Gulfport Energy Corporation (GPOR) Q3 2014 Earnings Report, Transcript and Summary

Jessica R. Wills - Associate Director of Investor Relations Michael G. Moore - Chief Executive Officer, President and Director Ty Peck - Managing Director of Midstream Operations Aaron M. Gaydosik - Chief Financial Officer J. Ross Kirtley - Chief Operating Officer

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division Jason A. Wangler - Wunderlich Securities Inc., Research Division David W. Kistler - Simmons & Company International, Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division David Deckelbaum - KeyBanc Capital Markets Inc., Research Division Andrew Venker - Morgan Stanley, Research Division Biju Z. Perincheril - Susquehanna Financial Group, LLLP, Research Division Cameron Horwitz - U.S. Capital Advisors LLC, Research Division Ipsit Mohanty - GMP Securities L.P., Research Division David E. Beard - Iberia Capital Partners, Research Division Gordon Douthat - Wells Fargo Securities, LLC, Research Division Marshall H. Carver - Heikkinen Energy Advisors, LLC Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Brian T. Velie - Capital One Securities, Inc., Research Division Jeffrey Grampp - Northland Capital Markets, Research Division

Good day, ladies and gentlemen, and welcome to Gulfport Energy Corporation Q3 2014 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would like to introduce your host for today's conference, Jessica Wills. You may begin.

Thank you, Will, and good morning. Welcome to Gulfport Energy's Third Quarter 2014 Earnings Conference Call. I am Jessica Wills, Associate Director of Investor Relations. With me today are Mike Moore, Chief Executive Officer and President; Ross Kirtley, Chief Operating Officer; Aaron Gaydosik, Chief Financial Officer; Keri Crowell, Vice President and Controller; Ty Peck, Managing Director of Midstream Operations; and Paul Heerwagen, Vice President of Corporate Development. During this conference call, the participants may take -- may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and business. We caution you that the actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we may make reference to other non-GAAP measures. If this occurs, the appropriate reconciliations to the GAAP measures will be posted on our website. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with earnings announcement. Please review at your leisure. At this time, I would like to turn the call over to Mike Moore.

Thanks, Jessica, and good morning to each of you. As announced in the press release yesterday evening, Gulfport reported approximately $90.1 million of EBITDA, $70.4 million of operating cash flow and $6.9 million of net income during the third quarter of 2014. Adjusted net income, comparable to analysts', a non-GAAP measure was $11 million or $0.13 per diluted share. Gulfport delivered strong third quarter results driven by the continued success we are experiencing in the Utica Shale. Production for the third quarter averaged approximately 42,332 BOEs per day, exceeding our previously stated guidance of 40,000 BOEs per day and representing a 60% increase over the second quarter. Building upon that momentum, we continued to see growth on the production front, with production during the month of October averaging approximately 55,900 BOEs per day and during the first 5 days of November averaging approximately 59,300 BOEs per day. Gulfport is uniquely positioned relative to the majority of the companies at E&P space. We were financially prudent in building the company and will act softly and responsibly as we budget our level of operational activity for the next year. Considering this, Gulfport will wait to provide 2015 budgeted activity until after the first of the year, to allow us time to gain more clarity around the expected commodity price environment. Regardless of activity levels, we expect to be able to deliver significant growth in 2015, shouldered by a healthy 2014 active rate, a sizable completion backlog and strong individual performance under our managed-pressure program. We expect the 2015 activity to be funded through operational cash flow, our undrawn credit facility and other sources of liquidity. While we have experienced notable production growth over the past 5 months, we remain focused on devoting significant attention towards our capital program and being prudent with every dollar spent per barrel added. From January 1 through September 30, Gulfport's E&P capital expenditures for our 2014 program totaled approximately $351.5 million and expenditures related to leasehold acquisitions totaled approximately $345.2 million. We continue to refine our completion design trending towards shorter stages and more sand per foot of lateral. From this, we hope to see further improvements in well performance and believe the results will outweigh the associated uptick in costs. Considering this going forward, we estimate oil institution cost in the Utica will be around $10.2 million in the condensate window and $11.2 million in the wet gas and dry gas windows of the play, all assuming a 7,600 foot lateral. On the leasing front, our activities have materially slowed. Gulfport continues to see core acreage in and around its drilling units, but the availability of unleashed acreage that they -- within our leasing parameters is becoming scarce. Today, Gulfport has approximately 184,000 acres under lease in the Utica Shale. We are pleased with the leasehold position we have amassed for the play and believe that our consolidated acreage provides a go forward with [indiscernible] purchase support numerous years of drilling. Looking towards 2015, we expect to spend significantly less capital on new leasehold as compared to 2014. Operationally, Gulfport had a solid third quarter, and we continue to see consistent improvements in the Utica Shale. On the going front, Gulfport drilled 29 wells with an average spud to rig release time of approximately 22 days per well, a decrease of 48% over the average of 2013. We are currently running acreage in the Utica and plan to be a 6-rig by year-end. Efficiencies were also strong on the completion side as Gulfport consistently utilized 3 completion crews throughout the quarter and currently has 5 pads in inventory. While we are pleased with the efforts of our team to date, we remain focused on the velocity of continual improvement. Rig mobilization packed with efficiencies, wastewater recycling and production facilities design are areas we are currently in the process of evaluating. We remain focused on mitigating operational costs through our vertical integration efforts and during the third quarter, Gulfport participated in the acquisition of an additional sand mine. Together, our investments in the sand business represent a current combined processing capacity of approximately 1.5 billion tons per year of high-quality Ottawa white sand. Given the current industry trend, we're utilizing increasingly more sand per foot of horizontal lateral drilled. We are very pleased to operationally had this key component of our business. During the quarter, we brought online 19 wells in the play, all located within the wet gas window. All of these wells are flowing under the company's managed-pressure program, and we continue to monitor the effects of the program across all phase windows of the play. In the wet gas window of the play, after 200,000 barrels of cumulative production, we are seeing approximately 38% higher pressures, when compared against the average pressures of the original wells. Turning towards to condensate window of the play, after 100,000 barrels of production, we are realizing nearly 5x greater pressures than the average of the original program. We are pleased with the results seen today and posted in our presentation yesterday evening, you will find comparisons between the original program and the current-managed pressure program. During the fourth quarter, we expect to bring online 14 to 20 wells in the Utica, which includes the 9 wells that were brought online prior to today's call. Subsequent to the third quarter, Gulfport began flowing our dollar pad, where among other things, we are testing multiple space regimes in the wet gas window of the play. Please note these wells are in the very early stages of production. We will analyze numerous streams of production data over the life of the wells, and given this tremendous amount of data that will be streaming to us daily, we plan to provide our team with adequate time necessary to generate solid, fact-based conclusions. In the meantime, we continue to monitor other spacing tests we have conducted in the play and are sharing information with and learning from our peers as they conduct similar experiments. To clear our own results and the data collected from our peers, we expect to feel very comfortable in our long-term ability to optimally space and develop each window of the play. With regard to our midstream activities, Gulfport continues to benefit from teaming up with reliable midstream partners. MarkWest recently began operations at its Cadiz II facility, a 200 million cubic feet per day cryogenic processing plant. This new facility increases total main play process capacity as Cadiz conflicts the 325 million cubic feet per day and allows Gulfport to deliver an additional 150 million cubic feet per day to the premium Midwest markets. Furthermore, we are pleased to see more press announcements regarding the sanctioning and timing of Cadiz III, another 200 million cubic feet per day of processing that is scheduled to come online in the first quarter of 2015. Meanwhile, the buildout of the dry gas gathering systems by both MarkWest and Rice are moving according as planned. In fact, within the next few days, Gulfport plans to bring online our first dry gas pad serviced by the Rice gathering system. We remain confident in each party's ability to construct necessary infrastructure to remain on target with our planned tie-in dates. These relationships are very important to our development. To my knowledge, we are one of the few, if not only, companies in the Appalachia that has a pipeline readily available to turn in wells and immediately sell upon completion. In the current commodity price environment, when compared to our Appalachian peers, Gulfport is better positioned as a result of quality firm transportation and a robust head growth. During the third quarter, our realized natural gas price settled at approximately 90% of the average NYMEX last-date settlement price and our NGL realizations settled at approximately 49% of the average at WTI for the quarter. These results continue to meet the company's expectation of the basis differential guidance ranges previously provided this year. Gulfport is committed to upholding strong price realizations and continues to evaluate multiple operational scenarios driven by various commodity prices as we plan for 2015. Our firm transportation portfolio secures access to premium pricing environment and becomes available for use timely and in conjunction with our production profile. In addition, we have secured our strong well economics by locking in significant percentages of our 2015 and 2016 production with natural gas hedges at 406 per MCF and plan to continue to be active in the hedging market to support our balance sheet and provide certainty to our cash flows. Lastly, we continue to maintain a strong balance sheet and a high degree of financial flexibility in connection with Gulfport's all redetermination under its revolving credit facility. The lead lender has proposed to increase the company's borrowing base from $275 million to $450 million, subject to the approval of the additional base within the syndicate. As of September 30, we had $153 million in cash, $617 million of total debt outstanding and we're completely undrawn on our revolving credit facility. Gulfport's strong balance sheet allows the company to remain nimble as we look forward to our 2015 plan and provides us with the option to adapt to the current commodity price backdrop. In summary, the main takeaways from today's call are first, the Utica is the strong aspect where we'll continue to see operational efficiencies and based on our activities in the second half of 2014, the company is positioned for meaningful growth in 2015. Second, we have secured transportation at 40 [ph] markets and have a robust head growth that will provide Gulfport with strong realizations for our products. Third, we have manageable fixed capital obligation and hold multiple sources of liquidity that offer financial flexibility as we plan for 2015. And fourth, our balance sheet holds only a modest amount of debt, which makes us well-positioned during periods of uncertainty and allows us to remain flexible and be opportunistic in this commodity price environment. This concludes our prepared remarks. Thank you, again, for joining us for our call today, and we look forward to answering your questions.

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

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

Say -- I just have a couple of questions here. First on production, I know you haven't put out '15 guidance yet, but just a couple of things around the production as I see it going forward. Are you still assuming much like the fourth quarter with the rig count somewhere around 14 to 20 wells per quarter next year? And then, if you could comment anything about, I guess, most of the wells next year, are they going to be more dry gassier? And the wet gas area, do you have any thoughts there? I mean, to kind of help us forecast which way approximately they go.

Well, I understand you are all trying to look out to 2015. 14 to 20 wells was the guidance that we did give in this year, and quite frankly, we're just going to have to wait and see what kind of plan we come out with for 2015. So I can't really guide you specifically on how to look at that. You do have to keep in mind that we are much more efficient with our drilling activities. The second question is...

The type of wells.

Again, we're looking at all that. We want to drill the most economic well. The wells that have cash returns, and so we're looking at what's the right mix of activities is next year both from a rig count and also across the phase windows. The beauty of the Utica is the ability to put rigs in different windows to adjust quickly to any commodity price changes. So unfortunately, I can't give you much guidance yet. We're going to hold off on 2015's specific guidance until after the first of the year.

Okay. And then, looking at -- to me it appears that on the type curves, both are holding up. I guess, kind of 1 question around that, if your thoughts about when you would or wouldn't -- if you would put out a -- just a pure dry gas type curve and how kind of that would fall in versus the wet gas. And then any comments, I guess, the only not fair would be maybe that the wet gas is trending somewhat along the bottom part of the estimate. But just your thoughts on that as well as the dry gas curve.

Well, I think, speaking to, I guess, the curves and sales first. As you recall probably, we put the condensate wells on earlier onto the managed-pressure program. So we've had more time with those wells. And quite frankly, condensate wells had more room for improvement. But we have seen quite a bit of improvement as well over on the wet gas side. It continues to be very stable, and we're very, very pleased with results in both of those windows. As it relates to dry gas type curve, we do have 5 rigs running in the dry gas window right now. So we're going to have a lot of dry gas pads coming on including 1 this quarter. We'd like to just get some of those pads on, Neal, and have some time production. We'd like to have a bigger dataset before we put out a dry gas type curve. So it's likely going to be sometime next year.

Okay. And then last question, just looking at the price realizations and well costs. I'm trying to get both on maybe an apples to apples. I noticed on the realizations, it appears that your realizations are more inclusive and include other costs maybe that some other peers don't include. And then again -- and then, looking at the well costs, trying to get apples-to-apples there as far as obviously, the absolute numbers' gone up. But just looking at how you would view on a sort of per stage basis there?

This is Ty, Neal. On a realizations, we run all our transportation costs and the downstream from the market in the realization. So the line item -- the mystery line item is gathering, processing and then the -- transport all that to get to market is in the realization.

So is that, Ty, I mean, at least another, I mean, is that 20% more? I mean, if that was backed out like others do. We're saying that could -- that would be 20% less or 30% less, just try to give me an idea.

I think if you look in our slide deck -- Slide 18. To give you an idea, maybe look at the transportation cost there in that graph on that upper left corner.

And then, Neal, just to make sure we answer all your question. Our well costs do include all facilities, all pad costs. So it's all inclusive.

So I guess, Michael, I'm trying to get is just, obviously, the gross number on the well cost that had gone from $9.6 million to somewhere around $10 million or so. But just your thoughts on a per foot basis, how are you -- it appears to me it's coming down but just trying to get a sort of percentage that you're showing.

Well, the increase in well costs is a direct correlation to the shortened stages that we're looking at right now. So first of all, let me say that. Secondly, on a cost per foot basis, I think we are at the bottom and if not the lowest on a cost per foot basis compared to our peers. So our well costs are still very, very competitive compared to our peers.

And our next question comes from Ron Mills from Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: 1 Mike, just -- you brought on all wet gas wells here in the third quarter. If you would look at where your rigs were located, and you talked about having 5 pads waiting to be brought online. Where are those located in terms of commodity windows? As we look out not just the fourth quarter but the next couple of quarters since at least that kind of commodity mix should be well-known regardless where you spend your money next year.

Well, I normally kind of answer in a different way, I suppose. So we're, I think, for the quarter, we are at 71% gas. Next quarter, probably closer to 75% gas. We do have a dry gas pad coming on here in the next few days. We should have 1 more wet gas pad coming on, and the rest of the pads coming on in the fourth quarter are going to be condensate pads. So we have -- we do have a 5-pad inventory right now that is all dry gas. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: The 5 pads are all dry gas.

So while -- you'll see a lot of dry gas coming on in the first half of next year. Is that your question? Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. Yes. I was just trying to get a sense about the commodity mix pool the tenure that changes given where your current pad inventory is located. And that gives me a good sense. The -- and Mike, did you say that you're currently at 8 rigs? If you say you would be looking to go down to 6 rigs, and if so, is that a function of just drilling efficiencies? And how many wells -- would that still allow you to drill the same number of wells?

So just from a contract expiration standpoint, we will be down to 6 rigs by the end of the year. But you're right, we're so much more efficient now. We can drill same number of wells with less rigs at this point. So 6 rigs by the end of the year. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And -- but is that -- even though the contracts roll off -- are you definitely going to let those go?

We probably will. There are plenty of contracts of rigs available -- sorry, rigs available to us. So as we continue to try to develop our 2015 plans, we have lots of options. What we've been doing this year just to make sure that we all understand is hydrating our equipment and our crews. So during this year, we have let contracts expire naturally. We brought on new contracts, and that's why you've seen us at a little higher rig count than we anticipated. We've been in a process of continuing to hydrate. As we look out to next year, again, with 6 rigs, we can drill more wells. We can drill the same number of wells. We've just got to find what the right level of activities are. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then on the wet gas curve that you referenced earlier, obviously, the pressures are quite a bit higher. But it looks like the optimized program is starting to cross through the original program here kind of plus or minus month 8 and maybe even at a little bit flatter decline. Any commentary around that? Any potential, any early estimates in terms of -- because it's crossing over at the 8-month mark and not the 2-year mark. It didn't seem like the lower IP rates will have much of a negative impact of -- if any on the IRRs.

Yes. No, I mean, we are certainly continue to be pleased with what we've seen. It doesn't appear that it's about to cross over. Again, the whole tier was with the new managed-pressure programs that we flattened, we flattened out the decline and increased the EURs. Obviously, we're not going to make any adjustment to type curves until we have more time under the managed-pressure program. But we continue to like everything we see.

And PV wise, this is Aaron. I just a quick crossover point being within a year, we're talking months to kind of the accumulative production wise ahead of where you were before but have a more pressure from that point forward. We think that, that's going to be positive from a PV point of view. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then 1 just -- I'm not sure this should be asked, but Canada keep marching towards that 6,200 barrels a day from that Algar Lake hopefully by the middle part of next year. Any update on potential monetization or some sort of event up in -- with the grizzly?

Yes, that's a good question, Ron. So with -- the plan is still continues to be a full production by midyear, next year, and then to continually evaluate the markets and find out what the opportunities are. Obviously, pricing is down a little bit for that commodity right now. But when we ramped up the full production, which is the gaining item for us. We'll evaluate the markets and decide what the best opportunities are for us.

And our next question comes from line of Jason Wangler from Wunderlich.

Just curious and Ron kind of asked what I think about the rigs. But heading into 2015 with the 6, could you maybe just kind of give as a little color as far as what those contracts look like? How long you're on term with those looking forward?

Jason, this is Ross Kirtley. We have a rig expiring or we're going to leave -- let it go in November -- at the end of November, 1 at the end of December. And then, we have a great optionality going into the first quarter of next year. We have a contract expiring in January and 3 in February. Then again, 1 in May and 1 in August. So we feel very good about our contract situation right now, and there's a lot of optionality to continue that very [ph] process. So we're excited about where we stand for the contract-wise.

Nice. I definitely agree with you there. And Mike, you mentioned, I think, you used 3 different pressure pumping crews in the quarter. Could you maybe just -- maybe it's for you as well, Ross, but where -- what are you guys seeing on that side as well, just up in the region right now?

Are you talking about as far as availability of equipment?

Well, availability and I'm assuming there's no contracts involved, but just what -- yes, the availability, and just kind of your plans on that side given that as you just kind of walked through you get a lot of optionality of the drilling side.

Well, obviously, our relationship and ownership in Stingray is very important to us and as is all of our vertical integration activities. And so we will continue to use Stingray heavily, and use other third parties as well. Ross, do you have anything to add to that?

No, that's exactly right. Stingray will be our go-to, and then we have another contractor or another provider that will fill in when we have that need.

And our next question comes from the line of Dave Kistler from Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: You mentioned in your prepared remarks the vertical integration on the sand mine side of things. Can you talk to us a little bit about what kind of capital goes into that? And maybe the estimated kind of economics with the investment from a rate of return or payback perspective?

Well, first of all, the investment is fairly nominal, $20 million, but what it really provides for us, Dave, and it does have a good payback, and I won't get into specific paybacks. But it really -- what it does for us is lock in our availability of sand. We are -- we continue to be concerned about sand. People are trending towards more sand, shorter stages. So I think, it's very, very important to lock in that source of sand. David W. Kistler - Simmons & Company International, Research Division: Okay. And then, with the Cadiz II facility coming online. Can you talk a little bit about the impact that might have for either reducing processing costs or increasing realizations as you can deliver to the Midwest market? I know you took up the processing transport marketing guidance a little bit, but just wondering if that provides an incremental cushion.

Definitely, with Cadiz II coming online, we're going to continue to ramp-up volumes in the coming days. And then, for the remainder of the year, we will be exporting most of that gas upwards of 80%, more production out to the Midwest markets. So it does release some volumes going through Seneca that we have been seeing the increased NGL transportation, but with our growth continuing into the remainder of fourth quarter. That's why we put that guidance -- the revised guidance through for the '14 -- 2014 at the level we did. David W. Kistler - Simmons & Company International, Research Division: Okay. And then, just 1 last one just to make sure I'm thinking about this correctly. Southern Louisiana production was down, but that well seems to be temporal in nature as workover activity was down even more than the production. Is that a fair way to think about that? And that probably comes back to a steady state of a little north of 5,000 BOE a day or 5,000 barrels of oil a day?

Dave, this is Ross again. Yes, you're right. The production was down. It was a result of less workovers, and we've had to workover some saltwater disposal wells down there. We had a couple of wells that were -- we were no longer, so we had more time on some wells than what we had anticipated. But yes, we're working hard with the team down there to get production back. Our goal with all of our assets is to produce these fields as efficiently and as much as we possibly can. And that's what we're heading towards in Louisiana as well.

Dave, we see -- we often see quarterly cycles. So it's not unusual to be down 1 quarter or 2 during the year, but it usually bounces right back. It typically has to do with timing of doing a recompletion activities, and as Ross said, we have reached completions this year. Also, sometimes in the winter, when the water levels are low, it causes us not to be able to move equipment around efficiently. So there is some quarterly cycles occasionally.

And our next question comes from the line of Leo Mariani from RBC.

Obviously, it looks like you've got some pretty good production momentum here. I think on previous calls, you guys talked about a year-end exit rate of around mid-50,000 BOE per day range. Is that still a fair number? It looks like you guys are a little ahead of that right now.

Well, let's just say Leo, we feel pretty comfortable with that exit rate number at this point.

Okay. Obviously, I know you're not ready to give 2015 guidance at this point in time. You guys talked about other sources of liquidity, which I'm assuming could be potential asset monetization. Could you guys kind of update us on any sort of current thinking around that?

Well, as you know, we continue to work forward on the service IPO. And obviously, I'm limited on what I can say there that could potentially be a source of liquidity for us. And then, also, we could continue to monetize our fame [ph] shares at some point. So those are -- those certainly 2 sources -- potential sources of liquidity for us.

And Leo also, this is Aaron. We do expect us with our continue to drilling activity that the revolver -- the borrowing base will increase over time. So we're going to $450 million. Right now, we're in that process, and we expect that to continue to grow throughout 2015 as well.

Okay, that certainly -- it certainly makes sense. I guess, just in terms of the spend for '15. Can you frame it a up a little bit better philosophically? Like is there a target debt metric or anything like that, that kind of has you sort of focused on as you're planning your budget? Because obviously, as you talked through, you've got numerous liquidity alternatives here to potentially raise more capital on that front through asset sales, and the borrowing base seems to be in clean shape, undrawn, currently. So could you maybe just talk through any kind of high-level parameters that will sort of dictate budget?

Yes, Leo. Really it's more of a kind of a multifaceted approach. So part of the strategy behind waiting a little bit to give the 2015 activity level is just to give a little more clarity on what the commodity price environment looks like. But beyond that, what we want to do is also focus on making sure that we kind of think about our firm transportation. We got a great per portfolio of FD, [ph] and we've layered on hedges recently. So we do like the hedges that we have in place. That's kind of part of the decision-making process. And then, kind of what you're referring to is we have a strong balance sheet. We want to make sure that we maintain that strong balance sheet. So it's kind of all those things together that is part of the decision-making process for the 2015 budget. And then, of course looking at well economics and making sure that we're kind of driving long-term shareholder value. So that's kind of what we're thinking, and we just need a little more time to be thoughtful there. So that's why after the first few will follow-up with that.

And so Leo, just to be specific, our plan is to live within our cash flow and our sources of liquidity, including our -- the growth and revolver. So I think, we're uniquely positioned to have a lot of optionality about what we do next year. And we are a gas company and not an oil company. So clearly, our commodity is -- has been or a little more immune to the volatility lately. So do we have a lot of optionality coupled with our strong firm transportation position, as Aaron mentioned, and our robust hedges. So we try to put ourselves in a position to have the kind of program that's appropriate next year. But as you know, we do have -- we are fairly conservative from a debt perspective. But as we move into the development part of the play, which we are doing right now, certainly, we would consider that if appropriate as well.

Yes, it all makes perfect sense. Obviously, you guys spoke about getting the dollar pad online recently. Is there any kind of ballpark time frame when you guys may have some more detailed analysis around the results there?

Yes. I'll tell you, Leo, it's just going to take some time. We are getting so much data off of those wells. Remember, not only are we casting down spacing, we're also looking a lot of other things via the fiber optic cable that we strapped to the pipe. So we have hired an outside firm or several outside firms to help us analyze all the data, and they are beginning to do that right now. In addition, we have bought and installed and are using software of our own to analyze the data. But it's just quite frankly, we need more history, and we need more time to analyze all the data. So it's going to be sometime next year. I'm not sure even by our fourth quarter call, it will be finished. It may be after that, but we'll certainly get you information as quickly as we can.

And our next question comes from the line of David Deckelbaum from KeyBanc.

You talked about before -- I know that it's very difficult to triangulate '15 right now, but you didn't say that you're effectively done with the leasing CapEx. So as we look into the next year, I mean, you guys more than spent almost $400 million this year on leasing. Should we expect that number to be de minimis? And if so, you said that you're looking to live within your means. And even with the current strip pricing, if you held the 6 rigs, you guys think that you could be call us to free cash neutrality at the end of the year?

Well, we're just going to have to wait and see what kind of program we run next year before I can answer that question. But you're right on the leasing budget, it will be de minimis next year. Quite frankly, David, there's just not much left in the core of the play. What we've been trying to do is, as you know, is block up our existing acreage position. So that frees up a lot of cash flow that we then can think about putting into D&C cost.

Are there any acreage that you have in your Utica position that you would possibly look at monetizing as you get into next year?

No, I don't think we're looking at monetizing any of our position. And -- now keep in mind, we do have 6% of our acreage in the oil window. That is something we may or may not develop. We'll just have to wait and see. We could consider potentially monetizing that, if somebody has an appetite for it. But we're certainly not looking at monetizing anything else.

Are you looking at new completion designs for the oil window?

Well, we watch what everybody else does, but we're not actively working in that window. We're focused on what we think are the windows with the greatest returns.

Just the last 1, just so I understand. On the well cost side, I know the laterals are similar to what you had guided in the past. I know that completions -- those changes, is the largest factor the use of slickwater?

In the well cost?

Yes.

No. The slickwater is actually cheaper than what we were doing before. But the cost increase, David, is the direct relationship to stage links and sand. So we're using more sand and shorter stages, which means more stages. It's all about that.

And then, the well cost that you're using right now assumes that, that just stays flat throughout next year.

Yes, and that's the current -- that's the cost you should use going forward.

And our next question comes from the line of Biju Perincheril from Susquehanna.

Right now, you're showing pretty stable, nice production growth out of the Utica now, and I was just wondering if you could add some color as to how much of that is due to the new pressure-management program and more sustainable weights out of the wells versus less downtime for -- from fracking offset wells.

Well, I'm not sure I can quantify the specific contributions for you. I would say the growth and the predictability has been related to the managed-pressure program, and remember, we're managing pressures and not rates. And so that flatness of managing wells -- that predictability has helped provide stability to our production growth. So every pad that you bring on comes on in a pretty strong way, depending on which window it is. It comes on average rates. Each pad can vary a little bit. Now certainly, we've gotten a lot smarter and a lot more efficient in developing the field strategically. And so we developed units together side-by-side, so that we can eliminate any downtime by adjacent activities. So that's certainly has improved the ability to sustain production at very high levels because we're not shutting in pads that have producing wells on them. So that's also been a big contributor to our activities, and we'll continue to be going forward looking. We've certainly -- our operations guys and our drilling folks have certainly -- are very efficient in developing our units and making sure that we have minimal downtime.

Okay, great. And on the dollar pad, can you give us sort of maybe a preview of what also are you testing there other than spacing and well interference? How does the results could change your completions going forward? What variables you were testing there.

We're testing beyond spreading these wells out from 300 to 1,200 feet. We're testing cluster efficiency, we're testing stage spacing and we're testing effects on some chemicals. So we're doing a lot of different things. I think, we're getting 3-terabyte of data a day from these wells. So it's a lot of data coming at us, and so we're going to learn a lot, I think, from these wells.

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

Mike, in that condensate window, are there any HBP factors that would influence the decisions of how many rigs you need in that area next year?

Certainly, holding our acreage is something that we pay close attention to. I think you have to keep in mind that the acreage that expires the earliest for us is -- it was very expensive acreage. It was back when we were paying $1,500 an acre, if we can all believe that it was ever that low. But -- so we consider it, and it's part of our budgeting. When we look at our activities, it's certainly a data point that we consider and model, so we will. As you know, we have 5-year leases with 5-year options, and so if we can't get it drilled, we'll simply pay the lease bonus again.

Okay, but I guess, is it fair to say that in the earliest -- lease expiration is in that condensate window?

Yes. Generally, that's correct.

Okay, okay. And then, just in the dry gas areas. I know you're not putting on a curve yet, but can you give us, I guess, any colors on how you're producing the wells in those -- some other operators have talked about falling in the sales at some standard choked-back rate. Any colors trying to help us think about modeling how those wells come into the sales line?

Well, it's hard because every pad is a little different. And first of all, we only have 1 pad on right now, so we've got to get this other pad on. But remember, Cameron, we're managing the pressure drop, so we're limiting the pressure drop to no more than 100 psi per week. And each pad will be a little different, so it's hard for me to give you a specific rate to think about.

Okay. I'll wait for a curve. And I guess just last on the cost side, is there any material difference as you move down deep through that eastern acreage on the well cost side relatively to the wet gas number you just referenced earlier?

Honestly, there's not really much difference. It's a 1,000 feet deeper, which is very de minimis from a cost perspective.

And our next question comes from the line of Ipsit Mohanty from GMP Securities.

Most of my questions have been answered. But if I can stick to the dry gas window for a second and so more micro level that's what's -- what do you mean non-option Rice in this quarter? And how would you think about, as a percentage of your production in '15, how much of that is coming from them as normal? Within a partnership with Rice, we all look to dry gas pads as becoming related to AMI, and how close are you sort of following their best practices in that window?

Well, first of all, there were no wells in the AMI in the third quarter for us. We do have the Perkins pad coming on in a few days, which is part of the AMI. That's our dry gas pad coming on next.

And as far as -- this is Ty. As far as future wells coming on, they'll be both coming on in the AMI and outside the AMI, as far as the dry gas. So we're really not distinguishing between those 2, nor giving that information now. It's just the dry gas program.

Ipsit, let me clarify because I'm not -- I couldn't hear you very well, but there were some AMI -- some wells in the AMI that Rice brought on. But if your question was did we bring on anything, we did not -- that we were their operator -- getting back to your 2015 question, I can't tell you what percentage of wells that might represent until I decide what the number of operated wells that we're going to have on our side. So it's hard for me to give you a specific number there.

I understand. And then let me -- my follow-up is among the other question. Obviously, your balance sheet is in great shape. You managed that very well going into '15 for times like this. I feel you can't -- of the opportunities that lie around you, both on the asset side and the corporate side as well, with some of these companies trading at the levels they are. How would you -- is there any discussion on growing? Or would you be happy where you are and sort of develop that?

Well, I mean, as a company, I think we have a responsibility to our shareholders to always look at accretive opportunities. So you're right, there may be opportunities, and we'll evaluate those opportunities as they come along. And that's what we should do. We have a fiduciary responsibility to do that.

I know that would be something to -- we'll get some color in '15. The first of quarter of '15, when you give out '15 -- 2015 guidance or at any time it come along as you go through the year.

Well, I mean, certainly, when appropriate, if we had some of those activities, we would talk about it at the appropriate time. We are Utica-focused, and if we find a distress situation or a deal that we think is very accretive to our shareholders, of course, we're going to look at it.

And our next question comes from the line of David Beard from Iberia.

Most of my questions have been answered. I know you'd mentioned the IRR as in the DJ, would you care to share what price you were using because recently, prices have been -- it seems like 75 to 85?

I'm sorry. David, did you say IRR in the DJ? What?

Yes. You'd given a range of IRRs -- I'm sorry, let me just rephrase the question. Would you care to give a range of IRRs -- I'm sorry, in the Utica, as it relates to different gas scenarios?

Well, so we're not prepared to talk about IRRs because we -- as you know, we've been operating under this new managed-pressure program, and we need more time under the program before we evaluate exactly what the type curves are, what the EURs are and what the IRRs are. So that's probably going to be a discussion that we would defer until later next year.

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

Just a question again on the completion designs. With the shorter stage spacing, is this something you're planning across all the windows? And then, how many wells do you have under this new program? And then, lastly, what are the stage spacing going from? What's the distance between spacing? What was it before? And then, also, the same for the sand loading.

Well, I -- we've been at historically and we've talked a lot about this. We've been at 240-foot, 250-foot spacing, and we have started trending down. We began, I'd say, late summer in small ways using shorter stages and more sand. We haven't necessarily, I would say, done that on every single well of every single pad. But we're definitely trending down to as low as 180. So our spacing or stage spacing will be somewhere between 180 and 240. And we'll use -- historically, we've used about -- almost 1,700 pounds per foot, and we're trending towards more like 2,200 pounds per foot. So we're trending up on sand. We're trending down on spacing, and we think that will have direct impact on EURs, but obviously, we're going to need some time to evaluate that.

Okay. And that's a fairly new development it seems. Care to quantify how many wells you've experimented with this new design?

I'd say, a handful. There haven't been a lot. So it is a fairly new development, and it is the trend going forward. And so that's how these well costs that we're be providing to you is the way you should think about our wells next year. Obviously, we see what our peers are doing. We evaluate it. We talk to our peers. We're sharing information with all of our peers. So I think the industry -- the Utica folks generally would be trending in the same direction. Now obviously, everyone has their own individual thoughts on frac design, but we were definitely trending down on stage spacing and trending up on sand.

And our next question comes on the line of Marshall Carver from Heikkinen Energy Advisors.

I'm not sure if you can put numbers to this, but is there any way to quantify the amount of downtime you saw with pad completions or with wells that could have been producing but weren't in the third quarter? And what do you think you it could be heading forward? Talk about the downtime getting reduced.

To make sure I understand, downtime related to simultaneous operations? Or downtime related to lack of infrastructure? What -- I'm not...

No. The number of -- well, really both if you have it, but I was thinking more the amount of downtime associated with the continuous operations?

Yes. I don't know what that would be off the top of my head, and I can tell you that I don't think there was no downtime for lack of infrastructure. Again, we're unique and the fact that we can hook -- we've been able to hook, and we'll continue to be able to hook far more wells into sales immediately. So I -- there's no way I could quantify that for you.

Okay, and a follow-up. You talked about the number of where the pads would be located going online this quarter. What should we assume in terms of number of well per pad? Just trying to get a feel for the wells going online in different areas this quarter.

I'd have to go pad by pad, but it's 3 to 4 wells per pad.

And our next question comes on the line of Jeffrey Campbell from Tuohy Brothers Investment Research.

My first question is Slide 13 shows improved drilling data then implies at all 3 windows of the same drilling in the third quarter of '14. Did you drill wells outside of the wet gas in the third quarter '14? And if so, could you give us some color on what's been drilling in each window? And what might be coming online in the next quarter or 2?

That's a lot of detail to give. I guess, we could talk about that offline, but I'd rather not get into that level of detail on the call.

Well, just broadly, did -- was there drilling outside [indiscernible]?

Yes. I'm sorry. There was drilling in all windows.

Okay. We’ll get in the ways offline, but that was helpful. Over the last several quarters, you talked a lot about efficiency gains and maintaining well inventory. First, will the reduced rig count change your approach to inventory? And is that an area that might be revised in impending 2015 development plan?

I mean, Ross can jump in here, but I -- the plan has always been to maintain an inventory, and we're going to continuing to do that. Ross, do you have any different thoughts on that?

No. Mike, I don't really -- the goal is to make sure we have enough inventory to stay efficient or [indiscernible] and to just keep wells rolling on smoothly and to do our production. So that's our goal, and that's what we're going to attain as we go forward through the year.

And just to clarify, that's not going to be of material impacted there with the 6-rig program as opposed to a greater number of rigs you've had at some other points in time.

No, no, no. We'll pace our crews only to keep things level from quarter-to-quarter. That's the beauty of having an inventory. We have a 5-pad inventory right now, and that's probably similar to what you'll see going forward.

Okay, and the last question I'd like to ask. I noticed a jump in the G&A guidance from the last quarter, and I thought most of the hiring had been done. So I thought it would be helpful to get a little insight here.

Well, it's really, I guess, it's 2 things. First of all, we have continued to hire to stay ahead of our growth, so we have continued to add folks throughout the year this year. But secondly, we're just trying to true up G&A for what we thought it might be by the time we get to year-end. Fourth quarter, typically has some costs coming through, and so we're just trying to make sure that we provide a realistic guide for you guys for the total year. But really, nothing extraordinary specific to speak about except just continued ramp on our employees.

I mean and just as a quick follow-up of that, is there anything particularly interesting with regard to the employees that you've been adding? I mean, is it -- to do with the production out of that thing or just sort of general growth?

There -- I would say the majority of folks that we've been adding have been technical, so we continue to staff up there. Again, we just want to stay ahead of our growth. As you know, it got away from us at 1 point, and we're not going to let that happen again.

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

A quick question, I -- most of mine have be answered, but just a clarification. I'm not sure I heard it correctly. The sand loading from and to numbers, it was 1,700 pounds and now it's -- it was 2,200 did you say, Mike?

2,200.

And our last question comes from the line of Jeff Grampp from Northland Capital Markets.

Just kind of wanted to talk -- I know you guys don't want to get too much into granular detail on West Virginia, but any kind of high-level commentary there on any recent acreage addition? Is there any plans to potentially start developing on that side of the fence there?

No. We're -- I'm going to be vague on what I say about West Virginia. Obviously, for competitive reasons, we're out there, and so don't really want to talk the areas that we're looking at or our specific development plans. Once we get our a acreage position put together out there, then we'll decide when it fits into -- to our development plans going forward.

Okay. And then, just 1 more if I might. Last quarter, you guys kind of gave some high-level IP rates from wells that you guys put online last quarter, but this quarter you guys elected to just speak more kind of broad strokes. Should we expect that moving forward? Or is that something kind of stopping the error? Or can you guys share any kind of high-level IP rates for the wet gas windows that came on line for 3Q?

Under the managed-pressure program, just the 7-day IP rates just seems irrelevant. So we're going to get away from talking about 7-day IP rates just because it doesn't really mean anything in the long term. So the wells are performing. We're managing them under the pressure-management program, and that's what's more important. So we're going to trying to stop talking about IP rates.

Ladies and gentlemen, that is all the time we have for our Q&A session. I would like to call -- turn the call back over to our CEO, Michael Moore, for closing remarks.

Thank you, Will. We appreciate your time and interest today, as we know this is a hectic time of the year for many of you on the call. We certainly enjoy working with each of you and feel very privileged to be included in your coveraged universe. Should you have any questions, please do not reach -- do not hesitate to reach out to our Investor Relations team. This concludes our call.

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