Gulfport Energy Corporation
Q2 2015 Earnings Call Transcript

Published: 6 Aug 2015

[Operator:]

Good day, ladies and gentlemen, and welcome to the Gulfport Energy Corporation Q2 2015 Earnings Conference Call. As a reminder, this conference call is being recorded. I would now like to turn the conference over to Ms. Jessica Wills, Associate Director of Investor Relations. Ma'am, please go ahead.

[Jessica R. Wills:]

Thank you, and good morning. Welcome to Gulfport Energy Corporation's second quarter 2015 earnings conference call. I am Jessica Wills, Associate Director of Investor Relations. With me today are Mike Moore, Chief Executive Officer and President; Ross Kirtley, Chief Operating Officer; Aaron Gaydosik, Chief Financial Officer; Keri Crowell, Vice President and Controller; Paul Heerwagen, Vice President of Corporate Development; and Ty Peck, Managing Director of Midstream Operations. I would like to remind everybody that during this conference call the participants may make certain forward-looking statements relating to the company's financial conditions, results of operations, plans, objectives, future performance and business. We caution you that the actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we may make reference to other non-GAAP measures. If this occurs, the appropriate reconciliations to the GAAP measures will be posted on our website. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with yesterday's earnings announcement. Please review at your leisure. At this time, I would like to turn the call over to Mike Moore.

[Michael G. Moore:]

Thank you, Jessica. Welcome, everyone, and thank you for listening in. As announced in the press release yesterday evening, Gulfport reported approximately $34.8 million of EBITDA, $74.6 million of operating cash flow and $31.3 million of net loss during the second quarter of 2015. These results contain a non-cash unrealized hedge loss of $34.6 million. Comparable to analysts' estimates, adjusted net income for the second quarter, which excludes the previous mentioned items, was $250,000, or $0.00 per diluted share. Operationally, Gulfport had an active second quarter, as we continued to see growth in sales, and produced approximately 474 million cubic feet of gas equivalent per day, ahead of our previously issued guidance of 445 million cubic feet to 455 million cubic feet equivalent per day. This represents a 12% increase over the first quarter of 2015 and a 196% increase over the second quarter of 2014. Production during the quarter was comprised of 77% dry gas, 13% natural gas liquids and 10% oil. We continue to focus our efforts on the dry gas and lean wet gas windows of the play. And today, reiterate our expectations to exit 2015 with total company production of 85-plus percent natural gas. Our impressive 2015 results have been a product of continued solid well performance, coupled with the exceptional results we are experiencing from the dry gas window of the play. Gulfport implemented a managed pressure program during early 2014, which targeted to further enhance returns by improving EURs, predictability of production, operational runtime and overall capital efficiency. As we moved east to the dry gas window, absolute productivity exceeded expectations and the production rates and pressures we are seeing from these wells are beyond our original assumptions. Lastly our guidance for the year factored in a number of risk related potential delays and production downtimes associated with midstream and winter operations and as we have progressed throughout the year, we have been very pleased that our actual results have exceeded our risks expectations. Strong results during the first half of 2015, coupled with our anticipated activity for the second half of the year have led the company to update our 2015 production guidance and we now expect to average approximately 517 million cubic feet to 541 million cubic feet equivalent per day during the year, equating to 115% to 125% growth over 2014. In addition, we currently forecast third quarter production will average approximately 590 million cubic feet to 610 million cubic feet equivalent per day. Driven by our firm transportation portfolio, we priced approximately 96% of our natural gas production at premium market points, relative to in-basin pricing and as expected, before the effect of hedges and including transportation costs, realized approximately $0.41 per Mcf or $0.59 per in MMbtu below the average NYMEX net gas price during the second quarter. This compares to the company's previously announced full-year 2015 natural gas basis differential guidance of $0.52 to $0.58 off of NYMEX. We continue to utilize our firm portfolio to price our molecules at favorable indices and currently expect our full-year 2015 gas differential to be within this range. However, through the remaining summer months, we anticipate to swing wide of this range and we expect a narrower differential throughout the winter months due to higher seasonal demand. Before the effect of hedges, our second quarter oil price came in slightly higher than expected, driven by the completion and start up of MarkWest condensate stabilizer, allowing us more opportunities for better pricing for our Utica volumes. In addition, we continue to receive premium LLS pricing from our southern Louisiana assets. Our realized NGL price came in lower than anticipated, largely driven by the continued deterioration in the Northeast NGL market. Gulfport, as well as our peers, expect NGL weakness to continue near-term but believe overall prices could show some improvement during the fourth quarter due to higher seasonal demand and additional export capacity coming online. We have updated our NGL realization guidance to reflect current expectations, which accounts for the decoupling between the price of NGLs and the price of oil and we now expect to realize approximately $0.32 to $0.37 per gallon during 2015. Again, I'd like to reiterate that as we continue to focus on our high return dry gas opportunities in the Utica, liquids will become less and less of the total company production mix. On the hedging front, we realized a significant gain of $20.6 million in the second quarter. Including the cash settlement of our hedges and transportation cost, our blended realized price for the quarter totaled $3.41 per Mcfe. We continue to monitor the future curves (7

[Jessica R. Wills:]

Amanda, please open up the phone lines for the questions from participants.

[Operator:]

Thank you. And our first question comes from the line of Don Crist from Johnson Rice. Your line is open.

[Don P. Crist:]

Good morning, Mike. How are you this morning?

[Michael G. Moore:]

Hi, Don. How are you?

[Don P. Crist:]

I'm good. Can I start with the production guidance? I know the production that you added from the AEU transaction factors into it, but can you talk about the main drivers that were behind the significant guide up in production guidance? I mean was it more related to just risking or is the rock better or was there infrastructure things that you were worried about that came online faster than you thought? Can you just expand on that?

[Michael G. Moore:]

Well, thanks, Don. First of all, let me say that really the production we got from the AEU acquisition had very little impact in the second quarter to our overall production. But really I think, Don, it speaks to our rock quality here in Utica shale in the southern part of the play. These dry gas wells we brought on are pretty phenomenal wells, quite frankly, and they've exceeded our expectations. So really nothing's changed from a timing schedule aspect. We pretty much brought on what we thought we would for the second quarter. We're not slowing completions, we're not accelerating completions; it really is completely related to the quality of the assets that we have here.

[Don P. Crist:]

Okay. And just looking at your overall inventory count, how you calculated versus your total acreage position. It looks like it's pretty conservative. Can you talk about some of the drivers behind that?

[Michael G. Moore:]

In our new location count slide?

[Don P. Crist:]

Yeah.

[Michael G. Moore:]

Okay. So, certainly we factored in the effects of down spacing to 750 foot in the wet gas and dry gas window and 600 feet in the condensate window, and so we used that as the base for our calculation. Of course, we got lots of extra locations from the AEU acquisition and the Paloma acquisition but then we also applied a risking factor of 20% and I will tell you, that is an estimate and we continue to work on trades, swaps and we would expect to be able to create additional locations. But we thought it was appropriate to at least apply some risking factor to the number of locations we have available to develop.

[Don P. Crist:]

Okay. And if I could sneak in one more here, the 17 Bcf to 20 Bcf that you talk about in dry gas is obviously without ethane, any ethane contribution. Can you talk about other operators in the area that are talking about a 20 Bcf and kind of put that on apples-to-apples? Are they counting ethane in their EURs as well?

[Michael G. Moore:]

No. The operators that I can think of in the area also do not count ethane in their EURs as well.

[Don P. Crist:]

Okay. I'll jump back in queue. Thanks for the -

[Michael G. Moore:]

Thanks.

[Operator:]

Thank you. Our next question comes from Neal Dingmann from SunTrust. Your line is open.

[Neal D. Dingmann:]

Morning, guys. Trying to think of a question after all those. My first, just Mike, can you talk a little bit on cost structure a little bit? How you see it, or I guess you know what I'm getting after. It seems like in your guidance you've got cost structures I think, or well costs estimated to be about the same. How do you think about either the breakeven gas price or sort of, what – if you could talk about maybe what returns you're seeing today, just in broad terms for either one of those?

[Michael G. Moore:]

Well, first of all, from a return perspective and, of course, we provided a lot of the new information this morning or last night in our slide deck, but single well economic returns, the dry gas window or at today's prices are somewhere in the 56% to 61% range of IRRs, so very good returns. From a cost structure, you know we increased the costs in the dry gas window, just slightly to account for the higher mud weights that we have to deal with here but generally, we're able to drill these wells that are really efficient, a really efficient pace and at a very good price. From a breakeven aspect, Neal, I'd say somewhere around $2 is probably a breakeven price that you should think about.

[Neal D. Dingmann:]

Got it. And then just secondly, just moving over to takeaway in differentials. I noticed you had a slide, and you've had this before though, just talking about LNG exports. When you all look at it, and I know Ty is always looking at takeaway well into the future. Do you take into consideration potential for LNG exports? Is there anything that you're signing up there? Maybe if you could just address your takeaway differentials going forward.

[Ty Peck:]

Neal, this is Ty. We do look at the end users and what capacity they might have taken out. And I think they're all wanting access to Utica supply, which works well for us. So we've been doing that. We actually have been talking to the LNG markets and have done some deals there and continue to do some deals there, as well as all the growth in the Gulf Coast that's coming on.

[Neal D. Dingmann:]

Makes sense. Thank you, all.

[Ty Peck:]

Thank you.

[Operator:]

Our next question comes from the line of David Deckelbaum from KeyBanc. Your line is open.

[David A. Deckelbaum:]

Morning, Michael. Thanks for all those details. Just wanted to ask a question on the rig activity and where you see the rigs progressing through the end of the year. And for the conceptual guidance that you were talking about for 2016, does that envision that all of your rigs would be active in the dry gas window?

[Michael G. Moore:]

That's a good question. So right now we have four rigs running, two actually in wet gas right now and two in dry gas. As you recall, when we made the Paloma and AEU acquisitions, we pre-funded almost $300 million to bring in our fourth and fifth rig. The anticipation was that the fourth rig would come in late third quarter, early fourth quarter. We actually had had our eye on a big rig and it became available a little early, so we brought it in 30 days to 45 days earlier. The reason we have two rigs right now in wet gas window is because we've got some pad development going on, side-by-side pad development. As you know, that's the way we develop the units out there for efficiency's sake. But as soon as that fourth rig finishes up, it will move over within the next 30 days back to dry gas window. So the short answer is, what we would expect the rest of the year probably is three rigs in the dry gas window and one in the wet gas window. As we look to 2016, clearly the majority of our activity is going to be in the dry gas window. We have 900 locations to drill over there and only 168 locations left in the wet gas window. So we'll be heavily concentrated next year in the dry gas window.

[David A. Deckelbaum:]

All right. That's helpful. And could you just remind me where you are on the HBP schedule in the wet gas window? Are there any like significant commitments over the next couple years?

[Michael G. Moore:]

I'm sorry, you broke up there. I couldn't hear your question.

[David A. Deckelbaum:]

Sorry. I was asking if there are any significant HBP commitments over the next couple years outside of the dry gas window.

[Michael G. Moore:]

No, no. We have a minor drilling commitment on some of the new acreage that we acquired. It's 10 wells a year, but, no, we don't really have any issues there.

[David A. Deckelbaum:]

Okay. And I guess....

[Michael G. Moore:]

You've got to remember that we're largely drilled up, so most of it's held.

[David A. Deckelbaum:]

Okay. And just a last one for me, just trying to get inside your head a little bit. You talked about this conceptual 50% growth of $600 million or so of spend running five rigs and then you know doing more maintenance, another $300 million, generating free cash, 25% growth. And both of these scenarios are talking about strip pricing. So if we're in the same environment, what motivates you one way or the other? Because clearly you're growing fairly robustly in both scenarios. And you look at like the firm commitments that are coming online, it doesn't necessarily seem like there's a reason to necessarily go faster. So how do we think about you guys reaching your decision points on that, philosophically?

[Michael G. Moore:]

That's a good question. And I know 2016 is certainly on everyone's mind. And Aaron may want to jump in here, too, as well. When we're looking at level of activities that we think are appropriate, obviously we have to think about commodity prices, returns, liquidity, our hedge book, firm transportation. But I think, what's interesting and I think unique for Gulfport, David, is that we pre-funded $300 million. So we really pre-fund the 2016 activity for our fourth and fifth rigs out there. So we're going to be very thoughtful and think about our balance sheet, making sure our balance sheet is in good shape. We will not exceed our leverage ratio of 2.5 times. That's just something that we feel very strongly about. So we certainly, as we look at our activities, will consider that. If we do have an outspend, we want to make sure we can fund it with the money that we've already pre-funded. But as we look towards 2016, obviously we have to think about what is – the reason we are going to delay giving you a final conclusion obviously is because we want to see some visibility of commodity prices. But I will tell you, David, that we only gave you the maintenance scenario just to tell you the strength of these assets out here of this rock. It's pretty amazing that you can spend $300 million and you can actually grow your average production year-over-year. So we weren't necessarily trying to indicate that was the lower bookend of what we're thinking about, we were just giving you that to help you understand the strength of these assets.

[David A. Deckelbaum:]

Understood. Thanks for all the color. That's it for me.

[Ty Peck:]

This is Ty. I would add as well that we have strong, you've seen our core portfolio of the firm, I think we have good diversity there as well as strong connectivity. And so as we get into this market where we have projects coming on, those projects were committed to under a root assumption that was higher than we're seeing today. So that's where we have additional growth. We'll be very active in that release market and make a home for that extra gas.

[David A. Deckelbaum:]

Thanks, Ty.

[Operator:]

Your next question comes from the line of Jason Wangler from Wunderlich. Your line is open.

[Jason A. Wangler:]

Hey, good morning, everyone. You made some comments about the AEU acquisition. I was just curious with the 18 gross, 11 net wells, just what the plans are with timing there. And just maybe if you have any comment on the type of wells that they drilled, are they similar to yours, different, just what you're seeing there.

[Michael G. Moore:]

Beginning of the year probably is when we'll start activity out there and you're talking about the uncompleted wells? Is that...?

[Jason A. Wangler:]

Yes, sorry.

[Michael G. Moore:]

Yeah, certainly they had a different process on their activities out there, but it's a relatively small number of wells. So we'll get those wells hooked up and see what they do.

[Jason A. Wangler:]

Okay, great. I'll turn it back. Thank you.

[Operator:]

Our next question comes from Leo Mariani from RBC Capital. Your line is open.

[Leo Mariani:]

Hey guys, I was just hoping to get a little bit more color on your sort of your theoretical thoughts on 2016. If I heard you right, you guys were saying that you could run five rigs next year for $625 million to $675 million in capital. Now looking at the 2015 program, I guess you guys are – $630 million to $690 million in capital for maybe three and half rigs. So I was just trying to kind of reconcile those numbers there; any help you have on that.

[Michael G. Moore:]

Well, certainly we're going to – go ahead, Aaron.

[Aaron M. Gaydosik:]

Yeah. Hey, Leo. I think what I'd say is, keep in mind we did start the year with the six rigs running in 2015. And we also had service cost improvements and efficiencies that we did not build into that CapEx number for Q1. And so in Q2 we started to get the benefit of those efforts that Ross's team is working on and also just bringing the rig count down to three, so not quite apples to apples, year-over-year because of that. These are preliminary numbers and we'll follow up later this year with more fulsome thoughts on 2016. We're just pacing the numbers we run. We feel like these are pretty good numbers that we gave you in Mike's prepared remarks.

[Michael G. Moore:]

And I think you have to remember, Leo, that we had an eight rig program running in 2014. So we had quite a few of those costs spill over into the first and even a little bit into the second quarter of 2015. So it's a completely different capital structure for our 2015 activities and that's why you're going to see some apples and oranges CapEx comparisons.

[Leo Mariani:]

Okay. Now that makes sense for sure. And I guess, so you guys are also saying that the $625 million to $675 million next year, well I know it's not set in stone. That's more of just D&C and that's just operated, it wouldn't include any non-op that you may have had in the past through leasehold costs or anything like that?

[Aaron M. Gaydosik:]

It is all D&C and obviously we can't – what happens on the non-op side is TBD but that's kind of based on current line of sight, we think that's a good number. But it is kind of an estimate of both operated and non-operated activities.

[Leo Mariani:]

Okay. And I guess with respect to well costs, you guys have got I think different costs quoted in the different windows. You're showing your type curve assumptions $9.2 million, condensate $9.9 million, wet gas $10.2 million to $10.7 million. Just trying to get a sense on those costs, are those kind of what's budgeted for 2015? Are those current well costs and just trying to get a sense of what current well costs are and if you guys think that you can continue to move those lower?

[Michael G. Moore:]

That's a good question, Leo. I'm glad you asked. Those are current well costs, so that is what we anticipate right now for 2015. And really the only change that we made is we increased the cost of the dry gas window by about $35 a foot, so not as large an increase. But we do have to deal with higher mud weights out there and higher pressures, so a little bit of extra cost and then also we have to set intermediate stream more consistently out there. But I will tell you that we've not factored in, and Ross can comment on this as well, but we've not factored in any additional service cost reductions that we think we might be able to achieve and quite honestly, we are working on those right now. The vendors do seem to be receptive to that. And then secondly, we are not factoring in any additional efficiency gains that we think we might be able to achieve, which as I think you recall, we were bringing them some bigger equipment to deal with the pressures that we have over here at the dry gas window and we think we can achieve additional efficiency there, but we haven't built anything in. So hopefully we can maybe get those costs down a little bit but we'll just have to wait and see.

[Leo Mariani:]

Again, that's helpful. And it sounds like you guys definitely want to continue to make acquisitions. Are you still seeing stuff available out there to pick up in the Utica?

[Michael G. Moore:]

Well, I would say right now we're very focused on the development of the acreage that we have. We have a large critical mass. We've given you the number of locations, which gives us a very nice inventory. It's in the core of the play. So we're not currently looking at any acquisitions. We're heads down working on development, putting units together. Are there opportunities out there? Leasing on the ground is fairly nonexistent at this point. Most of those leases are gone. So you know what's left out there, you know the guys who own the acreage, so we're not necessarily aware of anything, but we're also not really looking. We are focused on our development plan.

[Leo Mariani:]

Okay. Thanks, guys.

[Michael G. Moore:]

Thank you.

[Operator:]

Our next question comes from Mike Kelly from Global Hunter Securities. Your line is open.

[Michael Kelly:]

Hey, guys. Good morning.

[Michael G. Moore:]

Good morning.

[Michael Kelly:]

I appreciate the bookends on 2016's growth and I was hoping Ty could do a similar exercise on gas differentials in 2016. You guys have guided to $0.52 and $0.58 off NYMEX for 2015. What could that potentially look like in 2016? Thanks.

[Ty Peck:]

Thanks. Mike. It's Ty. So I'd say that first of all the – we are not giving guidance right now for the differential for 2016 until we figure out a little bit more as to what we're going to weigh in those bookends. At the high end, I think we see 85% of that being sold through a premium price through the basin. And then I think beyond that, we have opportunities like I talked about earlier to be active in the release market as well as the connectivity to the different new pipelines, and we'll be the first to be able to jump on and get deals done.

[Michael Kelly:]

Okay. Is there anything that stands out that's different in 2016 versus 2015?

[Ty Peck:]

Let me – Yes, I was going to say, the other thing I'd say is, to give a little bit more color is to go to the slide deck to see if where our portfolio changes from 2015 to 2016. It ticks up a couple cents in 2016 and then it has a little bit more Gulf exposure in 2016 beyond. So just because of the nature of that, I think gives you a flavor for what those differentials might look like and then like I said, the percentage in basin versus out will kind of give you a bookend.

[Michael G. Moore:]

The beauty – Mike, the beauty of our portfolio is our optionality. So as different pricing point change, we certainly have the option of moving our molecules around and that's a very big strategic advantage in our opinion to our firm transportation portfolio and makes us very unique. For instance, as the Gulf Coast market demand continues to improve, we'll be able to move a lot of molecules down there. So we've got a lot of options and that's why it's difficult at this point to tell you specifically what the differentials are going to be. We're going to have to wait and evaluate what the best options for us are.

[Michael Kelly:]

Understood, thanks. And just a quick one. What's the right number of days to model for you guys in terms of cycle times to spud to TD in the dry gas? Thanks.

[Michael G. Moore:]

24, 25 days is probably the right way to think about it here in the dry gas window.

[Michael Kelly:]

All right. Appreciate it. Thank you.

[Michael G. Moore:]

Thanks, Mike.

[Operator:]

Our next question comes from Dan Guffey from Stifel. Your line is open.

[Daniel D. Guffey:]

Hi guys. Thanks for the comprehensive update this morning. You contracted for FT [firm transportation] into early 2018. I guess, how do you think about adding additional volumes in the out years and how do you mold that FT as you move forward?

[Ty Peck:]

Hi. This is Ty again. You know, as far as, I think I understand your question being, or are you meaning additional FT projects we've subscribed to?

[Daniel D. Guffey:]

Correct, yeah adding additional commitments.

[Ty Peck:]

I think we continue to look at those, to look at where the demand is coming from, where the upside is. I think we're all looking at Mexico, we're all looking at LNG. We are all looking at the conversion from coal to gas. So when we look at those type scenarios and see where those – that demand is, we are looking at the FT that supports it. And currently we've got to look at both ends. We've got to look at what producers have already subscribed to as well as what's in market to subscribe to, and make sure that's being fully taken advantage of before we go and try to subscribe or subscribe to another project, if that is the bottleneck is already happening. And so we're constantly monitoring that with the results that we see, our peers are seeing as well as what the demand growth is having as well. So both ends become pretty critical to make sure that balance is happening and we are definitely, if that pans out, and we see the need, we will do additional FT.

[Michael G. Moore:]

It's an interesting market right now dynamic, because of course you have a lot of rigs that came down and you have producers who took out a lot of FT early on assuming they were going to have a certain level of activity and certain volume of production as a result of that activity. Now, with folks cutting back on capital budgets and probably another swath here going forward, there's lots of FT available in the release market. And we are certainly well positioned to take advantage of that. Ty is looking at that. But we want to make sure what we find is additive to our portfolio and gets us to the right places and gives us the right options. These are twenty-year financial commitments. So we've got a great FT portfolio that allows us to grow next year with 90% of our product being sold in premium pricing points. And as we move forward, we'll continue to layer on the incremental projects that are additive to us.

[Daniel D. Guffey:]

Okay. Thanks. And then switching gears, looking at completion styles, they still vary widely in the dry window between different operators. I guess can you discuss your current standard design in terms of stage spacing, sand, liquid volumes, et cetera? And then anything you guys are currently testing to improve recoveries?

[Michael G. Moore:]

Well, it's interesting. You're right. There still is quite a variance among producers out here. We continue to like the recipe that we have. We're still generally at 180-foot stage spacing and we generally still pump 1,500 pounds to 1,800 pounds per 1,000 lateral foot of proppant. And we think stage spacing is maybe more important even than sand. So while our completion folks continue to test different ideas, generally, we really like the recipe we have, we like the results that we've had. And, right now, we're not really making any wholesale changes. Certainly there's a big bang for our buck here when you're considering cost EURs and stage spacing. And so it's a cost-benefit analysis. So we'll have to see. But, generally, again, lateral spacing is important and we're excited about the opportunity to move these wells closer together. We do know that longer laterals are very important to results. So we'll continue to try to drill the longest laterals possible. But I'm giving you a long-winded answer. The short answer is we like the recipe that we have, and we're not making any wholesale global changes at this point.

[Daniel D. Guffey:]

I guess just a quick follow up, if I could. You mentioned the longest laterals possible, you'll drill your type curves at 8,000 feet. I guess what is your capacity to go longer? On what percentage of your acreage are you able to drill those longer laterals?

[Michael G. Moore:]

That's a good question. I don't know that off the top of my head. They're still working on putting units together. On some of our acreage, they don't have all of those forms yet. From a technical limits perspective, I think we view when you get into 10,000-foot to 12,000-foot range, you begin to have challenges from a coil tubing perspective, from just getting your frac put away that far. So you can get up to there pretty efficiently and anything below there is fairly easy and we're very efficient at it. We've done some very long laterals, but I don't have the longest laterals that we have available to us right now in front of me.

[Daniel D. Guffey:]

Great. Thanks for all the details and congrats on a good quarter.

[Michael G. Moore:]

Thank you.

[Operator:]

Thank you. Our next question comes from the line of Jeff Grampp from Northland Capital. Your line is open.

[Jeff S. Grampp:]

Morning, guys.

[Michael G. Moore:]

Jeff.

[Jeff S. Grampp:]

And great job on all the additional color on the slide deck and 2016 and everything. I guess one of the things that I was interested in my getting some more color on as we look across your different dry gas areas on a rate of return basis, it looks like the east area's the strongest. But not a lot of planned activity there in 2015. So just wondering, is that infrastructure related, is that because you guys just want to methodically move out there? Or just curious on how the eastern area gets integrated into development over the next couple years.

[Michael G. Moore:]

That's acreage that we just picked up. And those acquisitions we haven't even closed on the stuff that's the furthest east, the Paloma acreage. So we'll start working on that. It's going to be a while. Ty's working on the infrastructure piece out there, as we mentioned I think on our last call, related to Paloma. So we're certainly moving full-steam ahead on getting everything that we need in place to get that developed. Midstream, that I mentioned that Ty's working on, is in the LOI phase right now. So we're right on schedule with the infrastructure piece of that project. And as we mentioned, we're tentatively bringing in – we brought the fourth rig in, started drilling on some of that acreage. And then we had previously announced we'd be bringing a fifth rig in also to help us with that. And of course we'll wait and see what we decide to do for 2016, but we're certainly incorporating that acreage in as quickly as possible into our development plans, but it takes a while to get those units put together and start that development. But we're on track.

[Jeff S. Grampp:]

Okay. That's helpful. And then just looking at the updated condensate type curves. And given the returns that you guys can get in the wet gas and dry gas areas, just wondering how that fits into the story longer term. It looks like it may be struggling to compete for capital with your other areas. And obviously you don't need the extra liquidity like you guys laid out with your position now. But does that become a divestiture candidate if there's some interesting acquisition opportunities elsewhere, or how do you see that area fitting into the story?

[Michael G. Moore:]

Look, under today's commodities prices, certainly the returns in the condensate window aren't really there for us. We've been pretty open about that. We view it more as optionality. It's not a great deal of locations. If you look on that slide, it's about 260 locations out of our total. We'll have to wait and see. I can't say today what exactly what we're going to do with it. We did like the condensate window, but we certainly need a better commodity price for it to make sense for us. So, we'll have to wait and see. We've got some time on those leases. They're not expiring right away, so we'll wait and see what the options might be for us.

[Jeff S. Grampp:]

Okay. Great color and great results, guys.

[Michael G. Moore:]

Thank you.

[Operator:]

Thank you. Due to time, our last question will be from Dave Kistler from Simmons & Company. Your line is open.

[David W. Kistler:]

Good morning, guys.

[Michael G. Moore:]

Hey, Dave.

[David W. Kistler:]

One just last question respective to the midstream and processing agreements that you established early on that I believe cover the development in the wet gas and the condensate windows. Can you talk a little bit about utilization there? Is there any overhang of costs? Are there any kind of commitments you need to deliver on? And this kind of comes part and parcel with a more focused activity in the dry gas window.

[Ty Peck:]

This is Ty, because we're an early on anchor, we don't have overhang commitments. We do have a set up to make sure that we're getting the best value for the product that's coming out. So but, no, we have flexibility as we go forward across those phase windows.

[Michael G. Moore:]

And then one thing I might add just to remind everyone, we were an early mover in this play and we were the original partner for MarkWest in their build out of the Utica. So we were an anchor tenant, we got anchor tenant status, which gives us a different kind of relationship with MarkWest than some other folks have. So, we have an acreage dedication and we don't have a volume commitment. So, again, from a cost perspective, we're strategically advantaged.

[David W. Kistler:]

That's great news. And then to the extent that you do have an acreage dedication there, is that something you could remarket in a different time for people who don't have the luxury of being in the dry gas window?

[Ty Peck:]

No, that's not. I would say that's – I don't want to get into details of how that would all work, but as far as someone else coming through there and the – it would be available to someone else, I guess. Trying to understand your question.

[David W. Kistler:]

Well, I was more thinking about it in terms of the flexibility it provides. It's great news that there's no overhang there. But I was just curious if there could be upside optionality or benefit from that over a longer term basis.

[Ty Peck:]

Yeah, no, I wouldn't say – there's, no.

[David W. Kistler:]

Okay. Really appreciate it. A great work on the quarter guys and fantastic results on the dry gas window.

[Michael G. Moore:]

Thanks, Dave.

[Operator:]

Ladies and gentlemen, we have unfortunately run of time today. At this time, I would like to turn the call back over to Mr. Mike Moore for any closing remarks.

[Michael G. Moore:]

Thank you, Amanda. We appreciate your time and interest today, as we know this is a very busy time for many of you on the call. Should you have any questions, please do not hesitate to reach out to our Investor Relations team. This concludes our call.

[Operator:]

Ladies and gentlemen, thank you for participating in today's conference.