Paul K. Heerwagen - Director of Investor Relations James D. Palm - Chief Executive Officer and Director Michael G. Moore - President and Chief Financial Officer

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Timothy Rezvan - Sterne Agee & Leach Inc., Research Division Joseph B. Stewart - Goldman Sachs Group Inc., Research Division Jason A. Wangler - Wunderlich Securities Inc., Research Division Biju Z. Perincheril - Jefferies LLC, Research Division Will Green - Stephens Inc., Research Division Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division Gordon Douthat - Wells Fargo Securities, LLC, Research Division Cameron Horwitz - U.S. Capital Advisors LLC, Research Division Brian T. Velie - Capital One Securities, Inc., Research Division Ipsit Mohanty - Canaccord Genuity, Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division David E. Beard - Iberia Capital Partners, Research Division

Good day, ladies and gentlemen, and welcome to the Gulfport Energy Corporation Q3 2013 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to introduce your host for today's Mr. Paul Heerwagen. Sir, you may begin the conference.

Thank you, Nova, and good afternoon. Welcome to Gulfport Energy Corporation's Third Quarter 2013 Earnings Conference Call. I'm Paul Heerwagen, and with me today are Jim Palm, Chief Executive Officer; Michael Moore, Chief Financial Officer; Stuart Maier, Vice President of Geosciences; and Steve Baldwin, Vice President of Reservoir Engineering. During this conference call, participants may make certain forward-looking statements relating to the companies financial condition, results of operations, plans, objectives, future performance and business. We caution you that 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 to our website. An updated Gulfport presentation was posted this afternoon to our website in conjunction with this earnings announcement. Please review at leisure. At this time, I'd like to turn the call over to Jim Palm.

Thanks, Paul, and thank you, all, for joining us for our call. During the third quarter, Gulfport generated approximately $51.6 million of operating cash flow, $97.4 million of EBITDA and $11.1 million of adjusted net income on production totaling 1,193,808 barrels of oil equivalent. In the year to date we continue to make outstanding wells. Let's take a moment to reflect in the past 10 months and the growth Gulfport has experienced since the beginning of 2013. We entered 2013 with 2 rigs, developing our 106,000 net acres, and have since added 5 additional rigs. Today, drilling with 7 rigs and having increased our acreage to 147,350 net acres. We exited 2012 with approximately 6,600 barrels of oil equivalent per day of production, and last month, Gulfport averaged approximately 15,500 barrels of oil equivalent per day, a 135% growth. In addition, we anticipate we will exit 2013 producing 27,000 to 32,000 barrels of oil equivalent per day, over a 300% increase from where we started in January. As you can see, we are experiencing significant growth as a company and continue to add employees to our talented experienced team to support and lead the company in the development of this play. As we continue to bring more wells online and see sustained production, we are learning and developing an understanding of how to best complete and produce wells in each of the fluid phases. Today, we brought online 7 wells in the wet gas phase of the play. As a can see from our presentation posted this afternoon, the wells continued to perform within the type curve. We're pleased with performance of the wells to date, and it's obvious that wedge gas wells in the Utica generate some of the best economics of any onshore North American shale play at…

Thanks, Jim, and good afternoon to each of you. During the third quarter of 2013, Gulfport generated approximately $97.4 million of EBITDA, $51.6 million of operating cash flow and $40.5 million of net income. Our third quarter net income also includes a loss from hedge ineffectiveness of $6.7 million and a gain of $52.9 million in connection with our equity interest in Diamondback Energy. Adjusted net comparable to analyst estimates, a non-GAAP measure, was $11.1 million or $0.14 per diluted share. During the third quarter, production totaled 1,193,808 barrels of oil equivalent or 12,976 BOEs per day, which was up 45% on a unit basis, quarter-over-quarter, compared to the second quarter of 2013. Allocated by field, third quarter production breaks out to be 7,199 BOEs per day from Utica; 3,817 BOEs per day from West Cote; 1,821 BOEs per day from Hackberry; and 139 BOEs per day from Niobrara overrides and other miscellaneous areas. Our production mix for the third quarter was 58% oil and natural gas liquids and 42% natural gas. Subsequent to the third quarter, October production averaged approximately 15,543 BOEs per day. Moving along to the income statement, excluding the loss from hedge ineffectiveness, revenues for oil, natural gas and natural gas liquids in the third quarter totaled $75.5 million. Average realized prices for the quarter, excluding the loss from hedge ineffectiveness, were $108.88 per barrel of oil, $3.51 per MCF of natural gas and $1.14 per barrel of natural gas liquids. Our Bennett price for the third quarter was $66.86 per barrel of oil equivalent. Lease operating expenses during the third quarter was $7.3 million or $6.11 per BOE, down 40% on a unit basis from the third quarter of 2012. General and administrative expense for the third quarter was $5.3 million or 4.41 per BOE,…

[Operator Instructions] Our first question comes from the line of Neal Dingmann of SunTrust.

Say, Jim, I was wondering, what can you tell us -- maybe more color around the Irons, as far as how much you can say around like choke size or the pressure that is associated with it or such as the shut-in tubing pressure, those things that you could color around that well.

Neal, It is really a strong well. We're are really pleased with it. We started off with about 6,900 pounds shut-in pressure on it. The last 24 hours that we were looking at it, we were throwing well over -- we're over 30 million a day, we're going about 3,200-psi. We probably will produce it long term, someplace from 15 million to 20 million a day. We think we'll be up in the 5,000 pound flowing pressure in that, and that's kind of the basics on it. Looks really strong particularly considering that it's not that long a lateral.

Got it. And then just one, my one follow-up. Just wondering on the type curves on this new slides that are out. Notice on there now, you've got a couple of -- just in detail, where you talked about sort of normalized trade, lateral length at 8,000. I'm wondering, around that, Jim, is that kind of now what your typical lateral is and how does that impact how this would trend on the line a little bit?

Well, that -- gosh, we've even got some laterals planned that are over 10,000 feet. But it depends on where you're drilling and how the leasehold comes together. The point is that you've got to pick a length. We started out on the Wagner with an 8,000-foot lateral with Von Gonten, so we just decided to go ahead and use that. You really do have to normalize them, we are seeing that there's a direct proportion between the length of the well and what it's going to produce, whether it's a gas well or whether it's a condensate well. So various people may pick other distances, that's what we chose.

Our next question comes from Tim Rezvan of Stern Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: A couple of questions on the dry gas window. Obviously, focus has turned there, with the strong dwell result, and I guess 2 rigs you're going to be running. Are those rigs operating there now? And, I guess, my follow-up is on -- what gives you comfort that you're going to avoid the midstream delays that you had last year?

Well, you just have to pick and choose early. Like this particular location we chose because we had a Dominion location -- or pipeline nearby. So we're going to Dominion instead of MarkWest on this one. So we kind of followed the pipelines early on. Also, as we start drilling further to the east, MarkWest starting out down South and down there, we've got Texas Eastern transmission and other pipelines. And so we're kind of starting on the South end and moving north. That allows them to bring their infrastructure along with our drilling schedule for 2014. So you just have to work closely with what you got to work with. But there are existing pipelines in place that helps us get started there.

And, Tim, just to add, we are working closely with MarkWest to ensure coordinated approach with our joint activities and pipeline availability and as Jim mentioned, we do overlap major pipelines, the Rockies Express and Texas Eastern. The permit right aways and long lead materials needed for the construction are already in place or in process. So we feel like we're well ahead of the curve at this point. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay, thanks. And then a quick follow-up on 2014 guidance. What kind of risking did you put in there? Do you think that gives you confidence that you can either meet or exceed those numbers?

Yes, that's a good question. We certainly did risk it quite a bit as we are looking at it, Tim. We've got people, infrastructure takeaway and services. So 2014 is certainly a different year than 2013. We're further ahead on the learning curve. We're in a better position on infrastructure and continue to secure firm takeaway and work with MarkWest. But we have put quite a bit of different risking factors into our model when we were looking at providing those estimates this year. So we hope and expect that we'll do a much better job this year of meeting those expectations.

One thing that when you go into a new play, one of the big risk when you first get in there is, is it going to produce? And that's one of the things that's been really different about this play. The first well we had, the Wagner, when we saw the sudden pressures up around 5,300 pounds on that, we had a 12.5- to 13-pound mud weight equivalent. Even over on the West side, we've got good pressures there. We've got really nice pressures with 6,900 pounds at the surface. So that is one thing that's different about it. I think we're finding that virtually all the parts of our acreage are good, and it's a question -- last year we had a lot of infrastructure questions, but those are getting resolved this year. So the infrastructure is much less of a risk than it was last year. We and MarkWest have both learned a lot of things, and so things are coming together well. So we're looking forward to 2014.

Our next question comes from the line of Joseph Stewart of Goldman Sachs.

Looking at your 2014 guidance, I know that you expect to drill 64 to 71 net wells. But how many Utica wells are you assuming that you tie into sales on that forecast?

Well, that's a good question. I would say, off the top of my head, that we're looking at probably 50, 55 wells.

Yes, usually what happens, if you got 7 rigs running, and of course you're on pads or drilling maybe 3 at a time on the pad, more or less, it works out that whatever you drill in that last 3 months are probably not going to get on. That's about 21 wells. So those last 21 of the year, on average, won't be on. That ties with what Mike had to say.

It's going to depend, of course, where we would end up with the resting period ideas. So that will be a little bit influx this year. But we're certainly getting closer to having those answers.

And Mike, what about the wells that were -- that are kind of waiting to be tied in from '13. I was expecting to be able to tie more of those in '14 as well.

Right, if you're talking about the wells that will carry over from December 2013 into January 2014, it does appear we're on target for those wells. If that's your question.

Yes. So, I guess, like how many total net wells would you expect to tie in, that would impact '14 production?

Now that's 10 gross wells and the net is maybe 75%.

Our next question comes from the line of Jason Wangler of Wunderlich Securities.

Just [indiscernible] it's kind of been pretty good on the Utica, so I think I'm pretty good there. Just curious with the oil sands, just the kind of continued kind of delays. What you're seeing there, and then maybe if there's any other color about around the filing of the other application.

Yes, I think I said '14. That's going to be filed in '13 at the end of this year, for the next application. But with regard to the plant that's being built now, they actually have steam going into the ground by the end of this month. And sometime, 3 months or so later, we should start getting the first oil out. So, as far as when we'll do something with it, with regard to the capital event and so forth, I think it's nice to have the production coming on. As we get more production, we're going to start derisking the play. When we do something, depends on what the capital markets are doing and so forth, but we're optimistic about the way things are going up there. They pretty well got things behind them and moving to getting that steam going on the ground with first oil coming out.

Our next question comes from line of Biju Perincheril of Jefferies.

So looking at your CapEx for next year, looks like there is some cost savings that's factored in. Can you talk a little bit about where costs are currently? I think you talked about $9.5 million. And what are some of the drivers, maybe, to bring that down?

Sure, Biju. Some of the things -- we've discovered that there is a large part of our acreage where we can leave out the intermediate string of 9 7/8 that we were setting about 7,000-plus feet deep. When we can leave that out, we can set that 9 5/8 string back at about 2,000 feet. So that saves a lot of drilling time. That saves us $1 million per well. So that's a big driver. The other thing is that we've found that we make better wells without the cross-linked polymers in there. Von Gonten has seen evidence of the same things. So, by leaving that out, we were going from what might be a $125,000 cost to own a frac stage to $100,000. And we're sometimes drilling well over -- or having well over 30 stages of fracs. So you're starting multiplying 30 stages times $25,000 a stage, and it makes a big difference. So we're seeing some of those kind of things come along too. Also, with pad drilling, of course, as you drill more wells off the pad, you get to spread that location cost around. And, Mike, anything you want to add to that?

Yes. We are, Biju, getting more efficient at drilling. So I think the important thing is that, as we move forward, we keep cutting down the number of days it takes us to drill a frac complete well. So obviously, that's going to help us save money. We're assuming, for modeling purposes, $9 million to $9.5 million well cost next year. And keep in mind that we're talking about, generally, an average of a 75% working interest next year as we look to put together acreage with other operators and drill the longest laterals we possibly can.

And then my follow-up is -- I don't know if you mentioned the 2014 exit rate.

Yes, I don't think we're going to start talking about that yet, Biju, so I did not mention that.

Our next question comes from the line of Will Green of Stephen's.

I wonder if you guys could break down the 64 to 71 wells? Can you guys talk about how that looks per phase? Or is there an easy way to do that?

Yes, I think there is. I mean, I think we've talked about where our rigs are going to be allocated. So, 4 rigs will be in the wet gas window, 2 rigs over in the dry gas window, with 1 rig in the condensate window. So that makes it easy for you to do the math.

Got you. And then the $250 million in leasehold expense for next year. I'm not sure if I heard what you guys were planning there, but is that just grassroots kind of leasing efforts in the Utica? Is that what that's budgeted for?

Yes, there's a lot as we bring our units together. But on the last 2 quarters, we have been averaging about 10,000 acres per quarter. And so if you take that for the full year and start putting the type of prices we're seeing today, that pretty well gets you to the number we're talking about.

So, generally, we're talking about filling acreage, Will, but for competitive reasons, we can't be more specific than that at this time.

Our next question comes from the line of Ron Mills of Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: You guys mentioned the production mix. Mike, in your guidance, in terms of -- it sounds like 50% to 70% gas with the remainder being split evenly between the condensate and the NGLs. As you look through the full year and kind of the production build that goes through, is it something that continues to get more gassy as we look through the year or how should we think about the production mix transitioning through the years as you grow those production volumes?

Yes, Ron, I think that's exactly how you should probably look at it. You will see a continued, I think, build during the year, as to get to a more gassy nature at the end of the year.

Wells are really strong on the East side, it looks like. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: For sure. And then you mentioned the hedges that you've put in place on the gas side, the $4. Presumably, this is all to handle the Utica gas. Is this $4, is a Henry Hub, is it local index price? If it's Henry Hub, is there any way to protect bases or how do you think about it from a marketing of the gas standpoint? I understand the $4 price point, but how will that potentially translate into pricing given what we've seen recently in differentials widening in parts of the country?

Yes, it's certainly Henry Hub. We do have the option to lock in our bases as well. But it's as firm as taken. As we take firm, we will hedge bases. So you've seen us already begin to take some firm out. You'll see us begin to layer in bases as we go through the year.

Our next question comes from the line of Gordon Douthat of Wells Fargo.

A question on the joint operating agreement with Rice Energy. Just curious how this came to be and was wondering if any acreage or financial consideration change hands in this transaction.

No, not really. They had more acreage on the North half, we have more acreage on the South half. We could all go out there and work separately, but it's more efficient to get together and just -- we concentrate our efforts south, they do it North. So it just works out just fine like that. We have some other things that we're not talking about now, some other projects we've got. We're going to make it more efficient for us to frac our wells and so forth. And so there's a lot that we're doing out there. But this makes both companies more efficient when we got the development agreement going.

And keep in mind, while this is a formal agreement, we do have CAs with virtually every operator in the Utica. And so we are working with our peers to put together blocks of acreage, as I mentioned earlier, so that we can drill longer laterals. So, effectively, we're doing this with other operators. And you probably have heard other operator talk in the last couple of days about these same scenarios. So this is something you'll probably see more and more of out there.

Okay, makes sense. And last question, on ethane rejection. How do you view that in 2014 and do you foresee a point where you'll have to process some just to meet pipeline specs? What's your outlook there?

Well, ethane's certainly going to continue to be rejected in 2014, and there probably will be a point where you have to do some minimum ethane recovery.

Our next question comes from the line of Cameron Horwitz of U.S. Capital Advisors.

I was hoping you could update us on the Wagner well, just given it's your longest producing well in the play and just hoping you could tell us kind of where current production is on that well.

Right now, we've got it shut-in, what we've been producing some of the wells around. They've been frac-ing some of the wells around it and we're also going to be drilling a Wagner 4 well nearby. So we haven't got anything real new for you on that one.

Okay, and can you address just current realizations you all are seeing there? And I guess also maybe talk about the NGL side as well, the step-down quarter-over-quarter in realizations. I guess, that being a function of more of the cuts you're seeing out of the plant and softening in demand. Or how are you viewing that?

Yes, condensate basically is currently WTI less 10. And then NGLs for this quarter, we saw them at 45% of WTI.

Our next question comes from the line of Brian Velie of Capital One Securities.

A couple of quick questions. The Irons well, can you comment as to how much of that well costs and your expectations for prices there on the dry gas window side?

Well, we haven't got all our costs in on it yet, but those wells -- I think you probably saw some internal numbers of $10.5 billion for wells over on the East side. I think that this one is a little deeper than that, it's going to be more expensive. But it's too early to tell exactly what they're going to be. We had some other things. When you get over East like that and you got you're new well, you're doing pilot holes and coming back up and drilling your laterals. And so I think it's going to be on the high-side, obviously, the average for next year. But very economic with the kind of rates that we're getting out of them.

Sure, and then just one follow-up there on -- as we kind of model out the dry gas play, obviously, it's super early to be making too many assumptions, but for kind of a placeholder, would you use maybe what we have in the wet gas window for an EUR expectation? Something in that range?

Well it's really too early to tell about the East side. We're going to have to get some history before we know for sure, but we sure like the way it started off. But you just got to have some history before you can start talking to EURs.

Our next question comes from the line of Ipsit Mohanty of Canaccord.

Real quickly just see the production taxes kind of trending down and going forward in '14. Is that more of Utica? Is that more of Ohio state contribution or anything like that?

Yes, it's absolutely directly related to the increase in the Utica production in our volumes.

And my second question is just on leasing, but not exactly. I know you're differing from that. But with the joint development efforts, is it fair to say that you're probably going to quote up more of the dry gas window?

Well, it's certainly fair to say that we have an appetite for the dry gas window. The Irons well is a phenomenal well. And so we're really excited about the dry gas window. We think it's going to have really good returns. We have thought that for some time now. The Irons well is confirming that for us. So certainly we have a large appetite for...

Hell, that's why we put 2 rigs over there, next year, and of course depending on results, we'll see what happens. But we like what we see.

Our next question comes from the line of Leo Mariani from RBC.

Just wanted to follow up on a previous question regarding NGL pricing here. Mike, talked about 45% of WTI this quarter. I guess that price has sort of been degrading on you guys for several quarters here. Any insight into kind of why that's been dropping relative to WTI, is it all kind of local market conditions in the summer? And where do this expect that, going forward, as we head into 2014?

Yes, that's exactly right, Leo. It's seasonal, and as you know, for the first 2 quarters, we actually saw 55% to 60% of WTI for our pricing. So there is some seasonality. But we are getting a full cryo [ph] recovery, which allows us to get an deeper cut of the NGLs. And we do have a heavier NGL mix with the Marcellus. So I think you're going to see us continue to get good pricing. I think we saw some seasonality this quarter.

Okay, thanks. And I think in terms of the Irons well can you guys give us what the choke size was on the 30 million a day initial production rate? And it sounds like you're choking it back and talking about pretty significant, 15 to 20? Can you give us the choke size to get to the 15 and 20?

Leo, choke size -- I mean it's kind of immaterial in some ways. We really kind of look at the pressures more than we look at the choke size, but we thought that 3,200 pounds of that kind of rate was pretty darn strong pressure. But we'll choke it back to that 5,000 plus kind of range and manage the pressure out there. And based on what we saw as we put the well on and bring it down to the sales line. It looks like we should to 15 million to 20 million a day at those kind of pressures. The reason I don't really get too concentrated on choke size is because you're bringing back little sand that eats up the chokes. So really pressures is what we look for and the rates that go with the pressures.

And we were looking at 5,000-psi. So that's really what's relevant.

Next question comes from the line of Amir Arif of Stifel. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just a question on the gas weighting of 50% to 70% for next year. Is that simply a function of the higher IP gas wells coming in or are you seeing changes in your GUR for some of your wet gas and condensate wells?

No, really, the GURs that we're seeing, or the NGL recovery that goes with the million cubic feet of gas, those numbers are staying pretty constant. Of course, when you start off on a new well, you're going to have a lot more condensate coming with it. And that will, over time, drop off. But the main thing is that we're just moving over into the dryer gases. And so we're getting more MCFs coming in there. And some of the far ones like the Irons well won't really have any NGLs or condensate with them. BTU is up around 1,070 or so, but it's not going to make those. So it's going to lower your percentages. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay, and just for the follow-up question. On your gas rigs, can you just [indiscernible] more on the Belmont County or are you going to be moving further south into Monroe County?

No, we've got acreage down in Monroe County and even some south of that. But we like where we are. We've been real pleased to see the kind of wells that we've made -- and any place we go that we plan on drilling well we have expectations that it's going to be a good well. We're not worried about drilling 4 wells. And so we think we're pretty well derisked our acreage, and we like what we got.

Our next question comes from the line of Marshall Carver [ph] of Hiking Energy [ph].

I had a question on the number of net wells to go online this year. I wanted to make sure the -- so that's 50 to 55 total net wells should go to sales next year, including the wells being drilled next year and the wells from this year, that could put online next year. So 50 to 55 net wells for the year.

Yes, I don't want to get into a specific discussion. We can certainly take this off-line after the call, and we can have a specific discussion about net versus gross.

Our next question comes from the line of David Beard of Iberia.

Two questions. First, just given your increase in CapEx, could you prioritize how you would look to close the gap between internally generated cash flow and CapEx?

Sure, we have cash on hand, obviously. We will have proceeds from the sale of the Diamondback Energy stock we announced today. And then we have borrowings under our revolving credit facility available to us about $150 million. And certainly, we always have the option of debt and equity securities as well.

Okay, and then the follow-up just to shift to your 2 type curves. The type curves have been tried tracking the lower end of your band. Can we really read or should we read anything into where they're tracking this early on in the type curve development?

Well it is real early and it's not many wells out there. But I think if you look back at the previous type curves, you'll see their tracking up even higher on the bands. And so it seems like we're getting more history and the type curves strengthening all the time. The actual wells as compared to the type curves.

We have a follow-up question from the line of Biju Perincheril of Jefferies.

Yes, I know you mentioned, on the Wagner well, that's currently shut-in, but can you comment on where it was producing? Is it still around 10 million a day that the type curve would suggest?

Biju, we've kind of moved on to not going over the individual wells. It's a good well. It's doing fine, but probably gave more information than we should have on it because we kind of moved into [indiscernible] individual wells, we'd hardly get called on. so we kind of moved on to not discussing the individual wells. Mike?

No, I think that's right. The what that we have production from wells in the type curve we think the more relevant data point is a composite average of the wells that we have producing under scenario. So we think that's meaningful at this point, and we think we have enough wells now producing that we are trying to move away from talking about individual specific wells.

Okay, that's fair. So the fact that the type curves still showing about 18 months or so flat production, and that was based on, I think -- it was worse [indiscernible]. I guess, you have you're gaining confidence in that number was history, is that a fair statement?

That's right, and like we say, if you look at the wells as compared to type curve for the last time we put it out. We're stronger all the time with production. So we like what we're seeing.

Okay, and just to confirm, the production guidance and the mix that you gave for '14, does that include any ethane or is that assuming...

No, that assumes ethane rejection.

And our final question is a follow-up question from the line of Tim Rezvan of Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Just wanted to, I guess, for those things out, what's your latest spot on resting wells, especially as you kind of look towards the Eastern part of the play?

That's a good question. We're still trying to figure it out. We have seen with slick water fracs, we can bring them back right away, and we can make a good well with minimal resting. However, you make more water then and bring back more sand. So we're still divided within our company. We still go back and forth as to whether or not we need it. But certainly, I would say it's certainly not the 2 months that we thought when we started maybe. Maybe it's no rest at all, that's why we're doing the Darlot. We're doing the science there and we're going to have parts of those wells that are 300 feet apart and we're going to look for communication between them, and we're going to do the microseismic and there's so many things that go into it. But we have done a lot of science. And we've made some remarkable wells today. But I think just tell you Tim, we still don't have all the answers. I wish I had a final answer for you, but I can tell you that I think Mike, you built 30 days into your model, the conservatism end of that?

When we finish tracking a well, it takes us approximately 30 days to drop plugs and get everything plumbed up and turn production on. So effectively, wells are being rested 30 days, yes.

And we currently have no further questions in the queue. I would like to turn the program back to management for closing remarks.

Thank you, Nova. I believe this concludes this afternoon's call. A replay of the call will be available for temporarily through the company's website. It can be accessed at GulfportEnergy.com. Thank you for your time and interest in Gulfport Energy this afternoon. This concludes our call.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program ,and you may all disconnect. Everyone have a great day.