Paul K. Heerwagen - Director of Investor Relations Michael G. Moore - Chief Executive Officer, President and Director J. Ross Kirtley - Chief Operating Officer Ty Peck - Managing Director of Midstream Operations Lester Zitkus - Keri Crowell - Mark R. Malone - Vice President of Operations for Ohio Activities Robert A. Jones - Vice President of Drilling for Ohio Activities Stuart A. Maier - Vice President of Geosciences

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Timothy Rezvan - Sterne Agee & Leach Inc., Research Division Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division Jason A. Wangler - Wunderlich Securities Inc., Research Division Mark Lear - Crédit Suisse AG, Research Division Jeffrey W. Robertson - Barclays Capital, Research Division Cameron Horwitz - U.S. Capital Advisors LLC, Research Division Marshall H. Carver - Heikkinen Energy Advisors, LLC Leo P. Mariani - RBC Capital Markets, LLC, Research Division David W. Kistler - Simmons & Company International, Research Division Subash Chandra - Jefferies LLC, Research Division Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division David E. Beard - Iberia Capital Partners, Research Division Gordon Douthat - Wells Fargo Securities, LLC, Research Division Jeffrey Grampp - Northland Capital Markets, Research Division

Good day, ladies and gentlemen, and welcome to the Gulfport Energy Corp. Q1 2014 Earnings Conference. [Operator Instructions] As a reminder, this conference call is now being recorded. I would like introduce your host for today's conference, Mr. Paul Heerwagen. Sir, you may now begin.

Thank you, Marcus, and good morning. Welcome to Gulfport Energy's First Quarter 2014 Earnings Conference Call. I'm Paul Heerwagen. Our order of speakers on the call today will be Mike Moore, Chief Executive Officer; Ross Kirtley, Chief Operating Officer; Ty Peck, Managing Director of Midstream; Lester Zitkus, Vice President of Land; and Keri Crowell, Vice President, Controller. Also on the call are Rob Jones, Vice President of Drilling; and Mark Malone, Vice President of Operations from Ohio; Stuart Maier, Vice President of Geosciences; and Steve Baldwin, Vice President of Reservoir Engineering. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, result 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 yesterday afternoon to our website in conjunction with this earnings announcement. Please review it at your leisure. At this time, I'd like to turn the call over to Mike Moore.

Thanks, Paul, and good morning to each of you. I would like to thank Gulfport's Board of Directors for their continued support, and I am honored to have been chosen to lead the company as the Chief Executive Officer. As Gulfport enters into this new chapter, the board and I are focused on developing a clearly defined plan, strong leadership and a proven ability to deliver on expectations. As a management team, our confidence in the Utica remains very strong. We all have keen awareness that we are stewards of a world-class asset as well as the resources of our stockholders. With this knowledge, we also believe it is in the best interest to manage this asset for long-term, sustainable growth. We have learned from a number of techniques we have tested in the play and narrowed in on a methodical, systematic approach that we think will maximize long-term value. Over the past several weeks, the management team and I have undertaken a very detailed review of our operations and the assumptions we were using to build out our development model leveraging off the knowledge and extensive shale experience of our new operations team. I challenge the team to carefully consider the balance between near-term growth and long-term value. Following this review and our ongoing analysis of the data from multiple approaches we took early in our development, we have determined that the original assumptions driving our operations were focused on near-term growth and now believe a managed, slower-pace of development will yield superior long-term results. Furthermore, our risk expectations for our Midstream partners, a measure outside our control, now only leave a narrow margin for error. Ultimately, the team and I are data driven and our results to date have led us to change our strategy going forward. This…

Thanks, Mike, and good morning. When evaluating the drilling side of the business, utilizing state-of-the-art, built-for-purpose equipment and experienced personnel directly correlates with our performance at the drill bit. The drilling team made it a priority during the first quarter to evaluate current contractors and service providers, and replaced those operating below our expectations. We recently contracted an upgraded generation AC [ph] shale rig that will be moving into the play shortly, and we accomplished this with no significant price increase. We have been and continue to work with contractors and service providers to upgrade the current equipment by replacing lead pumps, enhancing top-drive equipment, upgrading air packages and improving rig mobility. As you will see in the presentation posted to the website yesterday afternoon, during the first quarter, our team made excellent improvements on the amount of time from spud-to-rig release. Gulfport recently drilled multiple wells on different pads from spud-to-rig release in less than 24 days average. This is an approximate 10-day improvement from where we started the year. And bear in mind, this was accomplished as our average lateral length increased during the quarter. This is progress in the right direction as we continue to promote consistency and efficiency, and we strive to meet this goal with every well drilled. Turning towards the operations side of our business. We remain focused on the analysis of the data and the metrics generated since the inception of the play. Gulfport, along with all of our peers, is still learning the best way to produce these wells in this new emerging play. Determining the optimum production rate and pressure of any well is an act of balance and is a greater importance in the multiphase reservoirs. By maintaining producing pressures above dewpoint, it is possible to extend the producing life…

Thanks, Ross. On the Midstream front, we have continued to add to our firm transportation portfolio to enable us to advance on the execution of our dry gas development. In our process to add additional transport, we have maintained a diversified portfolio approach to both markets, term and structure to ensure we make commitments where we believe it necessary to move our product in the long term while maintaining attractive realizations. With regards to our dry gas gathering system, we have spent much of the first quarter working with MarkWest to optimize the system design, ensuring consistent operating conditions, as well as the ability to access the firm transportation and sales previously secured. Although MarkWest has been actively completing and clearing the right of way, we believe the tie-in dates for the dry gas wells may be later than forecasted. And as a result, we have decided that our initial margin of error has been absorbed and that further risking of our first sales days for the pads in the dry gas window is necessary. With the majority of our rich gas production going through MarkWest Cadiz I facility, we are anticipating MarkWest completing the 200 million cubic feet a day of Cadiz II processing facility in the next 3 to 4 months. While we continue to have access to MarkWest Seneca processing complex prior to the completion of the Cadiz II facility and do not anticipate our production to be curtailed, we will not be able to fully access the premium Midwest markets until the Cadiz expansion is completed. Due to this environment, Gulfport has chosen to slow the rate of gas growth in the wet gas window in an effort to optimize returns and match the firm takeaway already secured. In addition, as Ross just mentioned, this approach will fit well with the company's new directive of creating an inventory of wells in the completion queue. As we look into the remainder of 2014, we will continue to sell the majority of our gas out of the basin as our firm commitments will phase in with our production growth. Early on, we focused on securing pads out of the basin, and you have seen the flow through in our strong price realizations. Though we expect to maintain these through the remainder of 2014, the growth of the Utica volumes and associated cost of gathering and compression and fractionation and transport has led Gulfport to announce yesterday an adjustment to our gathering, processing and transportation expense, and now anticipate this to be in the range of $3.50 to $4 per BOE during 2014. We continue to navigate the market complexities, securing short-term flexibility without sacrificing the implementation of our long-term strategy of securing a product value by a diversified portfolio approach.

Thank you, Ty. Joining us on the call today, a recent addition to the Gulfport team is our Vice President of Land, Lester Zitkus. Lester brings with him over 25 years of experience in the Appalachian basin land work both in both the Utica and Marcellus. Lester has extensive background specifically in the Northeast, just providing Gulfport with a strategic advantage and level of expertise as we continue to pursue an aggressive leasing program. And with that, I'll turn the call over to Lester.

Thanks, Mike. Gulfport has recently entered into an agreement with Murray Energy Corporation, the nation's largest privately-owned coal company in addition to the largest coal operator in eastern Ohio, to lease approximately 8,000 acres of its oil and gas rights located primarily in Belmont County Ohio. This agreement marks the first of its kind in the Utica where an oil and gas operator and a coal operator are working cooperatively in order to coordinate well locations with the timing of development and proximity to active and plant coal mining operations across a broad area of Belmont and Monroe counties. We believe this agreement is also significant as it fits very nicely with our existing leasehold position in the dry gas portion of the play and adds a substantial amount of acreage to our dry gas development portfolio. Recently, Gulfport quietly began acquiring leasehold in certain portions of the West Virginia panhandle following the Utica shale play across the Ohio River. Following similar parameters to the approach used in the initial stages of our Ohio development, Gulfport's geologic team has identified target areas for the Utica in West Virginia and developed the tiered outline to focus our acquisition efforts. We are taking a disciplined approach by keeping our leasing activity within graded fairways where we believe the Utica to be most prospective economically as a standalone play. Additionally, when available, we are pursuing both Utica and Marcellus rights for the potential of stock pay opportunities and additional economic upside. Since the time of our last call, we have added approximately 13,000 net acres, and Gulfport now holds approximately 179,000 net acres under lease. Thank you for your time today, and I will now turn the call back over to Mike to discuss our other asset areas.

Thank you, Lester. Starting with Canada. During the first quarter of 2014, Grizzly's first SAGD facility, Algar Lake, achieved first bitumen production. Grizzly currently has all 10 well pairs on full steam circulation and averaged approximately 275 barrels of the bitumen per day during April. Grizzly continues to see production ramp as expected during the warm-up phase of steam circulation and currently anticipates the project to reach its peak production of approximately 6,200 barrels of bitumen per day in the second quarter of 2015. Grizzly's Windell terminal in Conklin and Alberta commenced operations during the first quarter, and Grizzly is currently in the process of taking delivery of its 350 leased rail cars that the company contracted to support the transport of Algar Lake production. In addition, Grizzly is currently in negotiations with multiple third-parties to provide loading services at the Windell terminal. At the Paulina terminal along the lower Mississippi River, Grizzly continues to work through the permitting process to gain approval for the construction of the 40,000 barrel per day barge transloading facility. Similar to producers in the Bakken, who have a solution to move their product, we believe Grizzly's rail solution out of the Canadian markets will allow optionality for multiple end markets and provide the company with the strategic advantage to ensure maximized returns. Now turning to Southern Louisiana. In Southern Louisiana during the first quarter, we drilled a total of 9 wells, completing 4 as producers with 4 waiting on completion and 1 nonproductive. In addition, we perform 38 recompletions. Currently, we are running 2 rigs and are drilling ahead on our 13th and 14th wells of 2014. I will now turn the call over to Keri to cover the financial highlights during the first quarter of 2014.

Thank you, Mike. During the first quarter of 2014, Gulfport generated approximately $192.8 million of EBITDA, $141.1 million of operating cash flow and $82.6 million of net income. Our first quarter net income includes a loss from hedge ineffectiveness of $8.7 million and a gain of $48.8 million in connection with our equity interest in Diamondback Energy, a gain of $84.8 million in connection with the sale of Blackhawk, a loss of $1.8 million in connection with a nonrecurring retirement expense and a loss of $18 million in connection with the potential litigation settlement relating to our Southern Louisiana legacy asset. Adjusted net income comparable to annual assessment, a non-GAAP measure, was $16.7 million or $0.20 per diluted share. In the first quarter of 2014, production totaled 2,437,851 barrels of oil equivalent or 27,087 BOE per day. Allocated by field, first quarter production breaks out to be 21,062 BOE per day from the Utica; 5,776 BOE per day from Southern Louisiana; and 249 BOE per day from the Niobara, overrides and other miscellaneous areas. Our production mix for the first quarter was 48% oil and natural gas liquids and 52% natural gas. Average realized prices before the impact of derivatives for the quarter were $98.26 per barrel of oil, $4.98 per Mcf of natural gas and $60.20 per barrel of natural gas liquids. Our blended realized price before the impact of derivatives for the first quarter was $55.66 per BOE. Gulfport experienced strong realizations during the first quarter of 2014, with natural gas settling approximately 96% of NYMEX and our NGL settling approximately 61% of WTI. Lease operating expense for the first quarter was $4.77 per BOE; transportation, processing and marketing expense for the first quarter was $3.19 per BOE; G&A was $3.90 per BOE; and depreciation, depletion and amortization…

Thank you, Keri. To wrap things up, keep in mind, we have just begun to scratch the surface of a 10-year inventory of drilling locations we have in the play. We continue to believe our acreage is the core of the play and our thought surrounding overall productivity remains strong. Since our last call, we've had great success in acquiring acreage in the sweet spot of the play, increasing our total position by 13,000 net acres. We've continued to add acreage and firmly believe each acre added in the core of the play brings significant value to Gulfport and our shareholders. My goal as CEO is to create a solid development strategy to harvest this value by leveraging off both the technical knowledge we have collected and the experienced unconventional shale team we have assembled. It is my hope that our new approach to development will allow Gulfport to enhance the estimated ultimate recoveries of our wells in the Utica and deliver on market expectations. I thank you again for joining us on our call today, and we look forward to answering your questions.

Operator, please open up the line for questions from our participants.

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

Mike, for you or Ty. Just obviously, with the Midstream issues that you've had on this -- on the guide down and then, obviously, you previously had, what's your thoughts for -- I guess, going forward, is there any alternatives that you all think about building more out of yourself? Are there Blue Racer or Dominions and some others that you could go with -- your thoughts -- you're kind of locked in with them or MarkWest at this point?

We've had good relations with MarkWest -- this is Ty -- and continue to work with them on a daily basis to make sure that we're pushing them. And I think we've -- we have some alternatives out there, but I think MarkWest is committed to getting the completion done. They think they can get it done. It's just a matter of us putting additional risk into our guidance.

Okay. And then, obviously, on the retrograde condensate issues, Mike, in the frac communication, just your thoughts on -- looking like it, I guess, for some of this aging condensate wells, your thoughts on the GOR going forward and, I guess, how that impacts -- or how you guys are thinking about the choked management sort of impacting these.

Mark, you want to take that one?

We've been up to look at the condensate wells and our wet gas wells for quite a while now. We've had -- we've got a lot of production to look at, and that's what we've been focusing on as of late. So right now, we don't seriously are changing anything associated with our type curves or anything to that effect, so...

Mark, does that mean -- I guess, when you look at, I guess, kind of what you all have said about some of these older wells for the retrograde condensate issues and the communication. I mean, are you guys still -- I noticed you didn't change the, obviously, the type curves. You have the ranges there. I mean, do you still have the confidence that they can still trend around those type curves, Mark?

Absolutely, absolutely. All shale plays have communication issues. I don't -- I've not been involved in one that has not. So I don't want to say it's common, but it happens. The good news is, is that in our shale play, it doesn't -- it isn't long-term effects, and most of the wells turn around. There is some water load for some time, but that's reversible in most all cases.

So Neal, just add to that, the data that we have today certainly supports the type curves. And we've been flouting the production of the wells on the type curve. And as you know, we started operating the wells, particularly in the condensate window, a different way, and we saw an improvement in the way they performed, and continue to see that improved performance. But we don't anticipate a change in the type curve. Certainly, there's not one mandated now as the data still supports it. It may be that, over time, with the new production techniques, the shape of the curve changes, but the area under the curve would not change. In fact, the hope would be that we could improve the area under the curve, which may ultimately improve the EURs.

If I could -- and just last question, Mike Moore, from strategy, just your thoughts. You continue to add a fair amount of acreage even, I would say, more than most in the play. Again, is there a certain number you're trying to get to, or is it just you think the economics are such that it still makes sense to continue to expand the acreage to sort of build up this inventory?

Neal, we continue to believe that this is the very best shale play in the United States, and so we're focused on adding acreage in what we think is the core area, we're very focused geologically. We've done a lot of work over in West Virginia. We've high-graded a fairway that we're interested in. So I don't -- we didn't say that we had a particular number in mind, but we think it creates a lot of value for our shareholders by continuing to add acreage in this core area of the play, and we certainly are going to continue to do that. Within reason, obviously, a price is always in consideration as well, but no set number in mind at this point. We have ways to fund it. Obviously, we're very liquid as a company, and so we're going to continue to be aggressive out there.

Our next question comes on the line of Tim Rezvan from Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: I was wondering if you could speak with as much kind of specificity as possible as to how you came up with this new guidance? And, really, why investors should believe it, given the challenges you've had with previous kind of forecasting?

Okay. Tim, that's a good question. So we've spent a lot of time recently really doing a deep dive into the data -- and Mark could jump in as well. But really, we were kind of focused -- his group really was focused on making sure that we were producing, developing every phase window of the play most efficiently. We saw an improved performance -- we're in the condensate window, obviously, when we changed the way produced those wells. And so the idea was, is there a more efficiently to produce the other phase windows also? And so they -- we have 50 wells producing now, we have a lot of data to look at, a lot of science. And so we did a deep dive into that information and have decided that there is a more efficient way to develop and produce each phase window of the play. Obviously, we're going to have to implement the new plan and monitor it going forward. But Mark and his team have a lot of experience in shale plays for many, many years. And so they bring a lot of technical knowledge and experience to the table. And we need to rely on the data and we need to rely on their expertise as a team, and that's what we're going to do here. Secondly, Mark's team asked for the opportunity to have an inventory of completion so they can be more efficient with their completion operations out there. And ultimately, also, hopefully drive prices down on the operating side of the business as well. And thirdly, Ty talked about midstream, possible midstream delays. Again, we were changing guidance for new production technique, completion inventory and we also became concerned that there might be some shift to the right in our midstream areas. So we thought it was appropriate to also risk our model more than that. As to, I guess, your last question, we are confident in our team, we're confident with our new plan. We certainly want to deliver on expectations, and we're going to do everything in our power to do that. But we needed to reset the expectations to be in line with our new plan. And all I can tell you is, Tim, that we're very focused as a team, and we're going to work very hard to make sure we meet and, hopefully, beat expectations going forward. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. I guess -- and then following up on that, can you talk about maybe the cadence of completions and wells being turned to sales? Kind of -- is that what's driving this updated number? Like, how do you see the growth playing out this year?

Well, if you're asking how many wells we're going to complete each quarter, we used to talk about, I think, 15 to 20 wells. So I think the range is going to be broader. So it's going to be a little lumpier. So generally, it will be 14 to 21 wells. We've already mentioned obviously that the second quarter is going to be relatively flat. We still have those 14 wells down, working on those from simultaneous operations. But then you're going to see a pretty linear ramp in the third and fourth quarter getting to the exit rate in the mid-50s, as Keri mentioned. So I'd -- I think that, at this point, this is how we're looking at the development. And the change is really -- it has to do with the new production techniques which, obviously, will mean that we've produced the wells and in a different way, less aggressive. And then also, we're going to have to build this completion inventory. So we're actually going to hold wells and not complete them necessarily, as soon as they're ready to be completed, to allow Mark's group to build this inventory. And then thirdly, obviously, part of the change as well is the shift to the right of being able to hook up some of our wells in the dry gas window, and then also be efficient with the processing facilities. So I'd say it's equally weighted. If you had to think about the 3 changes that we're making. I'd say the 3 had equal impacts on the guidance. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. Appreciate that. And then, I had one more and then I'll step off. With this exit rate guidance you've established in the mid-50s on a BOE per day basis. What, if any, contribution are you expecting from the dry gas window, which I guess is my way of asking, are you -- is anything in 2014 at risk if MarkWest really kind of stumbles on getting your dry gas hooked to sales?

Well, I think, we're really just talking about 2 pads. So I think the impact would be pretty small, Tim, 1 or 2 pads for maybe 1 month, is the kind of risk we're talking about. So the risk is pretty small. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: So that's what you have factored in right now?

That's right.

Our next question comes from the line of Ron Mills from Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Going back to the type curve discussion in terms of over time you think the EUR will at least stay the same, if not, potentially increase by changing the flow back. Can you provide a little bit more color beyond that and talk about how that also compares to the potential PV in that scenario and rates of return, or how that factored in to the decision?

I'll let Mark take that one.

Again, as I mentioned earlier, we've been looking at the production for quite some time. And we have the opportunity to flow some of our wet gas wells at some fairly aggressive rates. Love what our type curve indicates. When that happens, we've seen some signs of liquid loading and various things that we think are detrimental. So it's really flowing in a lesser rate to try to preserve the pressures. The good news is that we have a great deal of reservoir pressure in all phases of the play, so it's a positive thing. But again, we are trying to delay the -- trying to increase the EUR over time. Again, as far as the top curve, it's more about the shape of the curve and trying to affect the EUR in some positive manner. So...

So I think in the PV perspective, Ron, our hope is that we actually increase EURs, which would have either a positive effect of PV or at least a neutral effect on PV. So we don't think, ultimately, we're hurting PVs. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then maybe on Lester on the leasing side. The leasing and crossing over the river into West Virginia, can you give us a sense as to the competitive nature there versus Ohio, as industry has started to ramp activity in that place, in that area, and relative pricing to the Ohio side?

We're, for obvious reasons, not wanting to talk a whole lot about pricing or competitive nature. But I will say that we're taking a very measured approach. The environment over there is very different than what we've seen in Ohio, with regard to the need to really identify drillable blocks. It is not, in our view, wise to run over there and conduct the blanket lease play based not only in geology, but surface issues. So we're trying to be surgical about where we acquire with assurances that we can develop it and get the gas out. With regard to pricing, I don't want to go into that either, but I will say that at the current time, it's a certainly favorable to what we're seeing prices do in Eastern Ohio. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then maybe, Mike, this is for you, just from a -- or maybe Keri. From a liquidity standpoint, the reduction in guidance, there's obviously a reduction in cash flows and EBITDA. You talked about the liquidity of have including the Diamondback shares you have, quite a bit of liquidity. If you look out to 2015, you'll have some flow-through impacts. How do you think about that impact later in 2015, given your relative leverage position, which is low and the growth in EBITDA is -- could've been more of a high yield type impact in 2015? Or how would you look at that liquidity?

Yes, that's a good question, Ron. So we don't yet know exactly what our 2015 program is going to be. Certainly for this year, we're well-funded with the cash that we have on hand. The Diamondback stock and access to our revolving credit facility of $275 million that, keep in mind, will grow as we continue to add Utica reserves, so I would expect the fall determination to add quite a bit more of availability there, it's completely undrawn. But we're at a different point in the play, Ron, now. And so, certainly, at some point, debt is appropriate. We were -- when we were early in the play, it didn't make as much sense, although we did put it on $300 million of high-yield debt. But I don't know if you saw, we recently got an upgrade in rating from one of the rating agencies. And so when it is time for us to go back to the high-yield markets, I think we'll see improved executions. So it certainly is appropriate at this point in our stage development. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then one last one on -- maybe for Mark. In terms -- when we -- you talked about the backlog of completions. What do you think is an ample number of wells in backlog to -- what level do want to get to, to be able to maintain that more consistent completions? And just, Mike, was the upgrade before taking into account the -- this guidance change, I would assume?

Well, I don't know if there's a magic number. I mean, ultimately, it may turn out to be 3 to 4 pads. But key is simply having an inventory in front of the fracture, so we can go from pad to pad consistently. 3 to 4 pads equates to 12 to 15 wells between now and the end of the year. So again, I don't know if the number is just as important as just having wells in front of the crew so they can move uninterrupted.

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

Just curious as far as with the guidance move, and, obviously, the second quarters kind of being flat. It looks to me at least like your gas hedges, you'd probably be over-hedged. I mean, could you just speak to what that might mean for even second or maybe even third quarter? And what outcomes, I guess, are there?

We may be a little bit over-hedged for the second quarter, but I think that quickly changes as we move into the third and fourth quarter. So it really doesn't have a big impact on us, Jason.

Okay. And I appreciate the inventory discussion. I guess from just the plan of how many wells to have completed this year, does that basically just move down by the, call it, 10 net wells. And if it does, what is that difference, I guess, in the exit rate from kind of holding back? Do you have any idea on that?

I'm not sure the net impact is 10 wells, it's probably something between 5 and 10, Jason.

Our next question comes from the line of Mark Lear from Crédit Suisse. Mark Lear - Crédit Suisse AG, Research Division: I guess, can you kind of talk through the decision to not use the interruptible capacity at Seneca. I know diffs [ph] might be a little bit wider, but still probably getting something from your gas versus nothing also could be beneficial.

Yes, this is Ty. We will have -- we send gas down to Seneca today. We have some capacity firmed up there as well as well as take away masked with that. And so if it extends too long, then we will have to make those decisions. It's just a matter of, do we want to send our gas -- with the new directive here, we want to send our gas to a place where the differentials are high? And if we have 1 week, 2 weeks, 4 weeks, just depending on the timing, do we want to do that or do we want to help build this well inventory. Just taking in all of these factors, we'll have to make a decision at that time. But we now have in process the -- or in place the process to make sure that feedback and those decisions are made appropriately.

And, Mark, just to follow up. It is a business decision, but it's really -- we're talking about a slight delay to get a 25% increase in our price. So that seems like a wise business decision. We're talking about millions of dollars here. Mark Lear - Crédit Suisse AG, Research Division: That's fair. I guess given some infrastructure constraints in different areas of the play, maybe can you talk about the ability to reallocate rigs to different areas to take advantage of areas where do you have infrastructure? Or is it kind of the rig -- where the rigs are primarily focused on the dry gas and wet gas window, is that going to stay consistent going forward?

Well, that's the beauty of this play. You do have different phase windows and you certainly have the ability to move rigs around to take advantage of the best opportunities possible, and certainly, we can do that. And there may be times that we do choose to move rigs around, depending on what we see. Mark Lear - Crédit Suisse AG, Research Division: And then I know you're talking about building up a backlog, have you guys said where the backlog is currently? And then, I guess you said you wanted to get to maybe 4 or 5 pad backlog of 4 to 5 wells, so how many more do you need to drill to get to that level?

The number of wells that we've drilling on has been published. I mean, that doesn't change. The backlog was simply again staying -- having similar wells waiting to complete, so it doesn't affect our drill program. Mark Lear - Crédit Suisse AG, Research Division: Right. But...

Mark, we -- I'll make sure I clear all your questions. We don't have a backlog right now. We're just beginning to build the backlog. So Mark -- as Mark mentioned earlier, his team is going to start building the backlog inventory so that they can be more efficient in their completion. So are we answering your question? I want to make sure we got it right. Mark Lear - Crédit Suisse AG, Research Division: Yes, I mean, I guess I want to get a sense for how this backlog, ultimately, kinds of smoothes out the lumpiness. I mean, are you guys are ultimately going to be focused on -- I mean, clearly the focus is to reduce wells' downtime going forward, and I thought this was an issue that was kind of put behind you. But how is the development plan, I guess, changing as well from this standpoint? Are you guys going to be drilling pads next to each other? Or kind of focused on drilling out an entire area, so you ultimately don't have forward downtime? I just want to get a sense how some of this lumpiness ultimately goes away, because building backlogs and drilling bigger pads should get you there. Kind of what's the timing on when, I guess, downtime is going to be kind of behind you?

This is Rob. I'll kind of try to address this. Really, the goal from the drilling side is to try to get consistent with the rigs that we have. And it looks like there's a slide in there in the presentation that we've done a pretty good job here in the first quarter. As we do that, we want to have a set of wells always ready for Mark's frac crews. And there's kind of a balance here that with the 7 rigs, I'm going to be producing so many pads and so many wells monthly. And then his, which is probably a little lesser number of frac crews, are able to move to those locations. The way this will work is that the drilling will get out in front of the completions, and then there'll be a time down the road that you add another completion frac crew. So you kind of -- and then the inventory will go in the opposite direction.

Our next question comes from the line of Jeff Robertson from Barclays.

Mike, most of my questions have been answered, but I was curious if you could talk about what the exit rate for the first quarter might have been had you not changed your completion schedule?

For the second quarter or the first quarter?

Well, first and second. Just, I guess, if you hadn't changed your completion schedule, where would you have been tracking relative to the prior guidance?

Yes, I'm sorry. I just don't -- I don't have answer to that question. I don't -- I haven't looked at that.

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

I guess, Mark or Mike, just on the condensate frac communications, can you talk about just what the lateral spacing was between the optimized wells and the original wells? I think it sounded like you guys just had the communication issue on the BK Stephens, so I'm just trying to understand how that was spaced maybe versus the riser?

They were spaced 1,000 foot, on this particular example.

Go ahead. Okay. So there was no significant difference in terms of -- it looked like in this schematic, maybe there was some difference in terms of how those walls were spaced?

Yes, there was. The BK Stephens is 1,000 foot, and the riser is -- build the riser just to the north, the opposite direction.

Okay. So no -- so the spacing pattern on them is essentially the same. So I guess I'm just trying to understand why -- potentially why you might have seen some of that communication on the BK Stephens, and I guess not seeing it on the riser?

I don't know that the communication is a spacing issue. And there's -- we mentioned early on. I mean, communication is pretty prevalent in most all of shale plays. I personally have not been involved with one that has not seen communications to some degree. The good news for us is in most every case, the wells recover. I mean, you do have some lost reduction for some period of time as well loads up. It takes some time or some special operations to get that water unloaded. But the good news is they do recover. I think if you look at the slide on Page 17, what you'll see is a dramatic drop when that well is impacted. But if you look out, I mean, it's also recovering quite nicely, and we expect it to return to original production.

And just additional comment, this is -- communication during frac-ing is not unusual in this kind of a play. Every operator sees it. It's very limited. We haven't seen it a lot out here, so it's not really something that we're surprised with. I has nothing to do with spacing. Really it's -- can vary from pad to pad, from well to well. Rock can have unique characteristics in certain areas. So it's just something that happens from time to time. So it's nothing that has implications for spacing, it just is something that we sometimes see in the shale play.

Okay. Appreciate that. I guess given that, to some degree inherent variability, how are you thinking about that concept as it relates to your guidance? I mean, how do you factor that in?

Well, we're still generally spacing wells. If you're talking about -- are you talking about spacing them? What are we...

No, I guess just in terms of your production guidance. I mean, how do you factor in the whole -- the frac communication into the production guidance?

It's not necessarily to factor it. It's so limited. It just so happens so rarely. And remember, some communication is okay. So it's -- this one, in particular, we pointed out because it's a explanation that we needed to make for the downtick on that particular slide. But it's not something you need to factor in. It's something that happens only very occasionally. And usually, the wells clean up typically pretty quick it come back. So only sometimes do you have any kind of permanent communication.

Our next question comes from Marshall Carver from Heikkinen Energy.

I realize you haven't given any 2015 guidance at this point, but what are the key project milestones to watch there? Has any of the timing on those slipped at all in the last quarter?

Well, if you're talking about what has to happen before we can decide what we do in 2015, is that your question?

Yes. Or any color you can give on -- yes, that would be one way to answer my question.

Okay. So I'll attempt to answer that. If I don't answer, please let me know. But certainly, this play is not in development mode yet, so we still have to understand downspacing. The Darla pad, as you know, is our big experiment out there and we're doing a lot of science. We're not going to have the answers on that until later in the year. The other thing is, certainly, that we have to make sure that the infrastructure is there and available for us in all the areas of the play before we can think about ramping up in bigger ways. Those 2 really haven't changed. Those have been certainly milestones that we needed to hit before we could think about moving to manufacturing mode. But I'd say the third thing is, Rob and Mark, both are working on getting our well cost down. And so we need to get our well cost down before we move to development mode of the play. So we're still in the early process, but as we look to 2015, I hope most of the milestones have been hit, and we can think about this play in a different way. We certainly are very excited about everything we see below the ground. And so what we're trying to do above the ground is make sure that we're producing these wells the most efficient way possible.

You haven't seen any change on any of the 2015 infrastructure timing in the last quarter or so?

This is Ty. No, we haven't. We think 2015 looks better across the basin actually.

Okay. And what is your best guess on spacing at this point in the play? How many feet between wells? Or if you don't know, when will you expect to have that answer?

Yes, we're just going to stick to the statutory spacing for right now. Again, the Darla pad is our big project over on the east side of the play. We did a few things over on the Boy Scout pad early on. But we're not going to have that information on the Darla pad until later this year. So until that, we're just going to stick to statutory spacing for the most part.

Okay. And a final question would be, what are the key issues that would put you at the low end of your 2014 guidance versus the high end? What do you see the main risks to the upside or to the downside of the range?

Well, well hookup variability is a part of it, and then midstream is part of it. I mean, really, those are the 2 ways that you either miss or make guidance. We don't think -- the well hookup, we think, is more controllable than, I'd say, midstream because that's something outside of our control.

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

I was just hoping to clarify this communication issue that you mentioned here. Was this just on frac-ing offset wells or was this actually after post frac-ing on production from wells here?

This has always occurred frac-ing near producing wells. And that's one of the things going forward as we frac on the -- as we drill on multi-well pads. I mean, this -- you're going to see this effect limited as the year progresses for that very reason.

Okay. And I guess just looking at some of the wells you guys have here, I think you've had some condensate wells that have been online for, I guess, almost a couple of years at this point. Can you talk a little bit about what type of oil cut you guys see on the condensate wells at sort of initial production and sort of where that goes as you move those wells today?

Hang on one second, we're looking at that.

Leo, let's follow-up with you offline on the... We've got the details behind type curve that we've previously published. We'll provide that to you.

Okay. I guess just looking at some of the land purchases, and you took the budget up to $375 million to $425 million. I want to get a sense. Does that include the Rhino acquisition in that budget? And also just wanted to get a sense of roughly what the land spend was in 1Q?

It does. It does include the Rhino acquisition. And again, as Lester indicated, we're not talking specifically about West Virginia acreage, but we got 13,000 acres between Ohio and West Virginia at -- I think the average cost was maybe between $8,000 and $8,500 an acre.

Okay. That's helpful. And I guess just looking at your wet gas wells. Can you just give us a sense of kind of roughly where you see the declines on those maybe after kind of a year. I'm not sure if you've had wet gas wells on production for quite a year yet. But just maybe a little bit more information in terms of kind of early IP-type rates and then sort of where those go after a period of time.

I guess I'm not -- you can see on the type curve, Leo, the declines. And so those are the declines. The data -- we're plotting every well onto the type curve and, so far, that's what we're seeing. The way we're producing the wells. Now going forward, we may see something different as we put this new program into place. But right now, on the wet gas curve, the wells are holding flat for a period of time for 18 months.

Okay. So you're actually seeing that flat production for the wells that you have on historically here. That's what I was trying to find out.

Yes, that's what we're seeing. So again, it may change going forward, but we'll just have to wait and see.

Okay. And I guess just to follow-up to that, what's the oldest producing wet gas well at this point?

The Wagner 1.

And what's the rough time on that in terms of how long it's been on.

Started producing in August 2012.

Our next question comes from the line of Dave Kistler from Simmons & company. David W. Kistler - Simmons & Company International, Research Division: Real quickly, kind of thinking about the completion side of your activity. What percent of completions in the Utica are done by your vertically integrated Stingray crew?

I'd say the majority. We do use third party at times. Mark, you want to add to that?

Yes, personally, I mean, Stingray services provide about 2/3 of our pumping services at this time. David W. Kistler - Simmons & Company International, Research Division: Okay. So if they're providing about 2/3, and I would assume same crews, et cetera. When you talk about efficiencies gained by having a -- the same crew there, you're really talking about it with only 1/3 of your completions. Can you quantify what you guys clearly expect to see from the savings perspective?

Well, I mean, there's a couple of reasons to have the efficiencies. I mean, number one, we feel like that services are going to get tightened in the basin towards the end of the year. We're seeing indications on that already. So we're leveraging the amount of work that we have to do to leverage pricing to obtain some better pricing as we go forward. And then if we use services outside of our Stingray services, then certainly we want to have the best services available. To get those, you have to leverage the pricing and also have to offer some commitment. So that's the reason for the... David W. Kistler - Simmons & Company International, Research Division: Sure, sure. Can you give us any kind of color in terms of the term you're thinking about locking down and any flavor in terms of what you're seeing from pricing increases as you've been moving from well to well and picking up and dropping service crews?

I don't have a feel for what the price increase is. But again, to leverage the amount of work that we have is going to give us some substantial savings over the next 12 months. And that's what we will leverage for as the year out.

Our next question comes from the line of Subash Chandra from Jefferies.

I want to revisit and reconcile something you said a couple of minutes ago. On the wet gas holding flat for up to 18 months, I guess the oldest producer there, but then also the view that you might have been pulling them too hard. I guess is the pressure data that you're looking at or what is -- based on flat production, does it look like anything bad was going on from looking at it from the outside?

From the wet gas type curve, again, just to clarify, every well doesn't necessarily produce flat. Every well is a little different. On the aggregate, the curve is flat. And that's what the plot of all the wells together on the curve show. But there are differences from well to well. Does that answer your question?

Yes, yes, no, that helps. So you're saying obviously variability around the mean, and so that's right. So best practice would still be to not flow them as hard and to address the liquid fallout.

That's exactly right. That's key.

Okay. So my second question is, as you see some of this variability across the play, is there a way to determine or do you have a view how much of that is because of the phase change versus the rock quality, the Point Pleasant quality?

Well, we were very focused geologically on the Point Pleasant thickness when we were leasing our acreage across the play. So there's not a great deal of variability in the Point Pleasant itself. But this is a shale rock. The rock itself is very homogeneous across the play from what we see, but there can be differences in different phase window. Each phase window is a little different and also needs to be produced a little differently, and Stuart Maier is going to add some color here.

We don't really see a lot of variability in the rock quality. It's primarily the types of hydrocarbons that flow through the reservoir that dictate the variability.

Okay. Is the Rome trough, does that ring a bell when you think about the West Virginia Utica potential as a geologic feature that splits Ohio from West VA?

We look at all the geologic structural features as part of our analysis, sure.

So I've heard of that being expressed as something that can help the West Virginia side of things. Do you have a view as to that specifically?

No, not really. It could be beneficial or it could be detrimental, really. It could go either way.

Okay. And the final question for me, can you just discuss maybe the new hires, who they were in sort of the last 6 to 8 months? And how they were engaged in this process of reviewing wells and guidance?

Well, there's a whole army of folks. But at the helm, we've got Mark Malone, who's Vice President of Operations; Rob Jones, Vice President of Drilling. Ross Kirtley, our COO, has been with us almost a year now so. But below these guys -- and Lester Zitkus, our Vice President of Land; and then, of course, Ty Peck, our Director of Midstream, have all been hires within the last year, but there are probably a hundred folks below them that have also been added in the last year.

Our next question comes from Matt Portillo from Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a few quick questions from me. I was wondering if you could provide some context on, I guess, either the IP rate. So as you guys use pressure maintenance, how should we think about the change in the IP rate? Or maybe the initial kind of production over a period of time for this choked back wells? Just trying to get a sense of how much this could be impacting your production profile near term.

Well, keep in mind, our -- for instance, our wet gas type curves were showing that we were producing these wells at about 10 million a day. But I guess, Mark, do you want to respond to that going forward?

Yes, we'll probably produce those at a lesser rate than the published type curve right now. I mean, we've been looking at a number of things to decide what type of pressure. I wish it was easy as pressure rate. But you know that condensate wells, as an example, I mean, we look at a number of sensitivities to determine how to produce these wells. I mean, the ultimate goal, of course, is to manage these wells so that you remain -- keep pressure above dew point. There's a number of things that affect that. There's a number of sensitivities that we look at that include wellhead pressure, temperature, GOR, critical gas flow rate. I wish it's as easy as pressure, but it varies from phase to phase, and then there's a number of sensitivities that you have to examine. So...

The thought process is to find the optimal way to produce each well. Each well is going to be a little different. I think we will have probably some general guidelines in each phase. I don't think we know what that is yet exactly. And you're probably trying to model and trying to model IPs. So we'll have to all work on that together. But just keep in mind, the idea here is to either keep the area under the curve the same or maybe even expand the area under the curve. Ultimately, the shape of the curve may change a little bit. The decline may change a little bit. But we think we're going to see -- we hope to see improved EURs from this new program, but we're going to have to figure out exactly what the optimal way to produce these. We're just now beginning this process. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then I guess a follow-on question to that. In regards to kind of this year on the PDP side, as you guys have reviewed the data you have so far. Has your assumption around PDP declines changed at all in 2014? And has that led to some of the revision to your '14 production? And then, I guess, as we think about 2015, you brought down the production guidance this year with, I guess, in theory the view that you have more constrained rates, would that not suggest that the production profile for '15 maybe better as you have a flatter decline rate on these wells?

It certainly could. First of all, I'd say, we didn't have concerns over the PDP. What we're really just trying to do is finding that optimal way to produce each well. But you're right, the positive effect could be that we have less of a decline in 2015. But again, it's too early. We don't know that for sure. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And just 2 quick last questions for me. I was hoping that you could just -- I know that this has been brought up a number of times, but I was hoping that you can maybe provide a little bit more color. As you guys look at the wells that you've analyzed so far, what the effective propagated frac length is on these horizontal kind of completions? Obviously, you've highlighted that there's some water frac communication. But just trying to understand a little bit better what the effective frac length may actually be? And then, I guess, the last question for me. If you were to remove the infrastructure constraints or baked-in infrastructure delays in your guidance, what would your 2014 production look like? So if MarkWest was actually able to deliver on their promises, how would you guys think about your production growth this year?

I'll address the frac question first. I mean, we've got a project in place right now that we've talked about a great deal in the Darla. We're in the middle of that project at present. That's going to give us an opportunity to look at spacing from 320 to 1,200 foot. And one of the objectives of that project is to also examine effective frac length. So we're early in that. And hopefully for that project, we'll be able to better define what the effective frac length is.

And the second part of your question, the answer is, I don't know. I don't think it's probably appropriate for us to speculate on that. We're confident with the new guidance we put out. And I'm not sure what the answer is if we had -- we didn't feel like we had delays.

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

Could you maybe talk a little bit about your guidance relative to the assumed production per well, either per day or per month or something like that just so we can kind of bracket tie-ins and the associated flow rate per well.

So you're asking us -- I want to make sure I understand. You're asking us to tell you how to model flow rate per well?

Or what's in your guidance. If you're putting out a guidance number, you have to have some type of flow rate per well. Can you give us any color on that?

Well I'd really rather not get into specific modeling questions here. Again, keep in mind, we're going to bring on 14 to 21 wells. We've given you flat production for the second quarter and told you that there'd be a linear ramp up to 55,000 barrels a day by year end. David, it just feels like that's as specific as we need to get at this time.

I certainly understand. Maybe just talk a little bit about how you would carry backlog of wells waiting to be completed. Do you think once you get a certain backlog, that number stays constant? Or does it actually grow as you drill more wells? Or will you eventually close that? Just how are you thinking about managing that transition from drilling to completion?

This backlog is going to be progressing as the year goes out. I mean, it's not a magic number of wells. It's just simply having pads available for the rigs to go to or the crews that have to go to in conjunction. In other words, uninterrupted services so that we keep the crews busy. Again, we're thinking 3 to 4 pads, but once we get to that point, it's not going to be something that's ever building. We'll get to point, and we'll just keep up.

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

Just one question for me. So you mentioned 14 wells being taken offline from ongoing completion activity. And I'm just wondering, is that due to Gulfport completion activity or third-party completion activity?

No, that's all Gulfport completion activity.

Okay. So you have a handle on that going forward, and I assume do you have that incorporated into our guidance?

Yes, that something, Gordon, that we had been pretty public talking about. We knew that April and going into May, we were going to have some simultaneous operations going on. So as Mark alluded to earlier, that's something that really becomes minimal going forward because we are planning our activities away from adjacent pads as much as we can. So you won't see very much simultaneous operation issues going forward after we get through this.

Okay. And then do you foresee a point, given where industry is drilling -- the activity levels of industry, do you foresee a point where offset operators will be completing wells next year with your wells that you'll have to shut in or is that an issue at some point?

I think this will progress and the area becomes drill. I mean, you're going to see those effects. But the good news about the Utica is, I mean, it's different in a sense that we communicate with our offset operators on a frequent basis. We have technology exchanges. I mean, we're talking to them frequently. So being able to communicate with those guys and understand when they're going to frac relative to when we are. Again, we have good relationships with our peers and partners out there that we can minimize that effect.

And I think just to point out so that you keep in mind, there are state rules about staying away from lease lines. So every operator has to stay at least 500 feet away from the lease line, which puts it at least 1,000 feet away. So operators are going to work together on this if it becomes an issue. You're not certainly going to want to interfere with each other.

Our last final question comes from the line of Jeff Grampp from Northland Capital.

Just wanted to maybe talk about well cost and maybe if you guys can kind of give us some color on what recent costs have been coming in that, and then maybe give us a sense for where you think those could be trending given the decreases in the drill base you guys set recently and the efficiencies that you hope to be gaining that you've talked about lately?

I'll take a little bit of that, and then I'll also let Rob talk as well. We're still just talking about $9.5 million average well cost for the year. Obviously, starting out the year a little higher and then trending down as we get to the end of the year. So I still think $9.5 million is the right kind of average cost to use for this year. Now of course, on the east side of the play, those wells are a little deeper, so they're a little more expensive. And then as you go west, they're shallower and are less expensive. But I still think that's a good way to think about it. Then I'll let Rob talk about the trends down and his efficiencies out there.

Yes, this is Rob. On the drilling side, the first thing we've done in the first quarter is really put a focus on reducing days. If you reduce days, you reduce dollars. And we've done a pretty good job with the first quarter of starting to bring our well cost down just by reducing days. From there, we'll certainly try and eliminate the deficiencies we have in the drilling process. We've been working on upgrading our drilling equipment and with really working with the existing equipment we've had in enhancing those packages. Certainly, we've done a good job in the first quarter, and we'll continue to work on our deficiencies and our data collection process, and then we'll focus on our new metrics.

Okay. And then last one for me, I know you guys have kind of talked about it, about providing the market with a dry gas type curve. Is there any update there or any kind of timing that you can provide us with of when you think we could see one of those for your dry gas type curve?

Yes, that's a good question. We had certainly talked about putting out a dry gas type curve this year. And we still intend to do that, but I think it will be later this year. Under our new regime, our new management, including myself, certainly, we want to be thoughtful about making sure that we have enough data when we put out type curves. We put the first type curves in the other 2 windows earlier, but we just want to make sure we have a bigger data set when we put out the first dry gas type curve. So it will be later this year.

Sir, that concludes our allotted time. Please proceed with any closing remarks.

Thank you, operator. I believe that concludes this morning's call. 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. This concludes our call.

Ladies and gentlemen, thank you for attending today's program. You may all disconnect, and everyone have a wonderful day.