs toward the end of the year to get ready for 2014. But right now, that's our best guess, $1.375 billion.

Our next question will come from Ron Mills with Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Just as it relates to the Kibler area, Mahoning and Trumbull counties, there's -- can you give us some sort of lay of the land of other industry activity in that area between guys like BP, CNX, Hilcorp, et al? It's 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 got the largest concentration of land in and around the Kibler area. We've drilled 4 wells down in that region, roughly 4 of our 9 wells stretch across about, I don't know, 30-mile stretch, 30, 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're the company that's drilled the most horizontal 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, but I'm sure that will segue into horizontal drilling pretty quickly. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then obviously the -- what you sold, what you have seen at least has helped drive your decision to invest in the oil storage and rail-loading facility. Can you talk about what Phase 1 is? What will be running by year-end? Which is Phase 1 of that program and the benefits of Phase 1?

This is -- we're talking about high gravity oil or condensate. We're going to have to stabilize so as to make the economics as best as they can be. We're going to have to store centrally, so we're not running trucks all over the land with small tanks. And we need egress 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's going to be open to other companies as well. And we've got a lot of interest in what we're doing there. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay, great. And then just moving over to the Bakken. The early results have been very strong in really both the northern and southern areas. Has anyone used slick water down to the south? I know it's worked very well up in the north and it's starting to gain at least stature or interest in industry. Can you describe what some of the applicability will be -- also be in the southern area?

Well, I don't know personally of anybody that's used slick water frac down at Fort Berthold. There has been extensive use of it -- extensive means, 10 wells or so by now or 15 wells south of our holdings in Williams County, quite a few wells right in there which is how we got -- became interested in the whole concept. And as you know, you don't have to go very far south there to -- 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're going to try -- we're trying one right now and we'll judge based on that. We're having great results with it up north, though. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then, you've brought a couple of Three Forks 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? Or is -- 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, there have been relatively few cores taken by the industry. We take cores in every area of concentration, acreage concentration we have. We've taken cores down there. So far, all of our completions have been in the upper Three Forks. we're quite interested to find out about either separation or drainage in some of the other benches, and we're participating in several of those downspacing tests and drainage tests. So I think in a general sense over the next 12 months, you're going to see a ton of information coming out of the industry on what's going on and how effective all of that is. We're hopeful that it's going to be very effective and economic. It's just early days in that process right now, but the industry in general has just barely gotten out of the lease-capture phase just within the past year or so . Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And did you say the 6 areas you have right now, they're all moderns? Are they all walking rigs capable of pad development? And have you transitioned that -- the whole rig program over?

Yes.

Our next question will come from the line of Kyle Rhodes with RBC Capital Markets.

You've provided 3 wells opening at Utica. I think in your press release today, you've said you've tested 5. I'm just wondering if you could provide some other color on the other 2 wells, maybe the Brugler 1H or any other well as well.

I think the other one will be the Yoder. Both of those wells have 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'll be better than the Phillips but not as good as the Kibler, and we just have to get them online to really understand that. They're oily and we just -- they're basically shorter lateral wells that were drilled as part of our delineation so we could get cores. We didn't have large units formed to make 7,000 and 8,000 for the lateral lengths, which is our current style of drilling everywhere we're 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're online.

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

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

And did you guys look at the Devon acreage at all?

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

To the east?

Pardon me?

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

Well, our acreage block is expansive in the area. I think we have close to 100,000 acres in leases and options, some number about like that, 90,000 or 100,000, I don't know.

Our next question will come from the line of Jeff Robertson.

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

Yes. Now. Again, I'll point out we're not really having any trouble staying in zone now that we've figured out that, that landing spot was so critical to initiating frac jobs. We frac-ed out of that landing zone into the rest of the formation, but the rest of the formation is just as -- it's tighter than that landing zone. It's 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're not really having any trouble with it right now. We had trouble on a couple of wells and -- because we didn't really understand how supercritical it was, but we do now.

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

Let me answer your part 2. We hope so but we don't know. We're going to 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 impact of the borrowing base, we could be looking at anywhere from probably $125 million up to $150 million, somewhere in that ballpark. We've gotten some back of the envelope. We're projecting more, so it will be somewhere in that range. And I will say also, we did have an acquisition this quarter. It was kind of on the small side for us. But it's going to offset, partially at least, the reduction that we're going to take related to the conventional assets sell.

It's the new home deal?

Yes.

Jeff, keep in mind that the timing of the closing of that sale will be early fourth quarter, or middle fourth quarter, something like that. So it's really a 2014 kind of a impact for the company. And the rest of impact will be measured in reduced operating cost because those mature fields, sometimes the operating cost on them is 3 or 4x as high as a new shale well.

Our next question will come from Robert Bellinski with Morningstar.

I was just wondering, what's the -- with the Williams County acquisition, what does that take your working interest to? And then second, I know it's still early days, but do you have any additional details on your well spacing tests in the Bakken?

We don't have anything, any results to put out yet as far as the downspacing test in the Bakken. Charles, what specifically are we doing there? We're drilling how many wells in...

We have 1 unit that will have 7 wells in it with some 660 spacing in between them that we just finished the drilling.

So we'll be frac-ing all those, kind of batch frac-ing. They'll all come on within about 6 weeks from now or thereabouts. We'll have information on that pretty soon. In terms of Williams County, I think it doubled our working interest up to about 75% or so.

Our next question will come from Mike Kelly with Global Hunter.

I was hoping you could talk about the consistency of your acreage in El Halcón and really I'm just trying to get a gauge on what you expect from variability there, if you do build up to the 100,000-acre, 150,000-acre position?

Our target is 100,000 to 150,000. I'm sure we'll hit that range somewhere but it's 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 3D survey available through this area so -- but so far it's very consistent. Thickness and quality, very consistent. We do have a lot -- quite a few logs that go through the section, drilling down to the boot and other zones so we got a pretty good handle on this. But you're drilling these wells in, over time, in very close proximity. So it's going to be very consistent from well to well.

Okay. And on the liquidity front, just kind of hoping to get your high level thoughts here, of how you move forward. Obviously, you guys are in a rapid growth mode. But just dealing with 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 '14?

Well, as you might know from our production growth, our revenue is growing dramatically as well. We have significant proceeds this year from divestitures, and we have a growth -- our borrowing base is growing, we've raised a little money right along, so we're in great shape. And I think the infrastructure business, as we move that away from our kind of parent borrowing base, we'll free up some capital there as well.

And we do have time for one final question. and our final question will come from Brian Velie with Capital One.

Just a quick question. On the 2 wells that are being tested and then another 2 that are resting right now in the Utica, can you say which counties those are in and when we might be able to expect some test results?

Well, we've got essentially 3 more wells in the general area of the Kibler that will be coming on in the next weeks and months or so. We got a couple of wells that are waiting on pipeline, a little more north of there. And there's a well drilling up in -- that was drilled up in Mercer County. And there's one to the far north, the Staab well that we're just now getting on -- we're just now turning it on. So majority of what we're bringing on right now is in the -- down around the Kibler area. Everyone, thanks 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.