Gulfport Energy Corporation (GPOR) Q2 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Gulfport Energy Corporation Q2 2013 Earnings Conference Call. [Operator Instructions] As a reminder, today's conference call is being recorded. I would now like to pass the conference call, Mr. Paul Heerwagen, you may begin, sir.

Thank you, Kevin, and good morning. Welcome to Gulfport Energy Corporation's second quarter 2013 earnings conference call. I'm Paul Heerwagen, Director of Investor Relations, and with me today are Jim Palm, Chief Executive Officer; Mike Moore, Chief Financial Officer; Stuart Maier, Vice President, Geosciences, Steve Little, Vice President of Midstream Operations. During this conference call, the participants may make certain forward-looking statements regarding the company's financial conditions, results of operations, plans, objectives, future performance and business. We caution you that all actual results can 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 on 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 GAAP measures will be posted to our website. An updated Gulfport presentation was posted yesterday afternoon to our website in conjunction with the earnings announcement. Please review at your leisure. At this time, I'd like turn the call over to Mike Moore.

Thanks, Paul, and good morning to each of you. During the second quarter of 2013, Gulfport generated approximately $101.3 million of EBITDA, $43.9 million of operating cash flow and $43.8 million of net income. Per share on the IPO. Closed the market Monday at per share. The stock has increased 146% in value per share and following their recent announcement of 2 acquisitions, Diamondback continues to add value and accretive investment to the Gulfport shareholders. During the second quarter, production totaled 815,300 barrels of oil equivalent or 8,959 BOEs per day, which is up 3% on a unit basis quarter-over-quarter, compared to the first quarter of 2013. Allocated life field set for production turns out to be 3,524 BOEs per day from the Utica, 3,268 BOEs per day from West Cote; 2,019 BOEs per day from Hackberry and 148 BOEs per day for Niobrara, and other miscellaneous areas. Our production mix for the second quarter was 71% oil and natural gas liquids; and 29%, natural gas. Subsequent to the second quarter, July production averaged approximately 12,548 BOEs per day. Moving along to the income statement. Revenues for oil, natural gas and natural gas liquids in the second quarter totaled $70.2 million. Average realized prices for the quarter were $113.98 per barrel of oil or $80 per MCF of natural gas and $54.23 per barrel of natural gas liquids. Our price for the second quarter was $86.10 per barrel of oil equivalent. Our average realized price per barrel of oil was impacted by the mess that which we account for hedges. Gulfport accounts for hedge by the cash flow treatment which was chosen at the acceptance of the hedge to reduced volatility quarter-to-quarter. This quarter, the hedge impact resulted in additional $5.5 million of oil revenue. Without this hedge impact, average realized prices would have been $104.70 per barrel of oil and $79.60 per barrel of oil equivalent for the quarter. Lease operating expenses during the second quarter were $5.9 million or $7.21 BOE, down 20% sequentially on a unit basis from the first quarter of 2013. General and administrative expenses for the second quarter was $4.9 million or $6.01 BOE, down 22% sequentially on a unit basis for the first quarter of 2013. Depreciation, depletion and amortization expenses during the second quarter totaled $28.5 million or $35.1 per BOE, down 11% sequentially on a unit basis from the first quarter 2013. In terms of capital expenditures, during the second quarter, we spent a total of $74.1 million on 2013 activities, which excludes Gulfport's portion of Grizzly activity and Utica leases. Moving onto the balance sheet. Into the second quarter, we had approximately $214 million in cash and were undrawn on our revolving credit facility. At present, we have fixed price swaps for 5,000 barrels per day of oil for the remainder of 2013 at a weighted average price of $99.86, and 10 million cubic feet of gas per day for October to December this year at a weighted average price of $4. In addition, Gulfport has been solidifying its hedging program for the coming years. Likely, fixed price cost for January 2014 to December 2014 of 2,000 barrels of oil per day at a weighted average price of $101.65. Additionally, Gulfport has fixed price swaps for January 2014 through December 2014 of 50 million cubic feet of gas per day at a weighted average price of $4.01, and January '15 through March of 2016 of $2 million cubic feet per day at a weighted average price of $4. We have financial hedges to secure our cash flow obligations and recently signed firm agreements to transfer our product which Steve Little, our Vice President of Midstream Operations, will address later in the call. Due to the challenges we experienced today, we have restructured our growing plans in 2013. We are utilizing the benefit pad drilling by revisiting our 2012 producing locations, as well as drilling 2 to 3 wells while on location before moving the rig. As a result of the growing pad wells, the increase in spud sales timing has negatively affected our near term production. Downtime has also been experienced when we are drilling new wells on a location which are producing well. Producing wells must shut in during rig treatment on and off location and during simultaneous completion operation associated with completing new wells. On-average, each pad location experiences at least 3 to 4 days of shutting in production due to rig movement and at least 5 to 7 days during the fracturing of 1 well and remember, in most cases, we are drilling 2 to 3 wells at a time. The downward revision is due to operational factors and I would like to stress that the changes are in no way signaling a degradation in well performance. Our 2013 guidance is changing but the production is shifting and we recognize in 2014. We currently estimate our 2013 full year production to be in the range of 5 million to 6 million barrels of oil equivalent and production in the third quarter of 2013 to be in the range of 14,000 to 15,000 BOEs per day. Based on the current hook-up schedule, we plan to hook up 4 to 6 during the third quarter and 25 to 30 wells during the fourth quarter. Due to the majority of 2013 wells coming online in the fourth quarter, we currently estimate a rate of 37,000 to 50,000 BOEs per day going into 2014. We estimate full year LOE to be in the range of $6 to $7 per BOE; full year unit G&A to be in the range of $2.50 to $3.50 per BOE and we estimate our DD&A to be in the range of $30 to $33 per BOE. Thank you for time and interest today. Now I'd like to turn the call over to Jim to cover our operational highlights.

Thanks, Mike, and thank you, all, for joining us for our call. In the Utica, during the second quarter, we spud 16 wells and worked aggressively towards completing our wells. We started the quarter with 3 drilling rigs and today, we have 7 rigs under contract. In the first quarter, we had 3 wells producing at an average 801 BOEs per day, exiting the first quarter at 1,163 BOEs per day. And in the second quarter, we brought on 10 additional wells and had an average production of 3,524 BOEs per day, exiting the quarter at 6,993 BOE per day. We continue to execute on our 213 -- 2013 program and with our acceleration of rig count in play, are working diligently to execute our program. In the past 2 years, we've learned a lot about this Utica geologically. Overall, the general character of the play has not changed, but as we learn more about the reservoir, a more accurate depiction of the extent of each split type across our acreage position emerges. Referring to the map in our presentation posted at the website yesterday, we divided an play into 4 carbon phases: oil, condensate, wet gas and high gas. These 4 simplified generally accepted split type regions correspond to observed, well results. In reality, there are no precise hard lines of distinction between the phased areas, but are more variable phase transition across the area. The heavier hydrocarbon fraction sprayed the lighter hydrocarbon fractions from west to east as temperature and pressure increased with debt. Phase differentiation is an important vehicle in designing optimum completion of production procedures to maximize recoveries. Using the new price windows, we now estimate that 8% of our acreage is NOL; 27% in condensate; 22% in wet gas and 43% in the dry gas phase of the play. As we bring more wells online and see sustained production, we're developing a better understanding about how optimally flow the wells in each spud phase to maximize the returns and ultimate recoveries. In the wet gas phase of the play, Gulfport has brought on 5 wells today. It's still early for some of these wells, but production history shows that these wells are producing better than our forecast type curve. The wells have produced at an average per day rate of 2,427 BOEs per day, and average 60-day rate of 3,322 BOE per day and an average 90-day rate of 3,289 BOE per day. Remember, this is the actual production to sales from these wells, and I'd like to highlight the sustained level of production is validating our business thoughts that the wells in this phase of the play will experience little to no decline during the first months of production. While it's still very early in the process, based on our estimated type curves of 4 million to 3.1 million BOE in today's pricing and assume -- and assuming a normalized well cost, we estimate the wells in the wet gas phase of the play to have a payback of 5 to 7 months. In the condensate phase of the play, Gulfport has brought on 9 wells today. The wells have produced at an average 30-day rate of 1,275 BOEs per day and average 60-day rate of 1,053 BOEs per day and an average 90-day rate of 912 BOEs per day. This is below our initial-type curve, but these are very good wells. We are changing our frac design and managing flow in pressures, both steps that have the potential to lead to better recoveries. Again, still very early, but based on our estimated type curves of 1.5 million to 1 million BOEs, at the strip pricing and assuming a normalized well cost, we estimate wells in the condensate phase of the play to be have an average payback of 8 to 22 months. In the dry gas phase of the play, Gulfport has brought on 1 well to-date, that's 1 well. The well produced at an average 7-day rate of 3,351 BOEs per day and an average 30-day rate of 3,105 BOEs per day. Today, the well is producing at 2,895 BOE per day, with a flowing pressure of 2,902 psi. In 45 days, this well has produced over 0.6 Bcf. While we have not release a type curve in the dry gas phase of the play, this well suggests that this gas phase will have quality economics and strong production results. We're not holding any wells in the oil phase of the play. We estimated that approximately 8% of our acreage is located. But our drilling well, right on the edge of the condensate and the oil phase of the play is expected to be online in September and will provide us more information on the Western side of the play. At the time of our last call, we had 2 wells producing on the Boy Scout fab. We recently added 2 more producers of Boy Scout 2-33H and Boy Scout 4-33H. The Boy Scout 2-33H produced at an average 7-day sales rate of 747 barrels of oil and 2.1 million cubic feet of gas with a flowing tubing pressure of 1,505 psi. The Boy Scout 4-33H produced at an average 7-day rate of 519 barrels of oil and 2 million cubic feet of gas per day with flowing tubing pressure of 1,398 psi. We are testing the gap or spacing with the new wells. The Boy Scout 2-33H is 800 feet from the 1-33H going to the north, and the Boy Scout 4-33H is 600 feet from the 5-33H going to the south. As it's coming on a resource play, we saw frac spudder in the original producing wells on the pad when we frac-ed new offsets. However, the producers soon unloaded the frac pattern and returned to previous production levels. Although we saw an indication of frac spudder, the wells do not appear to be in communication with 1 another they produced. While it's still very early, the new wells are producing to our expectations and we believe the pricing regime in the play is likely to be less than the current statutory 1,000 foot pricing. On the wet gas side of the play, the first well of our Darla project is spud next week. What we learned from the Darla wells will be critical in this process. We believe that determining the spacing regime earlier in the play is imperative to helping us optimize the development of our acreage and maximize returns. We are currently drilling wells in the range of $9 million to $10 million. However, we became more efficient at drilling and completing our wells and laid the cost of spending downward. We anticipate another 10% decrease as a favorable by early next year, and I'd like to take a moment to share a few of the areas where Gulfport has began to experience significant benefits. Let's start with pad drilling. As Mike mentioned earlier this year, we altered our 2013 drilling plan to allow for increased pad drilling. Due to the nature of the photography we have in Ohio, the cost of construction at the pad can be up to $1 million per location, and production facilities, together with the pad, cost $2.25 million. However, subsequent wells can be added for about $400,000 per well, which is a significantly lower number and a significant cost savings. Second, Gulfport has change the way we're competing our wells by revising the chemistry and design of our fracs. Gulfport continues to complete wells with approximately 550,000 pounds of sand per stage. We recently altered our frac recipe and are moving to a slick water frac and eliminating the use of gels. This can reduce pumping charge on the completion by 20% per stage. For a 6,500-foot lateral with 26 frac stages and the potential savings is approximately $650,000 per well. Not only should we experience cost savings, the use of slick water should enhance the productivity of the wells by eliminating the drill residue in the formation. Third, Gulfport has been successfully revising our stream designed on the majority of wells, and we believe we'll be able to eliminate the intermediate phasing stream. This allows us to downsize the hole, save many on tubular, eliminate the extra cement job and save a considerable amount of rig time on location. On the wells where we can successfully apply this technique, we expect to see a cost-saving of approximately $450,000 to $550,000 per well. Fourth, we are now utilizing a rotary spudder [ph] tool when drilling the horizontal sectors of the wells. We ran a cost-benefit analysis and determined cost savings are recognizable and also believe there is an intangible benefit realized on all laterals by eliminating touracity [ph] and staying closer to our target zone. In addition, we've been successful at reducing our drilling times which results in us being able to bring wells online sooner. We estimate today, on an 8,000-foot lateral, using rotary can result in $100,000 to $200,000 in savings versus drilling with conventional tools. And finally, we are operationally hedging our activities, securing availability of quality and cost-effective service through vertical integration. This is particularly important in a rapidly emerging play like the Utica, where we want to ensure Gulfport's access to top-tier equipment and crews while also mitigating the potential price gouging and supply shortfalls. In addition, the profits from our proportion of the ownership in the very integration companies. In the Utica, we continue to lead an active leasing program that surround our core position. Underground leasing has begun becoming more competitive that we continue to seek both bolt-on acreage to solidify our current position and also new acreage. We announced in our operations update on July 23 that we added 8,000 gross, 7,600 net acres, bringing our total acreage position to approximately 145,000 gross and 136,000 net acres under lease in the play. We focused our efforts on delineating our position and we now feel the vast majority of our acreage has been de-risk. First, an important factor in the development for the Utica is midstream infrastructure, so I will now turn the call over to Steve Little, Vice President of Midstream Operations who can provide some details and updates of current activity on the midstream front.

Thanks, Jim, and good morning. Yesterday afternoon, we announced the execution of 10-year farm transportation agreements on both Dominion East Ohio, DEO and Dominion Transmission, DTI, for up to 100,000 decatherms of residue gas originating at MarkWest gas processing facility for delivery to our ANR Pipeline at Lebanon, Ohio. The DTI's interconnection with the DEO at Harlan Springs Ohio. This will provide all 4 with critical residue takeaway capacity and allow us to move gas west to the Midwest marked in Wisconsin, Illinois, Indiana and Michigan. In addition, the new agreements will allow Gulfport access to an additional 160,000 decatherms a day of farm transportation in 2014 for delivering to Texas Eastern and Rockies Express in Ohio, and DTI in Ohio. With this announcement, Gulfport becomes the first and only firm residue gas transportation shipper of DEO, in company with the firm transportation on DTI, becomes the first unit producer to diversify its market beyond DTI's sell point pricing index. Furthermore, the ability of the Cadiz processing facility to deliver residue gas at or below 1,100 BTU per standard cubic feet even at ethane rejection mode ensures the Gulfport will continue to flow even if other regional downstream pipeline outlets are unable to accept higher ethane. Although we believe that we do have some headroom with respect to ethane and residue, classifications given DEO ability to blend gas and the higher NGL recoveries we're achieving at MarkWest Cadiz plant. We are working to finalize commercial arrangements for short- and long-term ethane sales. Currently, we're reviewing brief proposals for the disposition of ethane and have been very pleased with the pricing settlement structures that we've been presented. Our intent is to finalize contracts with 1 or more consumers within the next 60 days. MarkWest is marketing our purity [ph] propane, butane and natural gasoline. Their 20-year history of NGL marketing in the Northeast gives them deep insight into the markets. MarkWest has been exporting propane for more than a year from the Northeast and the only midstream company in the Northeast with storage capacity at enterprises facility on the depth of pipeline. They also have significant truck and rail markets as wells as around NGL barrels in the Northeast, so marketing NGLs is critical to their success as well. We remain confident that MarkWest will continue to maximize value of both propane. Normal butane will continue to experience high demand in the winter and much lower demand in the summer. We expect that light propane, MarkWest will begin to execute propane in the next several years. This will keep the basin in balance and also for butane prices. All of our iso-butane is marketed to Midwest and Mid-Atlantic refiners. It's due to their acclimation unit and most of the natural gas gasoline is being transported to Western Canada markets by rail. We expect to continue to receive good netbacks for iso-butane and natural gasoline. Regarding condensate, I'll give a brief update about MarkWest condensate infrastructure in the downstream markets. We are pleased with how the development of the condensate stabilization storage internal facilities is progressing. MarkWest facilities, one has the ability to receive, upgrade and load out 24,000 barrels per day of stabilized condensate by the second quarter of 2014. The facilities will be very expandable in the next phase of the expansion while increase facility's capacity to 54,000 barrels per day. The timing of the expansion will be dependent on condensate production. Initial storage will be 100,000 barrels by the second quarter 2014 increasing to 200,000 barrels in the second half of 2014. In addition, raw facilities will be in service by the second quarter 2014 with an additional capacity of 50,000 barrels per day. Gulfport will have enough capacity in these facilities to ensure reliable flow. As a result of upgrading logistical possibilities and market optionality, we'll be positioned to maximize the value our at condensate at wellhead. We've recently completed a robust proposal for condensate sales in a joint effort with another Utica producer. We received significant interest from regional refineries accessible by truck and rail for finance with barging facilities in the Canadian markets. We're in the initial phase of commercial negotiations with counter-parties. At this early stage, we're very pleased with the pricing discovery and volume requested by the end markets. There have been a lot of questions regarding the processing capacity, so I'd like to address our current situation. MarkWest has a contractual litigation to build processing capacity above Gulfport's existing and projected volumes. Currently, there's 185 a day of processing capacity gas which still has substantial unused capacity. MarkWest has already announced, they will bring on an additional 200 million a day of cryogenic processing at Seneca in October of this year and an additional 200 million a day by the end of the year. This expansion will be followed by another 200 million a day with another 200 million at Seneca for just under 1 Bcf of processing by mid-2014. From a long-term perspective, there's enough capacity to meet various demand and enough lead time if we need to expand further. To conclude, you can see that we've worked very hard to ensure that we the best decisions in gathering to processing, transporting and selling our product in the basin. I'll now turn the call back over to Jim to discuss our current operations.

Thanks, Steve. Gulfport is very proud of the announced agreements with Dominion. It's a delicate balance between flow assurance and value preservation, and I believe Steve and our team have done a great job of achieving both. And now, let's move to our other asset areas starting with Canada. Grizzly currently expects first steam in the coming months and first production in the fourth quarter at its first SAGD facility at Algar Lake. Following the winter drilling season, sufficient resources has been identified at May River to justify an initial 12,000-barrel per day development. This application should be filed by the end of 2013. Now on the Southern Louisiana. At Hackberry, during the second quarter, we drilled a total of 4 wells, completing 2 wells as productive, with 2 wells drilling at the end of the quarter. In addition, we performed 19 recompletions. We are currently running 1 rig at Hackberry, drilling ahead on the 11th well of 2013. Meanwhile, on West Cote Blanche Bay during the second quarter, we drilled a total of 5 wells, completing 3 as producers with 1 well down in and 1 well drilling at the end of the quarter. In addition, we performed 21 recompletions. At present, the rig is active at West Cote and is drilling ahead and 11th well of our 2013 program. To wrap things up today, we're pleased with our operations, the growth and progress we're making on a number fronts. In the Utica, we are working aggressively toward executing our 2013 drilling program and gaining efficiencies a little bit and operationally along the way. We've only begun to get a glimpse of the upside as our technical and operations team continue to accelerate their understanding of the reservoir and deliver results. Our confidence in the Utica is evidenced by the addition of aggregate [ph] we continue to add to our position. We're in execution mode and we believe the impact of our 2014 cash flow will be significant. I thank you again for joining us for our call today and we look forward to answering your questions.

Operator, please open up the phone line for question-and-answer.

[Operator Instructions] Our first question comes from Neal Dingmann with SunTrust.

First question, and it could probably for Mike. Mike, just wondering on you, that's Slide 14 where it does show the plan hook-ups. I guess, is it safe to assume that the exit guidance would be about the same, assuming that those number of wells, as you're kind of hooked up as that schedule indicates on that Slide 14? And then, wondering if I guess maybe kind of second part of that for you, or Steve, if any of the infrastructure would come into play? .

It's a good question, Neal. So the answer to your question is, yes, those wells should be hooked up in the third and fourth quarter. And what's going to happen really -- the good news is, for this production shift, from the third and fourth quarter, is we're still going to have a really good exit rate. In fact, the exit rate is very similar to where we were before. So we talked about an exit rate of 37,000 to 42,000 BOEs per day, which puts us in a really nice position going into next year. So again, really, this production guidance going down. The good news is, we still in depth with the same exit rate. And we don't anticipate currently -- and I'll let Steve jump here too -- but we don't anticipate currently any delays related to infrastructure takeaway. But I'll let Steve comment on that.

I'll just say that the vast majority of the truckline, the main truckline are now in service. And we got -- plans, our drilling schedule kind of interchange with the midstream buildout. So we're not anticipating any near-term light associated with the midstream buildout.

And then the follow-up, Steve, where you got -- just as far, just sort of can you comment on ethane rejection, sort of the end market realization is kind of what you're seeing. We've seen some others with some peers with some pretty low realization. I'm just wondering what kind of markets you're going to and how you're accounting for that currently.

Yes. The rally of the evolution of the ethane market has really benefited us in terms of where the pricing points and pricing elements that were being initially offered by Naba [ph] with. I've been very pleased with the amount of options that are available. The 3 commercial deals that we have right now are international option. The other one is domestic kind of near the play. The other one our domestic but Apex-related. And I think that where we are right now, with the desire for the ethylene crackers, I think we're in a real good position to see a higher net target related to ethane.

All right. Then just the last question, if I could. Last question, just I think, would be for Jim. Jim, you mentioned about the wells have been on. I wonder if you could comment about just how the pressure or the restriction looks on that? And then secondly, which of those -- are all those are on artificial lift?

Well, Neal, we have essentially nothing on artificial lift right now. We just -- we did but just recently on our original Boy Scout wells, we've put some gas lift on there. But we've seen that the whole play is really strong. For instance, on the left side, even though it's shallower, we have lower pressures and more liquids in the East side, the condensate wells are always more difficult and more challenging to produce than the gas wells. But they are more valuable and they're really hanging in there and good shape. Everything that's ever been completed on the West side is still flowing. We do have plans the for the future to start going into the secondary recovery-type with gas lifts. The wells are equipped with gas lifts. We've got some plans, pumps down the hole. But right now, we're in the process of determining best practices. But we have to use our value on both the East and West side and we're really pleased with the way things are coming.

Our next question comes from Ron Mills of Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Jim and Mike. Just a follow-on from Neal's prior question on the gas lift, especially as it relates to condensate type curve that you put in your updated presentation. What are the assumptions on that type curve in terms of putting on gas lift and on the 2 Boy Scout wells that it sounds like you've recently placed on gas lift? Have you seen any early response? Just trying to gauge that.

Well, when we got original type curves for the Boy Scout and Wagner. We have anticipated actually that in a month and half, the Boy Scout well would die. And here, we're on back in December and it's still flowing. And so we've just recently put the gas lift on there, so we haven't had chance to actually find out if that's going to improve things. But remember, we have a lot of wells to test. We've only got 9 producing, though. So and they're going to be different. So any we need a little time to get the compressors in and start using the gas lift on the other wells. Some wells will probably respond, some won't. It's just too early to tell, but we're going to look at all the different alternatives we've got to increase the production. But I'll tell you, I don't know that I've seen that, very many place like this one where the wells are so strong where they can actually -- these wells are probably blow up the casing as they blow up the tubing. To new wells, we put on of the Boy Scout are very strong. They're very strong, very comparable to that first Boy Scout well. It seems like we're choking them back. We're producing -- we're originally on the Boy Scout well. We started out $4 million to $5 million a day. Potentially, it moves us back to about $2 million a day. We think conserving that gas is going to result in better long-term production on the wells. And so these are some of the practices that we're trying to develop right now to make those years and make fast recoveries.

It I think it's important to note, Ron, the play is really developed exactly like we expected. We always knew that the Western side of the play would probably operationally be different than the East side of the play. So as Jim mentioned, we're certainly still learning, but if you refer to the type curves that we put out this morning, and you look at -- first of all, let's just go to the west side of the play, the condensate type curve, although we didn't put it on the slide, the IRRs here are real, very strong, and we're assuming that a well cost of, I think, $9.5 million and strip pricing. But with the assumptions and with the production that we're seeing right now, and as you saw, we gave you 30, 60, 90 day rate, and we plotted it on the type curves for the 9 wells we had producing, although all of those wells have not been producing 90 days. But we're still seeing IRRs of 55, 277%. Those are really strong wells. Those are nice wells, and so again, we're still learning how to produce and operate on this side of the play, but still very pleased with everything we're seeing. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And if you look at that, how does that compare with the returns in the wet gas area?

Well, that said, good question and they are very different. The east side of the play, the gassier side of the play is certainly very, very strong. And with those same assumptions that we use over there, with the updated EURs of 3.1 million to 3.9 million barrels, those wells pay back in 5 to 7 months, and we're looking at IRRs. It's hard to say, but 550% to 1,250%. So these are incredible IRRs over on that side of the play, not to say that the wet side of the play doesn't also have good IRRs, but with the pressures out east, those are very nice wells. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay, good. And then in terms of the acreage breakdown, you now have -- you've broken it into 4 distinct areas. It sounds like a lot is now in what you now in your new presentation show is as dry gas and wet gas, plus or minus 70% of your acreage at least. What's your expected drilling schedule in terms of each of the distinct areas, and I guess I'm trying to get to a point of the timing of the potential dry gas type curve as well. I was assuming you're going to ramp activity in the area since it seemingly is approaching half of your acreage.

Ron, we started out the year with most of our rigs over on the west side, and now we're drilling with most of the rigs over on the east side, and we're trying some different frac techniques and so forth, and as we said, production practices that we bring these wells on. So right now, most of what we're doing is concentrated on the East side where it's wet gas. And as we've seen, the returns are really good over there, so that's probably a good place to be. But one thing we have found, when you look at that specimen well and 6/10 of a Bcf and about 45 days, that's telling you how strong the returns are over there. Now that's just barely into the gas side of things. And as you probably know, we had the Irons well. It's considerably east of that. It's probably about 6 or 7 miles from the river on the east side of Ohio, and we haven't put anything out for that because we're going to give you the production numbers when they come in. Dominion's late in the line now, but it's supposed to be producing by end of this month. But we think it's going to be even stronger based on -- it's going to be even stronger, we think, than the specimen well. We have to see when we they get it online, but with the test [ph] results like they are, with that well being deeper, pressures being higher, and so forth, we think the gas part of the play is going to be really good. And that's not just based on what we're seeing on our wells, but also what we hear from some of our other players in the play that has announced some really strong numbers, but we can't validate all of them but it sounds like there's some really huge results over on the east side.

For the rest of these year, Ron, we will be drilling on both sides of the play. And then next year, we'll start talking about at some point, probably on our third quarter call, we haven't quite finished that program yet, but certainly this year, we'll be drilling on both sides. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then the pace of completions, the 18 to 20 in December, really, the 25 to 30 in the fourth quarter, is that driven by the timing of Seneca or is it just the way the calendars work in working on pads? And trying just to make -- get the sense of the level of confidence in that new completion schedule and that's it.

That's a good question, Ron. Really has nothing to do with Seneca at all. It's all about the timing of the pad drilling and how it's worked out with those wells being drilled, frac-ed and completed, pressed and completed.

If you take a look, we've just recently added 3 rigs in the last month or 2. So if you look at those 3 rigs and say that the average starting drilling in June, you finish -- you're going to drill 3 wells, July, August, September, get frac-ed in early October, you're going to rest for a month or 2, put the wells on in December, that's where those are coming from. These new rigs that we've added recently and generally drilling 3 wells on a pad. There's just that much time involved in getting them on.

Our next question comes from Biju Perincheril with Jefferies.

Going back to the well hook up schedules, taking you 20 wells in December, can you talk about how many of those are going to be on existing well pads? And then talk also about maybe how you risk it and kind of what delay is presumed in that number?

It's a little hard to hear you, but I think I got the gist of the question. You're wondering how many of them are existing well pads?

Yes. I was wondering how many of the 18 to 20 hookups are on pads that are already producing? And then also, what kind of risking you have done in those numbers for potential weather delays or any other infrastructure related delays there.

Well, most of them are, if not same pad, they're very close. For instance, 3 of those wells are the Darla wells, are scheduled to come on in December. And the Darla is -- well, let's see, it's not a stone’s throw. You got to have a driver out there to get to the pad, but it's pretty -- it's just a little west to the north of the Wagner pad, goes into the same lines that the Wagner goes into. So we don't really see that there's a lot of risk to get that hooked up as the gas pipeline already goes right by us. Some of the others that we're moving to are in proximity to the shooter, so real close to those. So it may not be another well in the same pad, but it's ones that are very close where the infrastructure is already in place. So we don't feel like there's a lot of challenge to get them hooked up even if they are a new pad.

And then can you talk about any sort of weather delays that assumed in that number?

Well, Mike's got -- I think he's got some. He's kind of going to speak to, but they're pretty conservative.

Between now and the end of the year, I don't -- I wouldn't anticipate many weather delays, but where I do risk it is in the way I model the actual production and the way I declined a production. So there's still quite a bit of risking in there without putting in specific weather delays.

Okay, got it. And then on the recent Boy Scout wells, I guess, from -- how are you thinking about specifically getting in 2014 and beyond in spacing in the play? And what additional data or how long of a production history you need before you're moving into tighter spacing?

Well, we're trying to get as much comparison as we can. We just put the 2 new wells on. We do have sort of each well, the North well is the 1. South well is the 5. We have a production history on those wells so we have that to compare to. So we'll compare how these other wells produce. We'll look for signs that are better or worse than the first ones, see if they see interference along way sometime. But it's going to take -- I mean, I would think 3 or 4 months worth of production history to be able to say it looks like that we're not having interference. Initial results are we're not having interference though. We've had one well went on, on about 24th last month, one about 28th. And for instance, offsetting the 1 well, we have the 2 and because we have finished it back to $2 million a day, it's producing in the 700-barrel a day range of oil. I feel confident if we were to open that up today to 5 million like we produced on that, it would be up to 1,000 barrels a day right there. So it's showing every evidence of being just as a strong as the offset well, even though it's 800 feet away. And like we said, we did see communication during the frac, but we apparently didn't see any standout there or anything because they seem to be producing independently. So this is just more data. We've got to find an 800 and a 600. The answer is going to be different on the east side where it's gassier. So we still got a lot of things to learn, but the Darla wells will be real good. But like I said, those start producing in December. So it will take us a few months to see how they produce before we know what's going on. So it wouldn't come overnight.

And so what are the next sort of pilots after the Darla wells -- or done spacing testing?

We're really -- I think we're getting pretty close to the end of drilling wells for science. So those costs are going to be behind us. We are moving now. We feel like in the execution mode and working on really bringing the costs down. So I won't say we're never doing anymore science, but we think a lot of that is behind us.

Okay. And then one last question for me. Can you talk about -- I know you didn't give any 2014 guidance, but just different way of thinking about activity level of -- with 7 rigs, how many wells you could drill there in Utica next year? And again, how many of those will be sort of step-out wells versus developing existing producing pads?

Yes, we will be drilling more single step-out wells next year. I'm sure MarkWest already has our drilling rigs scheduled for the next -- this year then the following 2 years. So they know where we're headed. So we will be doing that, but right now, obviously, we got 7 rigs going. You can drill a lot of wells with 7 rigs, but we haven't really developed our plans for next year, and we phoned out the numbers 70 wells next year. I would think in terms of that, by the time we have our next call, we'll be giving you a number for next year. I think that 70 is probably on the low side of some range that we gave you, but we haven't got those numbers yet. So for now, it's still 70 wells next year.

Okay. Is it fair to assume that you'll keep those 7 rigs active next year?

Well, I think that it's likely that we'll have that many rigs around next year, maybe more, but we don't -- just don't have our program developed yet.

Our next question comes from Ipsit Mohanty with Canaccord.

A quick question on the condensate type of -- your daily average hasn't reflected the curve yet so just a quick -- just to think what gives you the confidence behind the type curve and...

Well, for instance, we just put on these 2 new wells on Boy Scout, and I think after 90 days, they're going to be performing above the current type curve yield. Some of these wells, we've got very few wells that have been on for 3 or 4 months. We've put a bunch -- we've put some wells. On out of the 9, most of them went on into April and May. So we have a pretty short history, but with the practices we've got now, I think as we finished these wells back, try some different things, when we get to 120 and 150 days from today, those will be higher results. That type curve, as far as actual production, will be pulled back up again, and I think you'll see it come back up to the lower type curve and exceed it as we get more wells on and learn how to produce him.

I think you got to remember that we -- these wells, some of these wells started above the type curve, and again, we talked about still learning operationally what to do out here. But we were just trying to give you guys the most up-to-date data we can plotted against the type curves, but I think you got to remember that a lot of these wells haven't been on very long yet. So I don't think we need to read anything into the type curve at this point. It's way too early, and we're still very happy with what we see out here.

We're just in the initial stages, but like we said, we got gas lift available to us. We're looking at submersible pumps, and being able to separate the gas with gas separators downhole, and producing the hole up with the submersible pump. When you think about 8,000-foot horizontal and you think about that barrel of oil at the tip -- at the toe of an 8,000-foot lateral, what we need to do is figure out how to get more energy to that barrel to get it to move back to the heel so we can lift it. So that's what we're working on now, and there's a lot of oil that's sitting down there, I think. It just needs a little more oomph to get it out of the hole.

Okay. And I know it's early days, you've just executed the transportation agreements over to Dominion, but if you could talk about any thought behind what the long-term impact is going to be when you ship the dry gas and the wet [ph] through those pipelines to the West?

Yes, I tell you that -- obviously, we have the ability to flow gas there. So we've actually preserved the ability to sell it, the Dominion south point as we pointed to. What you see currently happening is Dominion south point helping relative to perk in what you've see historically with the markets that we now have available to us that they've penetrated a large premium deferred. So now we have a clear path to achieve those near-term premium, but our working efforts focus on flow assurance, price diversity and price. And both of those -- all 3 of those seem to be -- have been achieved from this marketing agreement. So long term, we will focus on flow assurance and price diversity, and this is going to give us some near-term premiums. I think that what's being offered out there from the farm transportation offers for the next, call it, tranche of volumes that we have out there are availing additional markets for us that are trading at a premium, the Dominion south point. South point has been negative $0.60. We recently -- relative to FERC and net of transportation in Michigan, which will have the ability to move that market, has been trading at $0.02 premium relative to NYMEX net $0.02 premium minus all the transportation cost to get there. So the net of this, the net on a data current basis is huge with these recent agreements. So we're very pleased with how that all turned out.

Our next question comes from Jason Wangler with Wunderlich Securities.

Just curious on the acreage you were able to pick up, is there any way you can kind of give us lease indications of what side of the play it was, and then also just kind of the timing of when that was happening? Was there -- was it a bunch of small deals throughout second quarter and even in the third? Or was it a couple of transactions that happened more of the other?

Jason, generally, the acreage that we're picking up is like Western side of Belmont County, Northern Monroe, that type of thing. It fits real well with the acreage that we've already got. We managed to -- we picked up too little pieces, but we picked up some significant chunks. It's getting harder to find chunks with 1,000 behind it, but most of that increase that we reported was a deal that we did, and we have other deals that we're still pursuing. It's getting tougher to put them together. The prices aren't any cheaper, but still, we are finding the acreage out there, and we will be reporting more acquisitions as time goes on.

Our next question comes from Brian Velie with Capital One.

Most of my questions have been answered. I did have a couple of clarifying questions. The 906 wells -- well locations that you cite in the presentation, those are all -- that number is based on 1,000-foot spacing, is that correct?

That's correct.

Okay. And then just repeat of Ron's question from a moment ago, I'm not sure I got the numbers down right. Mike, you said that the 55% to 277% IRRs, that was for the condensate window?

That's correct, Brian.

And then the other number's 550 to 1,200 was wet gas?

That's correct.

Okay. And then nothing yet from dry gas at this point or oil that will come as you step out in '14?

That's right, nothing yet on the dry gas or the oil side yet.

Our next question comes from Tim Rezvan with Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Had a quick one. I wanted to follow-up on the dry gas result that you've talked about, this 1 well, the Stutzman. It's been online. You talked about from the 7 to 30 to current rates, we're seeing some production decline and that kind of differs from some of the commentary you've provided on wells like the Wagner where you expect gas to hold in for 12 to 18 months. Can you talk to kind of why we're seeing that variability?

Well, on the Stutzman, we haven't really seen any variability so far. We've been holding it constant. It's typically about 17 million a day, that kind of number. It's been flat. It could do more. We opened it up. We -- you always try to find where a well's comfortable, and that's where it is. You can see the pressures are almost 3,000 pounds flowing pressure today with that kind of a rate. So it is a lot. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. I just -- because that's deteriorating, 10%, 15% from the 7-day rate. That's the only reason why I asked so...

All. No, it's actually -- we're actually probably producing stronger. I'm not sure why the numbers suggest that, because basically, it's been -- it didn't take us long to get it up to that rate, and it's pretty well stayed there. We just -- it's real comfortable with that kind of rate, and it cranks along like crazy. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay. And then I want to step back and kind of ask a broader question. You have 7 rigs drilling now. I was wondering if you could speak to how those rigs are roughly allocated between the windows and how you see your projected activity level this year kind of by window? I don't know how precise you can be but...

Oh, let's see, right now, probably, it will be like 2 on the West side and 5 on the East side. We're more over on the East side now on the wet gas side of things, and that's mainly because we started the year out with more wells drilled on the west side so now we've moved over to the east side but...

Let me -- if you refer to the new map put out this morning, Slide 11, TML [ph], that will show you exactly what we're doing. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay, great. And then just one last one is more of a bigger picture question. You obviously have the liquidity to expand your activity levels pretty significantly from 7 rigs, but kind of given the manpower you have in place, how big can you get kind of operationally? How much after the program you think you can manage with the staff you have?

Well, we're real comfortable with 7 rigs, but we have been adding people all along. Right now, we're cramped a little building in -- on the eastern side of Ohio at Saint Clarasville, and we're building a new office building up there that has 25 offices in it. We've got about 7 where we are right now so -- and we're wondering if we got enough room in that building. We didn't mention when we expanded it, but we're building our staff and presence on the ground up there. Another thing that helps a lot is having Stingray up there, and having our own frac company, being able to work with them. You've got real continuity on the operations. That saves us a lot of time and money, and we mentioned that in the -- as we were talking about the cost savings, but having a 50% interest in that and the margins that you can make on a frac job, half of that margin on a well goes right to the bottom line, and we're spending $3 million to simply frac wells out there. So that's a big deal for us. But that continuity and having the same people available to us, and we do use third-party services because we can't get everything frac-ed with Stingray, but that kind of smoothes things out for us. We're picking up better drilling rigs all the time. We're up in our fleet. Now we're bringing in rigs that can move around hydraulically on the location, walk from 1 well to the next on a pad, keep the pipe in the dairy, and all these things are helping with the continuity up there so -- but we are adding people all the time up there too.

Our next question comes from Brad Heffern with RBC.

I was wondering, I know you don't have a flesh out 2014 sort of schedule yet, but if you're completing so many wells in December, is that going to result in having sort of only handful of completions or a relatively small backlog going into the first quarter? Or are we kind of at a point now where we're going to see you guys completing and hooking up to sell 15 wells per quarter or something like that?

No, we're actually completing those wells is a couple of months before we can bring them online. So the actual frac-ing is done a couple of months before December, and then of course, we'll be continuing to drill wells. So we'll still be completing -- with more or less 7 rigs running, we're going to have 7 wells to complete every month, and that will occur October, November, December.

So we're drilling on additional pad, and so with the 7 rig program, you're going to see wells coming on in each of the quarters next year with the timing of pad going 2, 3, 4 wells off the same pad. So you're going to see a little more leveling out probably next year from quarter-to-quarter, and then as Jim mentioned, probably do some more single-well pad drillings as well.

Yes, the reason for the lumpiness at the end of the year is having brought on 3 or 4 wells -- 3 or 4 rigs during the last 2 to 3 months, and so those wells, by the time you drilled 3, and then you frac them with that time delay, a bunch of those end up right at end of the year. But over time, it will level out so we're going to be 1 well per month on the average from each rig. So it'll be soon moving to the point of 7 wells per month to be completed, and then would bring on more rigs. Then there'll be a little lumpiness again at first, and then it will level out again.

Okay, understood. And I wondered if you could provide some updated thoughts on the same shares. Obviously, you guys sold the Phu Horm a month back or so. Should we expect to continue to see those sort of partial monetizations?

Well, obviously, as -- I'm sure our shareholders are -- were very pleased with the performance of the Diamondback shares. The management team has done a great job there. As you know, we announced recently that we have bought additional Utica acreage, and we used the proceeds of recent secondary that we bid on some bank shares, a small amount of bank shares that we sold for that. So I think if we have a continued opportunity to put it to good use, we'll do that, but we're still also happy to let them continue to build value through the drill bit. So no urgency on our part at all. Like you said, we have a very good liquidity position and lots of ways to fund things, but that certainly is an opportunity that we could take advantage of if we need to.

Our next question comes from David Beard with Iberia.

Maybe just talk a little about your wet gas type curve. I guess you have 5 wells now. Do you have a sense of how many wells you may have by your third quarter report or the first fourth quarter report?

Well, about the third quarter, let's see, as far as wells are going on, I'd say about the third quarter, we've got a couple of Wagner wells we're getting ready to frac. Those will be the wet gas type, and we're drilling -- we're moving on to some new pads now that are around the Shugert, we're drilling already around the Shugerts on that pad, and then going off to some of the adjoining pad. So there'll be a lot of the wells that come on through the rest of the year that are over on the East side so that's where our rigs are now.

Okay. And do you have a sense of where that curve may track as you add more wells just because the 5 you have in there are truly spectacular wells. And if we start to add in good wells, it could bring that number down, but I'm wondering if you'd care to take a guess on what that may look like over the next couple of quarters?

Well, I tend to do my planning thinking about $10 million a day per well. But like I say, we've got a strong well like the Stutzman, and you just need to crank it open a little bit more than that at first, but that's why we kind of think of a flat declining curve for a long time because the wells are capable of doing more than that. Another thing that I might point out to you with 2 of those wells that are producing now are on the court wells and those are wells that we spudded this year and so we have -- last year, we had a 50% interest in the wells when we spudded them. But this year, like with the McCorts, we've got more like a 78% interest to start working the interest because we bought out Wesford on part of their acreage. And as the rest of these wells come on really about the point most the wells that we're drilling now, we're looking at a 95% working interest. So not only are the wells hanging in there good and lasting long time, but as we put more wells on, our working interest is improving over time. So that's another reason why you're seeing the big ramp up at the end of the year. It's not just the wells that are going on, it's the working interest that's changing.

And David, I was looking at the schedule while you guys were talking. It looks like we can certainly add a 10 to 12 wells in that wet gas window before year end.

Okay. So would you care to take a guess at what that type curve may look like when you're looking out to January and March of next year as you now have 12 or even 15 wells tied in there? So should we expect it to come down or is it too early to tell?

Well, as far as the type curve goes, we like the way we've got them on there. That's -- we got some history so far.

We would not expect it at this point to come down. We -- again, we think it's going to be leveling out, and expect that there would be actually no decline. So that's our current expectation.

Okay, that's very helpful. And just a housekeeping question, did you guys give out CapEx in the quarter or did I miss it at the beginning of the call?

Yes, it was a $74 million, David.

Our next question comes from Joel Musante with Euro Pacific Capital.

I just had a quick question on just modeling going forward. I remember early on, you indicated that we should model out about 1/3 oil, 1/3 NGLs, and 1/3 gas. And I was just wondering, given that you know more about the different spaces and where your acreage is and midstream infrastructure build-out, if that has changed or if we should continue with that mix?

I think at this point, it's still probably appropriate to use it. I think we were 29% gas at this time. So I would continue to use the 1/3, 1/3, 1/3. By the third quarter, we'll certainly have more clarity there, but I think it's still good at this point, Joe.

Okay, all right. And then actually, I know that some of the gas wells that are drilled to the East and West Virginia and Pennsylvania, still have quite a bit of NGLs. So I was just wondering, when you say dry gas, what is that -- I mean, how should we think about that?

Well, the Marcellus wells over there do have a lot of NGLs, and they're just across the line in West Virginia. And we do feel like over on the East side of our acreage, we've got potential to see some of those same things. In fact, we'll be -- we're making a really closed effort, and we maybe drilling some wells up the pad and test those, the Marcellus and the Utica Shale. So we think there's some real potential over on the East side of our acreage for wet gas in the Marcellus, as well as the dry gas that we're expecting in the Utica.

And the Stutzman, which is on that Eastern edge over there, is 23% NGLs.

Our last question comes from Dan Rise with GRT Capital.

Jim, I'm wondering as you gravitate towards more slick water fracs from gels, are you going to be experimenting with changing your resting times?

We sure are, Dan. That's -- we feel like on both the East and the West sides that we can shorten it because we don't have to wait for the gels to break. So in fact now, some of the recent wells we drilled over on the West side, in particular, where it's shallower, it's cooler, it takes longer to break the gels so we're frac-ing some wells with our normal type approach, but cross length and linear gels. And then the other ones we're doing just with the slick water, and we intend to start those coming back. I'm hoping that these 2 months and 1 month resting times can be dramatically shortened. We also see, as we move to South, even with the gel fracs, as we move south down toward where the Stutzman is that it seems like it takes less resting time there to bring the well on even without making the change to the slick water, but that's a really important point. We think that's going to shorten our resting time, maybe eliminate it particularly on the East side, eliminate it, shorten it, we hope, on the West side too.

And then remember, the side benefit is there's a 20% cost savings for a typical job so that certainly is advantageous for us as well.

Yes, it costs with our normal frac, 550,000 pounds cost of spud, $125,000 per stage if we use gels. And if we don't use the gels on the same sand, the cost is about $100,000 to frac that same interval, and we think we'll make a better well without residue from the gels.

Okay. Thank you, gentlemen. We believe this concludes this morning's call. A replay of the call will be available temporarily through the company's website and can be accessed to gulfportenergy.com. Thank you for your time and interest in Gulfport Energy this morning. This concludes our call.

Well, ladies and gentlemen, you may now disconnect, and have a wonderful day.