Gulfport Energy Corporation (GPOR) Q2 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to Gulfport Energy Second Quarter 2014 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. And now I'll turn the conference over to your host, Jessica Wills. Please begin.

Thank you, Tyrone, and good morning. Welcome to Gulfport Energy's Second Quarter 2014 Earnings Conference Call. I am Jessica Wills. With me today are Mike Moore, CEO and President; Ross Kirtley, COO; Keri Crowell, Vice President and Controller; Mark Malone, Vice President of Operations; Stuart Maier, Vice President of Geosciences; and Ty Peck, Managing Director of Midstream Operations. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performances 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 can be posted on our website. An updated Gulfport presentation was posted yesterday evening to the website in conjunction with yesterday's earning announcement. Please review at your leisure. At this time, I would like to turn the call over to Mike Moore.

Thanks, Jessica, and good morning to each of you. As announced in the press release yesterday evening, Gulfport reported approximately $137.9 million of EBITDA, $56.6 million of operating cash flow and $47.9 million of net income during the second quarter of 2014. Adjusted net income, comparable to analysts', to non-GAAP measure was $6.1 million or $0.07 per diluted share. In terms of capital expenditure during the second quarter, we invested a total of $156 million. As of June 30, 2014, we had $75.3 million in cash and had $339.3 million of total debt outstanding, which includes $40 million drawn on our revolving credit facility. Gulfport experienced strong price realizations during the second quarter of 2014, with net gas prices settling approximately 95% of the average NYMEX last-date settlement price, and our NGL realization settling approximately 47% of the average at WTI for the quarter. Both of these exceeded the company's expectations based on a midpoint of bases differential guidance ranges previously provided this year of 90% to 95% of NYMEX for natural gas, and approximately 45% of WTI for natural gas liquids. Production for the second quarter averaged approximately 26,725 BOEs per day. As we guided on our first quarter call in May, this volume was relatively flat for our first quarter production levels, which was primarily a result of 14 wells being taken off-line for ongoing completion activities in the Utica. During the month of July, Gulfport averaged approximately 33,952 BOEs per day of production, and during the first 5 days of August, production has averaged approximately 43,602 BOEs per day. The July and August production indicates we are making significant progress to delivering on our anticipated industry-leading growth in 2014. This past quarter, Gulfport's management team worked diligently in implementing the company's new development strategy in the Utica Shale, as outlined on the first quarter conference call, and we are excited to share with you some of the results we have seen today. Gulfport spudded its first well at Utica approximately 2.5 years ago, and while we have learned a substantial amount about the play, we continue to collect and analyze data to ensure that we develop the asset in a way that yields optimum near-term and long-term results. In the Utica, we continue to make solid improvements at the drill bit on average days from spud to rig release and average feet per day drilled. During the second quarter, one of the drilling teams' initiative was to focus on the high grading of equipment for our rig fleet. While we are still in the middle of this process, Gulfport drilled 20 wells in the second quarter with an average drill time of approximately 24 days per well, a decrease of 39% over the average drill days of 2013. I think it is impressive to note, as you can see in the presentation posted yesterday evening, we have increased the average number of feet drilled per day in the play, 52% over the 2013 program. When looking at single well metrics included in these averages, Gulfport's drilling team achieved company records during the second quarter. The team drilled the company's longest lateral to date of 11,147 feet and spud to rig released a well in less than 14 days, drilling approximately 1,025 feet per day. As we make progress at the drill bit, for the remainder of 2014 and looking into 2015, Gulfport will remain focused on creating efficiencies that enable the company to shorten drill times and increase levels of field activity with our current rig fleet. During the second quarter, our operations team also made headways towards developing an inventory of wells in the completion crew. Gulfport utilized the same 3 third-party completion crews through the second quarter and currently have approximately 3 pads in inventory. With our current rig activity, we had contracted 3 third-party completion crews for the remainder of 2014 and hold an average of 3 to 5 pads in inventory at all times. Gulfport is seeing tangible benefits through the creation of a well inventory and a repetitive utilization of the same completion crews working together from pad to pad. During the second quarter, Gulfport realized a 30% reduction in the time associated with some positive plug drill outs following fracture stimulation relative to 2013. These efficiencies reduce days on location, save on completion cost and allow for faster return in line date for associated wells. Later in the second quarter, Gulfport brought online 10 wells in the Utica, 8 wells in the wet gas window and 2 wells in the condensate window of the play. In the wet gas area, the wells had an average 7-day drill site [indiscernible] rate of approximately 2,392 BOEs per day, with a 42% liquids mix and an average perforated lateral length of 7,925 feet. In the condensate area, the wells had an average 7-day drill site [indiscernible] rate of approximately 955 BOEs per day with a 68% liquids mix and an average lateral length of 8,298 feet. All of these results just mention the included [ph] wells that came online under the company's new managed-pressure program in the play. The operations team continues to monitor the effects of the program across all phase windows. And posted in our presentation yesterday evening, the company has provided an illustration that compares pressure against cumulative well production. The best way to see the effects of a more disciplined pressure program is to compare the flowing pressure upstream of the choke after equal amounts of production have been produced. As a rule of thumb, our engineers manage the wells to maintain or -- at or below a pressure drop of approximately 100 psi per week. A well can see variation from this method early on, but the initial indications from the data suggest that by managing the pressure early in a well's life, we will be able to preserve the integrity of the reservoir and maximize the ultimate recoveries from the well. With regard to our midstream activities. On the processing front, during the first weeks of July, MarkWest performed scheduled maintenance and began phasing in additional compression horsepower on a rich gas system. We expect all production by year end to be on a low-pressure system, which will improve operational run time and the efficient implementation of our managed-pressure program. While we did experience downtime during the transition, we have seen production benefits and expect to continue to benefit as additional compression horsepower is added throughout the year. We recently announced that Gulfport has entered into agreements with both Rice Energy and MarkWest Energy in connection with the buildout of the dry gas gather in the play. Together by mid-2015, MarkWest and Rice's dry gas system will have the capacity to provide over 1 Bcf a day of natural gas into multiple interconnections, including the REX pipeline and TETCO. Over the last several months, each party has commenced constructions on their systems, and we remain confident in each party's ability to construct the necessary infrastructure needed to remain on target with our planned tie-in dates and 2014 guidance provided in May. In relation to pricing and the current environment surrounding the northeast operators, Gulfport has been diligently working toward securing firm commitments that offer deliverability of our products with attractive pricing hubs. Provided in the presentation yesterday evening, you may find an update on the long-term transportation and sales agreements that Gulfport has put in place to align with our projected growth in 2014 and beyond. The recently announced capacity on REX and ANR is additive to our portfolios as we continue to expand our access to premium markets, and as such, we reiterate our expectation of 2014 natural gas pricing prior to the effective hit to realize between 90% to 95% of NYMEX settlement prices. To recap, through the first half of 2014, Gulfport has realized a natural gas price of approximately 97% of the NYMEX settlement price. For the balance of 2014, we expect to see some slight pressure on realized prices as we wait to start up Cadiz II. Once on line, Gulfport will utilize an additional 150 million cubic feet per day of gas delivery to the Midwest market, which we expect to provide a significant increase to our realized price in the latter months of the year. In relation to our peers in Utica, Gulfport sits in a unique position, as we were first mover in securing early transport to premium market. That jumps available for use timely and in conjunction with our production profile. Gulfport continues to acquire acreage in its focus area in Ohio and West Virginia and today, has approximately 184,500 acres under lease. Our team firmly believes adding on top of our top-tier position is an accretive investment for the company, as we add new acreage to block up units and increase our position in one of North America's premier shale plays. Moving to the company's other operational areas, starting with Canada. During the second quarter of 2014, Grizzly's Algar Lake facility steam was circulated through all 10 well pairs, with 1 well pair being converted to SAGD production mode late in the second quarter. Grizzly commenced commercial production effective May 1, with bitumen production averaging 510 barrels per day in May and June, and exited the quarter producing approximately 1,200 barrels per day. In June, 50 railcars were loaded with dilbit and shipped through the Windell Terminal to the United States Gulf Coast markets. The plant continues to consistently produce in commercial quantities and today, production at Algar Lake is roughly 1,900 barrels of bitumen per day. Initial reservoir and plant performance continues to exceed management's expectations, and Grizzly currently anticipates the project to reach its peak production of approximately 6,200 barrels of bitumen per day in the second quarter of 2015. Now turning to Southern Louisiana. In Southern Louisiana during the second quarter, we drilled a total of 13 wells and have performed 46 recompletions. Currently, we are running 2 rigs and are drilling ahead on our 25th and 26th wells of 2014. In May, we discussed 3 items that attributed to our 2014 guidance revision. One, the creation of a well inventory; two, the implementation of a more conservative managed-pressure program in all phase windows of the play; and three, the potential delays associated with midstream. Today, we are finalizing Gulfport's progress and actions towards each of these goals. As mentioned, we currently have 3 pads in inventory and plan to hold 3 to 5 pads in the completion queue at all time. Shifting our production strategy towards a more conservative managed-pressure program has yielded encouraging initial pressure responses from our recent wells tied into sales. Early data suggest that this emphasis on reservoir pressure conservation will prove to produce higher ultimate recoveries. Lastly, we continue to work closely with our third-party midstream providers, and believe the additional risk applied to certain tie-in dates was appropriate and remain confident in the anticipated schedule assumed to date. We reported second production in line with our guidance. And during July and our early August production of 43,602 BOEs per day, Gulfport has generated significant growth, and we look forward to the next few quarters as we continue to execute on our 2014 program. We currently anticipate total company production during the third quarter of 2014 to be approximately 40,000 BOEs per day and expect to bring online 14 to 20 wells throughout the quarter. In summary, with 2.5 years of drilling in Ohio under our belts and over 60 wells producing, we believe Gulfport sits in a very unique position compared to other companies in the play. Being one of the first operators in a new shale play in a short amount of time, we have conducted a considerable amount of science to help us develop the play to yield optimal results. We made the necessary commitments to anchor and secure significant midstream infrastructure from the well head through the plan. Further, we made early commitments to pare our production to the limited available backhaul capacity to premium markets. We have increased the number of employees 258% just entering the Utica, and I am pleased with the exceptional staff we have in place and confident in their ability to deliver on expectation. Gulfport accomplished all of this while maintaining a pristine balance sheet. Looking at the remainder of 2014 and into 2015, with the increased efficiencies seen today, Gulfport expects to see attractive growth while maintaining appropriate levels of operational activity. We intend to fund these activities through a combination of available cash on hand, borrowings under revolving credit facility, the strategic sale of Diamondback stock, proceeds from the potential service of the IPO and a potential high-yield offering. This concludes our prepared remarks. Thank you again for joining us for our call today, and we forward to answering your questions.

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

[Operator Instructions] First question is from Neal Dingmann of SunTrust.

Say first, Mike, just a question, dialing a little bit more on the well completions that you spoke of. Can you walk through how many you had come online? Just -- I just want to make sure I get the numbers right for second quarter. And then I think you mentioned 14 to 20 expected to come on for third quarter and fourth. How many have already come on that quarter? And then secondly, around that, the type of wells, as far as between the wet gas and conde and dry gas?

We had 10 wells, Neal, come on line in the second quarter. For the third and fourth quarter, we expect 14 to 20 wells each quarter. And the third quarter, I will tell you, we've already brought on 7 wells, and all of those are wet gas wells. What we expect for the rest of the third quarter is again, mostly wet gas wells. We have one condensated pad coming on in the third quarter. And then in the fourth quarter, again, all wet gas wells coming on, except for one gas pad coming on.

And what you mentioned earlier, Mike, with the contracts in place, I guess, it's fair to say more than ample takeaway for that type of wet gas that should be coming on the second half of the year.

Yes, this is Ty Peck. Yes, we're -- we will be utilizing our capacity throughout the year and anticipate the Cadiz II facility coming up to fully utilize that capacity.

And Ty, let me follow up with that. Just on -- I'm looking at, I guess, Slides 18 and 19, where it talks about the firm transfer. I want to make sure I have this right. So all but -- what is it, Ty, all but 10%, just roughly 10% then we'll go into the Appalachian market. The other 90%, you already currently have locked into FT, so it'll realize that 90% to 95% NYMEX that Mike talked about? Or is that just sort of the blended?

I would say that it's going to be, I'd say, more around 80% going out and 20% in the Appalachian. And just some of that's due to operational ups and. downs. We'll send as much as we can. If I can get 90% out, I'll get all the 90% out. But it'll be more around between 80% and 90% out of the basin.

Okay, and then last, if I could, just switching gears, Mike. Just on the oil sands. Obviously, progress is certainly being made there now that you're railing that. Any comments you can make on potential monetizations? Or how you see that maybe playing out in the next couple of quarters?

No, it's a good question, Neal. We're very, very encouraged by the early production results from the Algar 1 facility. We're ahead of the ramp-up schedule. And full production is 6,200 barrels a day, which was originally anticipated to be mid-2015. We haven't changed that yet. But I think the 2 things that we talked about this morning, which are current production and also the ability to rail the product to the Gulf Coast, both put us in a position to begin thinking about a potential path event. But honestly, Neal, I think it's going to -- it's more likely you're going to be 2015 capital event.

Our next question is from Ron Mills of Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: A couple of slides ahead of what Neal was asking about, just on the cumulative type curves of the optimized wells versus the prior wells. It looks like the managed-pressure program is making a huge difference in the condensate wells and even the wet gas, looking like it's about to cross over the prior -- any additional commentary around that in the pressure drill down? Is this as you would've expected, better than expected? I guess, I'm just trying to get more color behind that chart.

Well, I think, I'll start and then I'll let Mark jump in here as well. I would have to say that we're very encouraged by what we're seeing today. And this is exactly what we hoped, if not a little better than anticipated. This is really, as you know, about managing the pressures. And so for example, some people were focused on the 7-day rates for some of the new wells. It -- rates are going to be different under this new managed-pressure program. So it's really about pressure versus ultimate volume, and that's what we're trying to manage here. Mark, you have anything to add to that?

I'll just echo what you said. I mean, we're managing the pressure. And as stated in the prepared remarks, we're managing to a pressure threshold of approximately 100 psi. So what we're seeing here is really what we hope to achieve and actually planned for. So you mentioned the divergence of those 2 lines in the wet gas, and that's exactly what we expect to see. So the ultimate recovery should be substantially greater. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay, and am I reading too much into the map on Slide 13 of your presentation? It looks like you have 3 of your rigs over in the condensate window now versus 3 months ago, you didn't have any over there. Is part of that because of the results you've seen from these managed-pressure program? Or how do you see the allocation of rigs between the wet gas condensate and dry gas windows over the remainder of the year?

Well, that's just a temporary situation. Sometimes we scale back and forth with different windows with rigs, depending on the units that we want to drill. So basically, the rig alignment that we talked about for the year is still the same across the play. So it's just how the drill schedule worked out, so we will have the same allocation of rigs for the rest of the year that we've talked about before.

Our next question is from Jason Wangler of Wunderlich Securities.

Curious -- you're talking a lot about the condensate and wet gas side. On the dry gas side, just kind of when -- and I assume, it's kind of infrastructure based, when we're going to start to see some production coming from that side? Is it when MarkWest and Rice really get up and running? And if so, when you think that's going to start kicking in?

Well, the only dry gas pad we have coming on the rest of the year, Jason, is going to be later in the fourth quarter. So certainly, MarkWest and Rice are going to have their systems ready for us whenever we're ready for those. But yes, we got -- we certainly got capacity out there. But we don't have -- again, we only have a 4-well pad coming on the dry gas window this year in addition to the other 2 wells we have.

Okay, that's helpful. And then -- and I think Ron kind of hit on it a bit. But just maybe with the rig efficiencies you're starting to see, are you comfortable with the 7 rigs and kind of where you have them? Or how do you kind of see that evolving, whether it's upgrading some rigs even further or going with that? And obviously, you already talked about completion, but just where you see the rig count kind of moving maybe the rest of this year or even as you look into '15?

Yes, that's a good question. Certainly, we have to give a lot of credit to our drilling team for the efficiencies they've been able to achieve out there. Very, very excited about bringing our average drill time down to 24 days. Obviously, with the 7-rig program, that means we're able to drill wells faster so we can drill more wells. Seven rigs right now is the right amount of rigs for us with the drilling efficiencies that we're seeing. We've played around with a lot of different scenarios for 2015. Not really ready to talk about that yet, Jason. But certainly, the efficiencies are making us really think hard about what the right number of rigs is for us. So we'll talk about that more probably on our third quarter call. But it's certainly very exciting to see these rig efficiencies, and that's, obviously, going to help our well cost as well.

Sure. Maybe just on that, just -- if I could sneak one more in, just -- as you kind of upgraded and swapped out rigs, is that pretty much done? Is there more to do on the 7? Or are we pretty much at the rigs that we want going forward?

Jason, this is Ross. I think we're pretty well settled on the 7 rigs for the remainder of the quarter. But to answer your question more directly, we're always in the process of upgrading rigs, upgrading crews and vendors. So that will be a process we'll continue to tweak as we go forward, and it'll be an ongoing and never-ending process of getting efficiencies from our vendors and particularly our inquiries [ph].

Our next question is from David Ostler (sic) [Kistler] from Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly going back to the managed-pressure wells, just for a second. Can you talk a little bit about what you're seeing as far as any changes on the gas-oil ratio or anything like that associated with managing those pressures?

No, we're not seeing any changes in the gas-oil ratio. We're managing based on the 100 psi threshold, so really no change there. David W. Kistler - Simmons & Company International, Research Division: Okay, that's helpful. And then maybe too early to tell, but we're seeing the crossover that was indicated in the earlier comment. How do you guys look at what the PV-10 of those wells are going to be under the new managed pressure? Just trying to get a sense for understanding that there's a little acceleration earlier by flowing them faster, but now obviously, higher EURs and a pretty early crossover probably -- I don't want to jump to conclusions, but probably supports a higher PV-10.

Well, I -- and that's a good question. And as we mentioned on our last quarter call, our expectation would be that the shape of the curves would change under this new managed-pressure program. It does seem to be doing that. We're certainly data driven and we'll continue to monitor that. But we think, ultimately, we're going to improve both NPV and EUR. Mark, would you add anything to that?

No, just that we're very early in the program. The IP rates that you see there are very short so there's a lot more data to gather. But the fact that we're -- if you look -- focus on the pressures and the difference in pressures between the old and new wells, that's exactly what we're managing for, and that's exactly what we wanted to see. So right now we're pleased with it. David W. Kistler - Simmons & Company International, Research Division: Great, appreciate that. And one last one, just looking at G&A and LOE on the quarter, they came in kind of a little bit higher than probably expected or then to your guidance. But I suspect the ramp up in production brings those within guidance, hence no change? Or are we looking more towards being at the high end of guidance on those? Just looking for clarification there.

Keri, you want to answer that?

Sure. Yes, we do expect the back half of the year that with the increase in production, that both G&A and LOE will level out and be well within our guidance.

The next question is from Dan Braziller of Jefferies.

I was just wondering what rate you're bringing the newer wet gas wells on at -- in the managed -- under the managed-pressure program? And what -- I know it's early, but what the early declines? If there are any declines or if the wells are holding flat, what those may look like?

Dan, this is Ross. We're really not focused as much on rate, what would bring the rate -- the wells on at rate. But we're more focused on maintaining the pressure. Mark, would like to step in and give a little bit more color?

Yes, I mean, we try to maximize our production each -- every opportunity we have. So we're all -- I don't want to say we ignore rate, but right now, the focus is more on the pressure side.

And just so that we're clear on this, because I want to make sure we all understand, each well is different out here. So each well's pressure will tell us how to produce these wells. And that's really what the -- we're monitoring pressure and adjusting rates accordingly.

So would you say that even just within the wet gas window itself, you're bringing wells on at fairly variable rates because you're seeing variable pressure per -- on each well?

Well, I mean, the intent is, of course, is to extend the flat production period of the well by managing the pressure. So we should see that and narrow our scene [ph], quite frankly. So the actual production for each well is going to vary based on that pressure response.

Our next question is from Leo Mariani of RBC.

Guys, can you talk a little bit more to what you're seeing in terms of current well cost in the Utica today?

Well, we're still sticking with our $9.5 million average well cost per year, Leo. I will tell you that we are not currently seeing any pressure on prices. Ross, I'll let you jump in here as well.

Yes, Mike. Leo, we have been very proactive in getting contracts out for at least 1 year. So -- and we also have our vertical integration with Stingray, which really helps us secure our frac spreads at our sand -- some of our sand sourcing. So we really haven't seen any pricing pressures, right, as far as -- of course, we anticipate those. And that's why we constantly work with our bidders and try to keep our cost down going forward.

Okay, that's helpful. And I guess just in terms of gas price realizations, you guys talked about 90%, 95% of NYMEX. Just wanted to clarify that. Is that going to be after transportation cost firm or before?

It's going to be after. You saw in our slide deck, we had kind of the average that we want to see through the next couple of years. But for the most part, you'll see that, that is getting to a market that is the Midwestern markets that we're seeing today, the premium to NYMEX on so...

Okay, that's helpful. And I guess, in terms of third quarter, it looks like production's ramping up pretty nicely here in July and the first 5 days of August. Are you guys expecting any other sizable shut-ins at all during the rest of the third quarter?

That's a good question, Leo. We do not expect that for the rest of the year. Of course, sometimes there are unexpected things that happen that you can't control. But we're really beyond those shut-in periods. We've got those 14 wells back online that we had shut in to do some additional work out there. And we think we're beyond shut-in -- those shut-in issues that we've had in the past.

Okay, that's helpful. And I guess in terms of Utica acreage, something you guys want to continue to acquire more. I mean, how much do you guys think you can realistically pick up in the Utica, kind of rest of the year and into next year? And what type of prices are you guys seeing?

Well, you saw this time that we only got added 4,500 acres, a little bit of that was West Virginia. And so we're being very strategic, I would say, in the acres that we're adding at this point. What we're really doing is blocking and tackling the units, filling those in as much as we can over in Ohio. And there hasn't really been any pressure, Leo, on pricing over in Ohio. So generally, it's still going for maybe $7,000 an acre.

Our next question is from Amir Arif with Stifel. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: You guys have been building your well inventory as you've suggested, and it seems like if you're drilling 20 wells a quarter, bill us a little more in the second half, can you just give us a sense of where that well inventory is going to be at year end? And if that's at a sustainable rate in terms of your connectivity -- activity levels heading into '15?

Amir, we're currently trying to maintain a 3- to 5-well inventory -- or 3- to 5-pad inventory, which will equate to 12 to 15 wells. We just are firm believers in this, that it will allow us to gain efficiencies as we complete these wells, so it is something we'll continue to build on and gain efficiencies going on. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: And then, so you're essentially already there, so it's essentially going forward, that inventory number doesn't really change much for -- at least, at this current activity level, is that fair?

That's fair, yes. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay. And then can you give us a sense of what the exit rate for '14 looks like?

We're still expecting to exit in the mid-50s. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: That's corporate production, right? Or that's just the Utica?

That's correct, that's corporate production. Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division: Corporate production, okay. And then just final question on the changes in the design completions, and great improvement with the pressure. Just choke back program, but are you -- and I know that these stages are already pretty high. But are you still looking to make modifications in terms of the -- I mean, you get laterals and your frac stages at both the tech [ph] side but are you still playing around with optimizing? So do you feel you're at a comfortable level now?

This is Mark Malone. I think the answer to your question is both. I mean, we're very comfortable with our current frac design. But we continue to look and watch what our peers and partners are doing. We meet with them frequently and so we're paying attention. But to answer your question, really, I think we're well pleased with what we got in place right now. But not to say can not be -- not to say, it can't be optimized.

Our next question is from Ipsit Mohanty of GMP Securities.

But if I could just stay on the dry gas part of it. I know you say 4 wells on the past, but you -- is it fair to assume there could be in that AMI portion of the dry?

That's correct.

And if you might, in your guidance, how much -- just your last -- percentage of production, do you expect to get from the Rice-operated portion of the AMI?

It's going to be at -- I'd probably refer back to Rice with their operations. But they're going to be similar to, I believe, where -- the same activity we're going to have out there in the dry gas portion.

Very similar to what you will have in the dry gas portion, correct?

That's correct, from what we can see right now.

Yes, this year, we just have a handful of wells coming on over there. So it's not material this year.

Right, okay. And then despite your condensate work, clearly, the newer ones doing so well compared to the older. You don't plan to bring online any more condensate wells for the rest of the year, if I heard it right? Is there a reason why?

No, there's a condensate pad coming on in the third quarter, 4-well pad.

And that will be it?

That's it.

The next question is from David Beard of Iberia.

Could you maybe comment or give a little color on the 7 wells that you brought on in July relative to their sales rates, relative to your type curve?

Well, we gave you the -- you're talking about the 7 wells we brought on in the third quarter?

Yes, correct.

Okay, they're all wet gas wells and we gave you those rates. I mean, what -- I'm sorry, what's your specific question?

I thought you gave us the rates for the second quarter tie ins. I'm just talking about the ones in early July that you brought online. Or did I miss that? Did you give us the...

No, I understand what you're saying now, I'm sorry. We haven't provided that yet, David, to anyone.

Okay, no, and I understand. And then relative to your land acquisitions, could you give us a little color maybe in terms of what counties you're looking at in Ohio? Or anything there just would be helpful.

Well, it's all dry gas acreage. And it's generally the opportunities where we're blocking and tackling our units is generally Belmont and Monroe.

Okay, and would that mean that you're looking in West Virginia? Would be more in Marshall County?

No.

Would you look down into Whitesell [ph]?

No, we're pretty geographically focused due east of our existing acreage position in West Virginia, and we've certainly geologically high graded. But for competitive reasons, we're not talking much yet about West Virginia. I'm sure you understand.

Next question is from Marshall Carver of Heikkinen Energy Advisors.

The -- just wanted to get some clarification. The exit -- exiting this year in the mid-50s range, would that be a 4Q rate average over 4Q? Or is that more a December 31 rate?

Well, I'm specifically talking about exit rate. But I'm sure you can do the math. We've given third quarter production as well, so I think they end up coming out pretty close.

Okay, so the fourth quarter full rate could be close to the exit rate?

That's right. There's not a great deal of growth built into the fourth quarter, but there is some.

Got you. Okay, that makes sense. And then I think in the prepared remarks you mentioned -- did you mention a potential service company IPO as the source of proceeds?

That's correct. We announced that some time ago and it's in the S-1 process, so you understand that we can't really talk about it but that is still an ongoing process.

Next question is from Jeff Grampp of Northland Capital Markets.

Just a question on frac density. We're seeing a lot of operators in the basin and other plays talk about getting oil denser with frac stages or doing any kind of increased proppant test. Is that anything you guys have been looking at or been testing at all?

Jeff, this is Ross. We have, as you know, we have the Darla project going on where we're frac-ing right now and testing a number of different parameters on that, which proppant distribution, pool size and all those are in that equation. And I'm going to let Mark kind of lay in here on some of the specifics that he's testing.

Yes, we've got several tests planned. We've done several tests, historically, all dealing with stage basin perforation design, prop volumes. So we've kind of been there on a lot of those issues, but we are watching what the market's doing. We know that trends are heading that way, and we do have some tests planned.

And just add to that, we're in the fortunate position of having 67 wells producing. And some of those wells, we tweaked a little bit. We've not made, currently, any broad-brush global changes to design, but Ross and Mark and their group certainly have the flexibility and the ability to test different things. We have to be a thought leader in frac design in Utica, and that's what we're trying to be. But we'll test different things. We'll watch our peers. And we've always said that this play would develop over time. It's still a new emerging play, and I think what we're going to see ultimately is there's going to be a little different design probably for each phase window. That will be a standard, but we're not quite there yet. We like the frac design that we have, but we are certainly testing different theories.

Okay. And then, Mike, shifting over to some of the liquidity options that you noted in the prepared remarks. Just kind of curious if Louisiana kind of fits into that category at this point in time? Or is that an asset you guys kind of like having as a source of free cash flow? Our just kind of any commentary on how that asset fits into the portfolio.

Yes, it's a good comment. We actually get asked that quite a bit. It is -- it does provide cash flow to help us develop Utica. It's pure oil. It's priced at LLS. It is not an asset that is currently part of our liquidity plans.

Next question is from Jeffrey Capital (sic) [Campbell] of Tuohy Brothers Investments.

First question I wanted to ask was just -- you mentioned the rig efficiencies that you've been achieving. Do you foresee any need to increase completions first? Or does the inventory management sort of obviate that need?

We're pretty well focused on 3 crews for the rest of the year. We may have to be put in on occasion to try and catch up. But pretty well focused on just maintaining a 3 crew right here. So we think we got that nailed down pretty well with our pad inventories. We're pretty comfortable where we're at.

Okay. And the next thing I want to ask was -- we're starting to hear more about ethane export in the Appalachian region. I just wondering, are you developing any longer-term plans to try to reduce ethane rejection perhaps along those lines?

Yes, this is Ty. We are out in the marketplace looking at both ethane export and supporting cracker development in the basin. So we are progressing on some things and continue to share those as they come more into fruition.

Okay, great. And my last question is, your Niobrara neck of the woods has been heating up lately. Do you still hold your acreage there?

We do still have that acreage. Actually, we have a few wells producing out there.

[Operator Instructions]] Our final question is from Joel Musante of Euro Pacific Capital.

All my questions have been answered.

Thank you, Tyrone. I believe that concludes this morning's call. A replay of the call will be available temporarily to the company's website and can be accessed at gulfportenergy.com. Thank you for your time and interest in Gulfport today. This concludes the call.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program. You may now disconnect. Have a wonderful day.