Good day, ladies and gentlemen, and welcome to Gulfport Energy Corp. First Quarter 2013 Earnings Call. [Operator Instructions] And as a reminder, this conference is being recorded. Now I'll turn the conference over to your host, Paul Heerwagen, Director of Investor Relations. Please begin.

Thank you, operator, and good morning. Welcome to Gulfport Energy's First Quarter 2013 Earnings Conference Call. I'm Paul Heerwagen. And with me today are Jim Palm, Chief Executive Officer; and Mike Moore, Chief Financial Officer. 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 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, appropriate reconciliations to the GAAP measures we posted to our website. An updated Gulfport presentation was posted this morning to our website in conjunction with yesterday's earnings announcement. Please review at your leisure. At this time, I'd like to turn the call over to Jim Palm.

Thanks, Paul, and good morning to each of you. During the first quarter of 2013, Gulfport generated approximately $35.7 million of operating cash flow, $99 million of EBITDA and $44.6 million of net income on production totaling 575,000 barrels of oil equivalent. Average daily production of 6,395 barrels of oil equivalent was below our expectations for the first quarter due largely to delays in the Utica midstream complex. The good news is that we hooked up 6 more wells in April. And the early results show them to be producing in accordance with our expectations, which were high expectations based upon our early test results. Although production has been challenged by our continuing hookup delays to date, our drilling for the rest of the year will stay close to the pipelines now in place and coming soon. Based on early production results from the 6 new wells we hooked up, we feel now is the time to accelerate our drilling. Our fourth horizontal rig is currently spudding and our fifth horizontal rig should spud within 10 days. We had originally planned to have 7 horizontal rigs running by the end of the fourth quarter. By now with our accelerated program, we're shooting for the end of the second quarter. Of course, when you put more rigs to work early, it means we will drill more wells. Rather than 50 wells this year, we now project that we will drill 55 to 60 gross wells. This results in an increase in CapEx that, as Mike Moore will cover later, we are more than capable of financing the increase through cash flow, cash on hand and availability under our revolver. In spite of these challenges to production, the last few months and the last few weeks, for that matter, have been noteworthy…

500,000.

I'm sorry, 500,000 pounds of 20-40 sand per stage and the other well was frac-ed with 500,000 pounds of 30-50 sand per stage. Once the wells begin flowing into the sales pipeline, which is expected in mid-June, we will be able to evaluate the results and see if difference in sand size makes an impact. The key takeaway, which I want to convey here, is that we now have 9 wells flowing to sales at a combined gross rate of over 10,000 barrels of oil equivalent per day. And we expect to have 4 more wells online by the end of June. Now turning to operations in greater detail. Our producing well count is now approximately 4 months behind where we thought it would be when we guided for 2013 last November. And production did not meet our expectations in the first quarter due primarily to the delays in the Utica midstream complex. However, in the Utica, we've made a quantum leap versus 12 months ago. A year ago, when we spoke with you, we had 2 rigs running. We'd only spud 3 wells and had just signed a gathering agreement with MarkWest. Today, we've spud 27 wells. We have effectively delineated over 85% of our acreage and we're producing over 50 million cubic feet per day of gas into MarkWest's wet gas gathering system. As I mentioned, we plan to move to 7 rigs as quickly as possible to take advantage of our recently completed midstream type play. Meanwhile, we will continue to refine our drilling and completion techniques to further improve results and gain efficiencies. On the midstream front, our partnership with MarkWest continues to progress. As we mentioned in the past, we have planned our 2013 Utica drilling program less takeaway availability, which we expect to provide…

Thanks, Jim, and thank you all for joining us on our call. During the first quarter of 2013, Gulfport generated approximately $99 million of EBITDA, $35.7 million of operating cash flow and $44.6 million of GAAP net income. In the first quarter of 2013, production totaled 575,543 barrels of oil equivalent or 6,395 BOEs per day. Allocated by field, first quarter production breaks out to be: 2,983 BOEs per day from West Cote; 2,480 BOEs per day from Hackberry; 801 BOEs per day from Utica; and 127 BOEs per day from the Niobrara, overrides and other miscellaneous asset areas. Our production mix for the first quarter was 91% oil and natural gas liquids and 9% natural gas. Subsequent to the first quarter end, production during April averaged approximately 6,429 BOEs per day and May's daily production has been tracking in the 8,000 BOE per day range. Moving along to the income statement. Revenues for oil, natural gas and natural gas liquids in the first quarter were $54.9 million. Average realized prices for the quarter were $102.68 per barrel of oil, $4.59 per Mcf of natural gas and $61.02 [ph] per barrel of natural gas liquids. Our blended realized price for the first quarter was $95.34 per barrel of oil equivalent. Lease operating expense for the first quarter was $5.2 million or $8.99 per BOE. G&A was $4.4 million or $7.67 per BOE for the quarter as depreciation, depletion and amortization expenses during the first quarter totaled $22.6 million or $39.24 per BOE. In terms of capital expenditures, during the first quarter on an accrual basis, we invested a total of $40 million, which excludes $7.5 million of Grizzly investment. Moving on to the balance sheet. In connection with Gulfport's predetermination under its revolving credit facility, Gulfport's lead lender has provided…

Operator, can you please turn the call over to Q&A?

[Operator Instructions] We have a question from Neal Dingmann of SunTrust.

Jim, can you give more further color on just kind of pressure drawdowns? You touched upon this a little bit. But I guess, what I'm trying to get to understand is sort of well-by-well on what you have so far based on the choke side and such, an understanding of kind of the pressure drawdowns you're seeing, if any, on the wells now that have been online now for a few months.

Well, really, Neal, we don't have too many wells that have been on for a few months. As you know, the Wagner has been on now for about 9 months. As we mentioned before, it was flowing at 2,400 psi when it was producing 10 million a day. So that's pretty stout after that much time. And of course, that's in line with what we've got on our type curve. We think it's going to be quite some time before it gets down to line pressure and goes into a declining rate. When we look again on the gassier side and we -- well, let's go next to the Boy Scouts. I mean, those wells, as we said earlier, they've had some challenges because we don't have the downhole configuration optimized on them and we've been drilling with a drilling rig over them, so we haven't had a chance to change it. But we're soon going to go in and put -- we're going to put some gas lift valves in on the Boy Scout wells. And they are still managed to do quite well. Actually, Von Gonten is our expert on that. When his computer ran simulations, they originally expected the first Boy Scout well to load up and die within 2 months. And here we are 5 going on 6 months into production, and we haven't needed any artificial lift. And it's still capable of making in the 500 barrel per day range, 400 to 500 barrels per day. So that's really done well. We think it'll be better, though, when we -- now that we've finished drilling the third and fourth wells on the Boy Scout. We're getting ready to frac those and when we run their downhole configurations in. All the other wells, except for 2…

And I think an important comment here to keep in mind, Neal, is that both the Wagner well is performing in line with the type curve. So I think that's something that is really important for us all to focus on. The Boy Scout is actually has exceeded the type curve at this point. So for type curves that we put out at IPAA in February, we're very pleased with the way these wells are performing.

And then Mike, following on to that, as far as obviously with your confidence or the reiteration of the 2012 guidance out there, you're obviously assuming a pretty high or steep ramp in the second half this year. Is the confidence you have with that, I guess -- or what is the confidence you have, given the takeaways you've seen earlier? I mean, does that have to play into the way that you'd already tying the Stout wells already in the line, and that's what you'll be doing going forward? Or what gives you the high confidence that you can continue to hit that production number that you have out there?

First of all, and it's a great question, we're very pleased with the performance of these wells. Obviously, getting behind early in the year is always tough. And we did have some additional delays. And at IPAA, we said those delays behind us -- were behind us, and that's true in the sense that MarkWest had obtained all the right-of-ways, all the permits. Those were the obstacles really to constructing those trunk lines and gathering lines. Trunk lines are all in place. The gathering lines are lain there or hooked up. So we have an extremely high level of confidence, I would say, going forward. And you've got to keep in mind, we also adjusted our program this year to drill wells in the areas that we can hook up immediately. So we're not going to drill in outlying areas, where it's going to take months and months to lay gathering lines. In fact, MarkWest at this point is actually ahead of us. They have gathering lines, I think, on 6 or 7 areas that are within a mile of our existing pad. They're just waiting for us to tell them exactly where to put it. So they've actually gotten ahead at this point. So that gives us a lot of confidence going forward. And then of course, secondly, we are ramping up -- we are accelerating, not ramping up. I don't want to use that word. We're accelerating our -- bringing our rigs. And certainly, that is going to help ensure that we get there as well. So we feel like we're through the major hurdles. I know you've heard us say that before. But we think we're there now.

Okay. And 2 last ones, if I could. Just maybe for Jim, remind us on the microseismic work. What does that indicate? Or have you any idea so far on the potential for downspace? And I know you talked about the Darla pad down the line. Any ideas so far about early indication on what downspacing looks like?

Well, I think we're going to see a lot of downspacing. But of course, it varies from the east side, where it's gassier, to the west side, where it's oilier. But what our microseismic has shown us is that we are very effective at keeping our fracs within the Point Pleasant interval and we're bounded on the bottom by the Trenton Limestone. And then our Utica is relatively tight as compared to the Point Pleasant. It seems to be a frac barrier to the fracs going uphole. So we found instead of going at 95 barrels per minute, we need to be back around 70 barrels a minute. That's good news because it makes our fracs cheaper than pumping the high horsepower. But microseismic -- and we're getting ready to run some more. But the microseismic we've run so far says we're very effective at keeping our fracs in the right place on the Point Pleasant. So I think I can see us maybe even moving to shorter frac intervals and closer spacing on the wells as we go forward. We're definitely going to get as many wells drilled in there as we can and downspace as much as possible. There might be a little interference. You don't want a lot of interference, but I think if we don't have a little interference between wells, then we haven't effectively downspaced enough. We've just now gotten to the point where we've got enough wells on where we can really see what's appropriate. You have to produce the wells as well as look at that microseismic.

Okay. And then just lastly, we've heard some peers, it sounds like some successful wells in Central Belmont, and then another, I think, in sort of Central Northern Noble. I mean, what -- I guess, just looking at either of those, Jim, what does that tell you, like in Central Belmont, as far as extending the liquids window kind of east of Wagner? And so I guess, what I'm trying to get a sense of is when you and Mike now look at the play, how do you get a sense of sort of the liquids window all the way from over that Wagner well over to your kind of things on the Noble, Northern Guernsey border?

No, you're right, Neal. I'm sure you're thinking about the Hess well that's east of the Wagner. And it had some pretty high liquids recoveries, which to us is just encouragement. But we don't know enough about the specifics of it to start changing things. But I think it's more validating of what we thought originally is what we're seeing over there. It's validating what we thought we had before. We haven't seen any reason to change what we think about our window at this point.

The next question is from Jason Wangler of Wunderlich Securities.

I was just curious if I could quick on South Louisiana. It looks like at least at Hackberry, you're maybe running a little bit ahead of schedule. Do you see drilling more wells again this year down there versus the current guidance? Or will you be slowing that down as you kind of focus more on the Utica second half?

Well, we went into this year assuming the same level of activity in Hackberry. And assuming we have the same levels of success that we've had, we'll continue to drill that up down there. I think last year, we ended up at 24, 25 wells. I think it's likely that we'll end up in the same place. But again, since that is still a field that we just started drilling a few years ago, it still is success-based. So it's all dependent on success. But it's likely we would continue to have that same level of activity.

Yes, Mike's right. There's a lot of unknowns there because it is more exploratory. But to give you an idea, we just logged the well at intermediate casing point, and it has an enough pay in that well to make a nice completion in the Miocene. But we'll set an intermediate string there over that, and we'll go on down and we'll do exploratory work in the Camerina. If we don't make a well in the Camerina, we'll produce that Miocene behind pipe. And if we make a well in the Camerina, we'll probably more or less twin that first one. So there's a lot of moving parts there as we drill these new wells, but we still do like the area. It's a good area. It's a little more lumpy. We're more predictable in West Cote, but it's a great place to go.

Okay. And if I could just one in the Utica, and I apologize if you maybe said it. But there was a slight increase in the wells drilled. Does that going to change how many you think you'll have online this year? Or will those just kind of fall into the beginning of '14 as you get those drilled up and online?

No. It will change the number of wells that we have online by year end. And you know that certainly will improve our position going into 2014. So it's likely what you could see is coming out of the year with a bigger number going into '14. So it should really poise us to be in a good spot in 2014 going forward.

Our next question is from Biju Perincheril of Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: A couple of questions. On the Boy Scout wells that you had experimented with sort of different resting period on those 2 wells, does that account for the sort of the barriers we're seeing in the production between those 2 wells? Or are there other factors that you are changing in those 2 wells?

No. There are definitely differences between the wells. The second one did have a shorter lateral, although I didn't really expect that would make a lot of difference in the IP. It might make a difference in the EUR. But it has been a weaker well than the first Boy Scout well. And we only rested that well for about 1.5 month. As you know, we'd like to -- now that we have pipelines available to us, we want to test how short we can rest these wells, so we can get them online as quick as possible. That one actually was 52 days before it went into the sales line, so like I said, it was pretty close to 1.5 month. The original Boy Scout well was actually rested for about 3 months before it went in. So we haven't quite figured out the west side. I'm still thinking I feel comfortable with 2 months resting time on the west side. The 10 wells that we drilled that are on that side from last year probably helping me make my mind up about that. I'm not sure it can't be longer. But right now, I feel comfortable with 2 months and less. And over on the east side, based on tests on the Stutzman and tests in production on the Wagner and the Shugert wells, over there I feel like 2 weeks to 1 month is plenty to rest the wells on that side. So the west side, we're still trying to figure out a little bit more than the east side. The east side is going to be quick with not too much rest. They will be better after a month than they are after 2 weeks, though. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: And then given the shorter rest period for that second well, are you seeing similar sort of decline profile? Or does it have a shallower profile?

Biju, you're kind of cutting out, you're breaking up, can't understand you. I think what you're asking is how it's doing since it went on. I would say it didn't -- well, actually we had a few days, we had 4 days where it made 1,000 barrels a day. But it quickly, came down quickly. But once it came down, it has continued to be pretty flat. And it's been on since January. So it just -- it hasn't really had much decline. So it's still having a flat decline, it just didn't have as high an IP. And maybe that's what happens. Maybe one well is not enough to tell you what you need to do to rest the wells. It does make me cautious about a short rest period. But we need to try a few more before we figure out what's appropriate. But it has stayed [indiscernible], even though it -- as far as decline goes, even though it wasn't as high an IP to start with. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: And I'm sorry, Jim, when you're talking about that flat decline, were you talking specifically about the second Boy Scout well or are you talking about...

The second, the second Boy Scout well. It came off of, like I say, when we first started out with it, we had 3 or 4 days when we did make 1,000 barrels a day. But now it's down -- it's more like we mentioned on the numbers that we've put out 205 barrels of oil, but it has lots of 250 barrels -- that day it was 205. It has a lot of 250s, and those kind of numbers, more the 250 to 300. So it's hanging in there flat and strong. It just didn't have 1,000 barrels the first month like the original Boy Scout well did. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Great. That's helpful. And then one last question for me. So as you're flowing these wells now to sales, are you running into any sort of pressure-related issues, line pressures or the rate -- or the constrains you are running these wells at restricted rates for sort of reservoir pressure management?

No. Really our rates that -- our pressures that we've got are pressure managed, that's why we don't open the chokes real quick, so we do manage the pressures on them. But the wells are way above the line pressures. We're not having any restricted takes. These wells haven't gotten down to line pressure yet.

Our next question is from Tim Rezvan of Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: I had a quick question on infrastructure. It sounds like you're seeing the light at the end of the tunnel with the build-out needed for 2013. Can you talk about future milestones that you need to kind of feel comfortable about 2014?

Well, as far as the infrastructure goes, by June, we should have -- we should -- except for one well, everything should be producing that we drilled last year, and we're going to keep everything else this year in that same window. So I don't think we're going to have an infrastructure problem. One thing I have to complement MarkWest about, though I read through some of those numbers about 600 million and 800 million a day worth the plant processing capability. They are really ahead on that. And I know we've been disappointed by these month of delays. We feel like at the end of the first quarter, we were 4 months behind where we thought we'd be in November, but -- because we only had 3 wells producing. But in April, they started making up for it. And if you look back at, say, the Marcellus and how they got started, you didn't see the plant capacity in there even when the pipelines came in. So if you look up North, there's been about 300 wells drilled and there's still 200 of them waiting to go online. So really I have to -- for a brand-new play, in spite of the frustrations that are a monthly kind of thing that we've been dealing with, we can actually see, like McCourts [ph]. We just finished 2 McCourt [ph] wells. There are 2 of those that were scheduled to come on June 1, and we talk to the guys every day. Well, in spite of that, within the last 2 weeks, they moved it to June 15. But I can tell you, we can see the pipe, but at the edge of the location now, they're still working on the pipe back where it connects in through the trunk line. But these trunk lines that go north-south, like our north-south line that takes Wagner, takes the 2 Shugerts and will soon take the Stutzman, that has over 300 million a day of carrying capacity back to the plant at Cadiz. And we have 2 lines that go west. One goes to the Boy Scout in the north side and other one goes to the Groh wells kind of south of that. And each of those main lines can carry over 300 million a day. And so we don't see that we're going to have -- as long as we stay in the existing playground and we will ease them out over time, maybe like fourth quarter, we'll start getting outside of that playground. But as long as we stay in there, we don't really see delays anytime this year in getting our hookups.

And they have -- just keep in mind that by year end 2013, they're going to have 600 million a day of capacity and then bring on another 400 million a day in 2014. It's not the plants, but their -- the plants build their equipment so the delays that we've experienced really have been about just gathering the permits and the right-of-ways for the trunk lines and gathering lines, and those are behind us now. So that's another reason we're feeling very encouraged by where we are today. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay, okay. So I guess what I'm trying to get at is if you look out to 2014, I don't know if you've really kind of mapped out your program. You've talked about 70 wells, but just kind of curious on the likelihood that we could see this issue arise again in 2014.

Well, I don't think we're going to see it. For instance, it's not related to our Cadiz system so much, but up in northeastern Harrison County, they have some pipelines in the works up there. And we have acreage up in the northeastern Harrison County, but we don't have any wells scheduled until very late this year and the early part of next year up there. So obviously, before we start drilling a well in November, we're going to make sure that they've been on schedule and they're going to have that pipeline ready to go when we're ready to have sales in February. So there's other places. And we do have acreage that we're not drilling today, we're not building locations on today because we don't think they'll have a pipeline in there. But we do know, and we have plenty of locations within this footprint they're establishing now. So if we get outside of their footprint too fast, it's our fault. But when we move out to new areas as we go west to the Groh, for instance, we'll move a little bit at a time, probably just drill one well out there and test it and make sure that they're going to have the pipeline before we start drilling the well. So yes, you've got to watch where they are, you've got to plan within that. But we're sticking with the footprint that's associated with the wells we drilled last year for this year. And by next year, anything we drill outside of that footprint, we'll make sure that the process that is coming to us is well under way before we go spud any rigs.

And again, MarkWest is staying ahead of us on processing. So again, the plays were tight. But we have looked out to the future to make sure that there's plenty of capacity. And so we've mapped everything out. And at this point, we feel very, very good about having plenty of processing for our activities certainly this year and next year as well. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. Appreciate that color. Related on the processing side, these production rates you provided in the release, can you kind of broadly talk about what NGL uplift you're getting? Those are going into the refridge plant?

We can do that. Let's see. The Wagner, of course, is our long-term history. And when they put in the refridge plant, Tim, they were guiding us to -- now we're not taking out the ethanes. We're leaving those in the gas stream and the residue gas, so we're looking at propanes, butanes, et cetera. And on the Wagner well, we -- they said, you'll make 24 barrels per million cubic feet of NGLs. So when they started it, we've got 3 months' worth of processing statement so far. And in January, we got 8 barrels. In February, we got 16 barrels. And in March, we got 22 barrels. So they're just about -- I would imagine in April, they'll be to the 24 that we expect to have with refrigeration. Now the cryo is coming in and when the cryo plant comes in, it's supposed to be twice refrigeration. So we should soon be at 48. They may have a little ramp-up there, we'll see. But it's pretty impressive. So if you think of a Wagner making 10 million a day, you're talking 240 barrels of NGLs. And I might remind you, too, that we got $60 a barrel. How do you do that when the rest of world is talked about 30% of WTI. Well, if you go to the Permian, you take out -- they have to take out both the ethane and the propanes and butanes and so forth, so they have Y grade, they call it. And that's what you get 30% of WTI on because it includes all those ethanes that have very low value. Up in the -- we are in the Utica, we leave the ethanes in. We're fortunate there's enough transmission lines and things that they can leave the ethane in there. We get a little value for the BTUs of the ethanes. But the main thing is that all that's left in our NGLs is the high-value deals. And so now we get about 2/3 of WTI for our propanes and butanes because we're not diluting their value with the nearly valueless ethane. So it makes our products really -- so when you talk about -- we could more than double those products if we had the ethane markets, which we see coming in '14 and '15, and we could more than double the liquids recovery, the NGLs. But the ones we've got today are a nice high-value NGL. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. And would you say that, that uplift is generally applicable across the other wells?

Well, actually when you get to the west side, we'd expect to get a little bit more NGLs, the propanes, butanes, those type NGLs on the oilier side. So every place is going to -- this could be up 2x as much by the time we get to a Boy Scout type well. And we're just now getting our plant statements in and seeing how that's coming. But there's more on the -- we'll get more uplift on the west side.

Our next question is from Don Crist with Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: This is Ron. Just on the restricted chokes you're running these wells on, how do the level of -- or what are the respective choke sizes compare with what you expected to bring these wells on in your guidance, either for you, Jim or Mike. I know that the rates are more restricted in pressure management, but you brought up the Boy Scout well that's producing above its type curve. How are you feeling about -- on the restricted chokes and how that compares with what you thought?

Well, really, to me, the choke size is a product of what you want to produce as far as the pressure goes. So we really look more at the pressures and then we just put whatever chokes it takes to keep the pressures where we want it to go. Now when you look at something like the Boy Scout, because it's so oily, there's -- really one of our biggest chokes at the Boy Scout has been the production equipment. That was the first oil well that we equipped. And we found we didn't have big enough production equipment. Now this didn't make any difference the first month when we were making 1,000 barrels a day. It was kind of like you'd take your water faucet in your kitchen and turn it on, and here came the oil. So it was real constant. And the production -- the equipment that we had worked fine. But as the well started to weaken a little bit, then it would slow down and then it would release a big hit of oil. And it was more than our production equipment could stand when all that liquid came at one time. So we've actually had to choke back that first Boy Scout well more than we'd like to. And we are soon going to be changing out -- we've upgraded a little bit, but we're still making changes in the surface equipment so we can produce it more. And like I said, when we get the artificial lift on there and we can gas lift it, well, that should smooth out those surges and help us open the choke up some more. So we've -- we actually sometimes had to choke the wells back more than we would like to just for those kind…

Well, that's always something that is a major concern of ours. But the guys have been working real hard. Before the year started, our land department committed to having 50 locations ready to go this year, whether we used all 50 of them or not, to drill exploratory type things. And I think we've now moved to -- back into the area that we've got. But one thing about it is by -- like the 2 McCourt [ph] wells that we just drilled, I'm ready to go back and drill some more McCourt [ph] wells. So we have the ability to have 2 [ph] locations. We actually have locations sitting there already that we haven't moved rigs on to, and now they're bringing the pipelines into them. And some of those were over -- like around the McCourt [ph] area and around the Shugerts, where 6 months ago, we thought, well, let's get them in our hip pocket so we got someplace to go if we need to, but let's concentrate on the west side because it's oilier over there. But now that the gas price has gone up some -- one location has been sitting there and now we're ready to put a rig on it. So things change with the prices and so forth, but the bottom line is our land guys are doing a real good job. And we talked about downspacing. We'd like to go back and drill more wells. We've only drilled -- we've drilled now 2 wells north on the Boy Scout and 2 wells south. We need to get back there and drill some more wells. So we're going back to the Wagner. We just moved a rig on -- it should be spudding today on the Wagner, where we had 1 well and we're going to drill 2 more off of that pad. So we've got the Darla north of it, we're going to still drill 3 wells up there. We've got a lot of stuff in motion. And so there's always challenges, but we're not going to -- it's not going to hold us up.

So Ron, just a little additional comments. I think we've said on prior calls our land guys are working lots of locations at the same time. I think last time I looked, it was -- they were working on 100 locations. So the permitting part, mechanically, is fairly easy. You can actually walk a permit through the state if you need a permit. Rigs are available. So I guess to answer your question the short way, we don't really see any obstacles to ramping up these activities at this point in time.

Yes, and one other reason, too, we keep running into the same players up there. We've got Chesapeake and we've got Hess and some of the local guys up there. And everybody is working really hard together. We've participated in their wells. They've participated in ours. We've got some Chesapeake wells where we've got 21% in 3 Chesapeake wells that we've drilled. And so there's been nothing posed to us that we've turned down, and there's been nothing proposed by other -- that we posed to other operators that they've turned down. Now occasionally, we'll propose a well and they might say, well, why don't we swap you this acreage or let's swap acreage on a couple of deals, and we've done that. But we haven't ever had any operator seek to slow us down. And so everybody's working real hard together. They've got things they want to get drilled, we got things we want to get drilled, and we're working to facilitate each other, not fighting each other. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then last thing, maybe for you, Mike. On the production guidance you gave second quarter, we have your full year. Given the small number of wells depending on which wells come on at what time, the various product mixes can be quite different. How should we think about -- or do you think about in the future, we're starting to talk about production guidance and outlook and expectations in a 2 and 3 stream model or format instead of just BOE? And then the follow-on is from an ethane standpoint, have you all -- do you all have agreements in place at some point in 2014, '15 to start selling those, or is that something that's still in the works?

So from the production mix question. At this point, although it's still early, we're still modeling and suggesting to the market that the Utica production mix this year is 1/3, 1/3 and 1/3, Ron. I think as we go through the year and we get more wells producing, we're going to be able to tweak that to be a little more finite. But I think that's a good way to think about it still at this point in the year. And that's certainly what I'm doing. As far as in ethane?

Well, with regard to ethane, everybody wonders, is ATEX going to have enough capacity for our volumes? And they are. And we're keeping our optionality. Right now, based on what we see, the ATEX capacity for instance is only about 53% committed. So we think we're best served at this point just to keep things flexible and see what develops. We do know there's going to be a lot of processing come on, fractionation '14. And like I mentioned on the call, that was a brief little comment on the call, but we're already getting -- I mean, Gulfport individually is getting calls from overseas about exporting ethane in 2015. So there is a freight train coming. But right now, we don't see the capacity constraints that make us -- we don't feel the need now to go ahead and make commitments before we really know what's going to develop. We'll watch it and if it gets -- if constraints change, well, then, we'll make some other decisions.

Our next question is from Leo Mariani of RBC.

Just looking for some color around your May production. I know it's early, but I think, Mike, you'd said, around 8,000 barrels a day in May. Just trying to get a sense of what the Utica production number would be out of that 8,000?

The Utica right now for May is averaging about 3,000 a day.

Okay, that's helpful. And I mean, just kind of eyeballing what you had in your press release in terms of the wells you had laid out with the 24-hour gross rates. I guess, I calculated that, if I add it all up, at about 4,800 BOE per day on a net basis. So I don't know, maybe I didn't do it right. I'm assuming 50% interest and 20% royalty on those wells you guys showed. So just trying to reconcile the 4,800 with the 3,000.

No, you're doing good, Leo. Of course, all -- that's everything is producing every day.

Right, it's not shut-ins.

Sometimes you've got some wells -- you have to shut the well down for a few days moving a rig, that type of thing. But we've taken that into account. And that's why Mike's number -- and Mike may have some other things. But that's the type of thing that keeps you from being at the max rate all the time.

Right. There are always, Leo, when you're producing these wells, you can always have temporary shut-ins for various reasons.

Yes. When you bring the new plant on, they'll have lines [indiscernible] and things like that so.

And then keep in mind that we've only had 7 days in May so far, so.

Yes, no, for sure. So obviously, you guys are anticipating that, and you start getting some increases here for sure as things get straightened out and you've got 4 more wells coming on in June. So would you expect that 3,000 right now in the Utica just to continue to ramp for the rest of the quarter? I mean, obviously, you guys are also talking about how the wells are still restricted chokes. As you open those up, certainly, we would hope for higher production rates, is that fair?

Sure, sure. And obviously, we've given you guidance for the full quarter earlier in my comments. So you're going to expect to see a pretty big jump when you bring those wells, those 4 additional wells on in June. And then also we've got a couple of wells shut-in temporarily right now for rig moves. Those will come back on in a few days. So there's variance from day to day, but we're just trying to give you all the information -- most current information that we have right now. But, yes, we're certainly expecting that to jump up dramatically.

Yes, and we plan for the stuff. We actually, every -- at the start of every month, as far as gas sales, we put together a schedule that takes every well and on the days that we're going to be moving off of a well, and we have to shut in because of a rig move, for instance, we put that on a 30-day schedule. So we have each individual well in there. And they don't produce the same from day to day. And then we take the combined total, and that's what we nominate for our gas sales. So we have to look at it real close. And we monitor, like I say, every well on a daily basis, a month ahead of time.

All right, that's helpful for sure. And I guess, you guys are obviously accelerating here in 2013 by adding some wells to the schedule. Should we also infer that you guys might accelerate in 2014? I know you talked about 70 wells, but it sounds like, I mean, you're not too far off there in 2013. So should we expect more than 70 next year?

I think, Leo, it's a good question. We don't want to get too far ahead of ourselves here. And remember, we do like to live within our liquidity as well. So it'll all be dependent on where we are at the end of the year, rig availability. We have to take a lot of things in consideration, service costs.

And that's -- really what it does, Leo, is give us optionality. We've got -- if we got 7 rigs running and we're not changing -- we haven't even given guidance for '14. But if you have 7 rigs running, and if they each drill a well per month, you're going to drill more than 70 wells. And like Mike said, if these wells continue to produce the way we see them and if we have the same liquidity situation we have now, our -- if we have the opportunity though, you can be assured that we're going to drill as many wells as quick as we can, get these reserves out of the ground for the whole play as quick as we can, move as much cash flow and production forward as we can and create value for our shareholders.

Okay, that's helpful for sure. And, Mike, I think you had mentioned first quarter CapEx, and I think maybe the line broke up or something, I couldn't hear what you said. Could you repeat that?

Well, on an accrual basis, Leo, it was about $40 million for our 2013 activity. But on a cash basis, it was only like $8 million.

Okay, got you. And I guess, could you guys comment on what cash G&A was in the first quarter of '13?

G&A was $4.4 million, cash G&A.

Okay. And I guess, I think you guys have reported $4.4 million in your income statement, but I know some of it was capitalized. I'm just trying to figure, is that $4.4 million the right number if I adjust for the capitalized interest, and I know you have some noncash stock compensation?

Yes, that's another -- Leo, that's another 35%, 40% that got capitalized.

Okay. So I guess it would be higher. And you're saying that the total of it is 35% to 40% capitalized?

Right. That's right.

Okay. And then I guess in terms of well costs in the Utica, is there any update there? Anything changed on the well costs?

Not really. The only -- one thing that is different though is that we did drill our longest lateral to date. We just finished the McCourt 2-28 [ph]. And that lateral was 9,485 feet long. The total measured depth was over 17,000 feet. So as compared to, say, a 6,000-foot lateral, that's going to be 50% more frac cost. So the good news is, though, it's going to be 50% more EUR. And that well, I might mention, we used rotary steerable on that. And that's been -- that's good for a number of reasons. One is that we put the rotary steerable in. We built the curve with it and went to TD in 6 or 7 days, and we were making about 2,500 feet per day on the last couple of days after building the curve. Now that's a good thing. Actually the break-even cost point is around 6,000 to 6,500 feet of lateral length. But when you use the rotary steerable, obviously, it's rotating all the time so you keep the hole cleaner, which means that you're going to get a better cement job, which means you'll get a better frac job, which means that should gain you IP and that should gain you rate. And the other thing is we can keep -- we have a target zone that's about 1/3 of the way up from the bottom of the Point Pleasant. And conventional tools sometimes, we're off 10 to 15 feet away from that above or below it, particularly, after you make -- right after you make your curve. But with rotary steerable, you can hit that target point. You can stay within a foot or 2 of that the whole away. So geologically, we're keeping our hole in the real sweet spot. So we may actually start using the rotary steerable on the wells that are less than 6,000 feet. We don't drill many of those, but even though it might cost you a few more dollars, and it's not that much more when you drill the lateral, we think the IP rates and the EURs are going to be improved enough to more than pay for that extra cost. So that -- but one thing that's been different, the cost per foot is pretty much like we thought, but we are drilling some longer laterals with more feet.

Our next question is from Brian Velie of Capital One Southcoast.

Most of my questions have been answered. But I just wanted to clarify something that you've mentioned earlier, Mike. The additional wells now with the accelerated plan, those are going to be coming on, you said, kind of in a fashion that will help you get set up for 2014 and give you some momentum there. So should we think of those as those incremental wells coming on so close to the end of the year that they weren't necessarily or aren't necessarily going to be much of a factor in '13 production, or do those help you maintain your '13 production guidance after the slow start?

They'll help some. If we bring in the rigs June 1, by the time we get them drilled, frac-ed, rested, we will get a little bit of impact, but not a great deal. Really, it really helps more exit rate at year end going into 2014 than it does 2013.

Okay. So the -- making up the difference after the delays here in the first quarter, then, I guess, the majority of that ground that's made up, I guess, can be accounted for in better well performance maybe than you were expecting beforehand, is that fair?

That's right. We're very encouraged by what we see and all the results we've talked about today. So I'd say that's a correct statement and we will get some incremental benefit, but the benefit will be more from the other wells.

The one thing is we feel like we're having our test results validated by the production, and it's time to go into manufacturing mode. We're getting close to manufacturing mode. Time to start ramping up our production quicker, get more value out of the ground quicker. And a side benefit is it helps us stay with the guidance we've put out. But like Mike said, we'll really be ready to hit the ground running in '14.

Okay. And then one more. Ron's question got to the 1/3, 1/3, 1/3 guidance that we talked about last quarter. I know that's for 2013. How much of that breakout is based on where you're choosing to drill this year, or is that something that you think is a fair split as we model out further years, or how variable will that be do you think going forward?

Well, I think it's a fair split for this year considering where we're focusing our activity. I think that may change a little bit in future years as we begin to delineate, for instance, that western, that window on the western side, the oil window and then maybe even more into that dry gas window. So it could change up some, Brian. But I'm not ready really to talk about 2014 until we get that drilling program completely mapped out.

Okay, great. And then finally the 4 wells that you brought on -- or that you detailed in yesterday's release, not quite as large from an IP standpoint, but certainly more condensate rich than, I guess, the previous average. How would you rate those amongst that previous average in terms of rates of return? Are they middle of the pack or somewhere else?

No, I think, if you're looking like at the Lyons, they're kind of in line depth-wise, a little bit shallower than a Boy Scout. They're going to have less gas per barrel of oil, but they still have substantial tests on the barrels of oil. I think what we're going to have there is they're going to be ones that -- they may actually need the artificial lift within the first month or 2. But one thing that we've seen, and like Von Gonten, he's seen a lot of stuff, too. And he sees that for the -- when he sees well histories and other places besides ours, they may not have as high an IP, but they are real flat declines through the Utica. So that gives us confidence that these are going to be flat declines. I think when you have like a Lyons with a smaller amount of gas, you're going to need the help with the gas lift, that's why we're putting the gas lift valves in there. But I don't -- I think we're going to see some really strong wells. There's a lot of oil in place over there. Just needs a little help with secondary, I think -- and it's what I'm expecting as compared to a Boy Scout, which has managed to flow longer than any of us expected it to.

Our next question is from Kerr Friedman of Simmons & Company. Kerr Friedman - Simmons & Company International, Research Division: Most of my questions have been hit, but just 2 real quick ones here. I'm curious if you could update us with your thoughts pertaining to the percent of your leasehold located in the wet versus gas versus oil window?

Well, I think we're probably still, like we said before -- Neal pointed out that, that Hess well that tends to valuate our old lines that we use, but we've said that about 17% looks like it's over in the gas side of things. We've got about 75% or about 70% in the wet gas window, which is the wells we drilled last year, the 14 wells we drilled last year. And then on the far west, the oil window, there's maybe the other 13% over there west of the Crow. Kerr Friedman - Simmons & Company International, Research Division: Okay, great. So no changes there. And then last question for me. We've kind of seen here recently that some operators have been posting estimated RORs in their Utica -- on their wet Utica position. And I'm curious to hear how your perspective of your leasehold matches up some of these RORs that other operators are posting?

Well, based on our type curves for the Boy Scout and the Wagner, which are ones that have been around for a while, our rate of return on those wells is right at 100%. They're looking really stout. But some of the other operators, I'm not sure which ones you're looking at, we don't have that much information about what they're doing. I don't know what numbers went into it. But ours are looking really good. We -- last year when we were planning -- well, even 4 or 5 months ago, before the gas prices got like -- where we thought the Wagner and the Shugert type wells would be a little slower payout and so forth because they were gas and -- but gosh, we had the Wagner on and its condensate levels are hanging in there. Now we're 9 months into it, that's still got great condensate recoveries. And then the NGL recoveries now that we're getting for it, we're soon to get 48 barrels per million at $60 a barrel. I mean, now they've matched up, where both of them are paying out in the year. So it's really looking stout with what we've got.

Final question is from Mario Barraza of Tuohy Brothers.

Just appreciate all the color on the Utica. Just quickly on the -- in Grizzly with first steam looking to happen in the next few weeks, are you still on track for production to come now in the third quarter?

I think we are. Actually, the first steam slipped a little bit, but they're down to the points of where they have milestones like certain commissioning dates that they're doing now. So it's going to be a little behind schedule. But they've also -- there's new technology coming along all the time. They're looking at a couple of things like injection condensate ahead of time and -- or hot water. And so they think they may make up a month toward first oil. So even though first steam seems to be -- maybe could be a month behind, first oil may be 2 months instead of 3. So we're still thinking first oil toward the end of the third quarter.

Thank you. This ends the Q&A portion of today's conference. I'd like to turn the call over to Mr. Paul Heerwagen for any closing remarks.

Thank you, operator. I believe we're out of time today. As always we'll be available off-line for any questions or follow-ups. A replay of this call will be available temporarily through the company's website and can be accessed at gulfportenergy.com. Thank you for your time and interest in Gulfport today. This concludes our 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.