Gulfport Energy Corporation (GPOR) Q3 2015 Earnings Report, Transcript and Summary

Greetings and welcome to the Gulfport Energy Corporation's Third Quarter 2015 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Jessica Wills, Manager, Investor Relations and Research for Gulfport Energy Corporation. Thank you. Ms. Wills, you may begin.

Thank you, Devon and good morning. Welcome to Gulfport Energy's Third Quarter 2015 Earnings conference call. I am Jessica Wills. With me today are Mike Moore, Chief Executive Officer and President; Ross Kirtley, Chief Operating Officer; Aaron Gaydosik, Chief Financial Officer; Keri Crowell, Chief Accounting Officer; Paul Heerwagen, Vice President of Corporate Development; Ty Peck, Managing Director of Midstream Operations; and Dan Haynes, Director of Marketing/Midstream. I would like to remind everybody that during this conference call, the participants may make certain forward-looking statements relating to the company's financial conditions, results of operations, plans, objectives, future performance and business. We caution you that the actual results could differ materially from those that are included 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 Web site. Yesterday afternoon, Gulfport reported third quarter 2015 net loss of $388.2 million or $3.59 per diluted share. These results contain several non-cash items including an aggregate, non-cash, unrealized hedge gain of $62.2 million, a loss of $3.9 million in connection with Gulfport's interest in certain equity investments, a loss of $58 million associated with the impairment of our Canadian Oil Sands assets, a loss of $594.8 million due to an impairment of oil and gas properties, and an adjustable tax benefit of $1.6 million. Comparable to analyst estimates, our adjusted net loss for the third quarter which excludes all the previous mentioned non-cash items, was $8.7 million or $0.08 per diluted share. An updated Gulfport presentation was posted yesterday evening to the Web site in conjunction with yesterday's earnings announcement. Please review it at your leisure. At this time, I would like to turn the call over to Mike Moore.

Thank you, Jessica. Welcome everyone and thank you for listening in. As announced in the press release yesterday evening, during the third quarter Gulfport produced approximately 647 million cubic feet equivalent gas per day and reported $8.7 million adjusted net loss, $168.2 million of adjusted oil and natural gas revenues, approximately $94.3 million of adjusted EBITDA, and approximately $82.8 million of operating cash flow. While we are certainly proud of our operational performance this quarter, we also acknowledge these are challenging times for the industry. I plan to devote the majority of my prepared remarks today towards addressing how Gulfport has differentiated itself to not only weather these cycles but navigate them opportunistically and ultimately exit in a position of strength. Our core philosophy of maintaining conservative leverage and preserving the strength of our balance sheet has paid dividends and will continue to be the driving force of our business and our number one priority. Before we go into the detailed discussion, I would like to touch briefly on the key points that we will be addressing today. First, capitalizing on dramatically increased completion efficiencies in the late summer, we elected to accelerate our activities ahead of winter. While this increases our spend during 2015, it enables us to halt all frac operations during the first quarter of 2016, a time when operations are known to be less efficient and more costly. Second, driven by our efficiencies on the completion side and the proven strength of the rock, production has tracked well ahead of expectations. We are committed to delivering strong realizations and in combination with the slowing of completions we plan to optimize near-term pricing through the voluntary procurement of approximately 100 million cubic feet per day over the next several months. In addition, we have recently expanded our firm portfolio and added for a hedge book. Third, while we were pleased to announce our equity participation in the recent midstream joint venture with Rice, we are equally as excited to share with you the strategic advantages afforded to us by this solution and the end-market opportunities that will provide optionality to end the previously mentioned temporary voluntary curtailments by allowing us to realize optimized pricing. Lastly, considering all the points I just mentioned, in light of today's commodity price environment we currently plan to forego adding a fifth rig in the Utica at the beginning of 2016. And we are directionally moving more towards the middle of the previously provided bookends of activity next year. As we contemplate levels of activity going forward, I assure you that we will continue to act thoughtfully and financially responsible. Now to the specifics. During 2015, we have been highly focused on identifying efficiencies and finding ways to deliver more with less in all areas of our business. We leveraged the lower pricing environment to gain access to higher quality equipment and superior services which has led to dramatically increased productivity. To further build on these efficiencies, we elected to accelerate our completion activities ahead of the winter when operations are less efficient and more costly due to cold weather. We now anticipate that we will complete approximately ten additional net wells this year and while this will increase our level of spend in 2015, we plan to halt all frac operations and suspend completion activities during the first quarter of 2016, which will offset our increased spend. We estimate these activities will increase our spend in 2015 by approximately $60 million and have updated our budget accordingly. We now anticipate spending approximately $667 million to $677 million on E&P CapEx during 2015. Our heightened focus on the efficiency front has led to further cost reductions across the board since our last call. With regard to well cost, our purchasing department continues to work aggressively with our service providers on cost productions. These reductions help with our efficiency gains, result in savings of roughly 7% on future well costs relative to our estimates provided in August. We have provided a more detailed breakout of costs by window on Slide 24 of the presentation, posted to our Web site yesterday evening. On (inaudible) cost coming down, we continue to realize economies of scale as we develop this very prolific resource and as expected per unit operating costs are also trending lower. Third quarter lease operating expense totaling approximately $0.30 per MCFD, which is down 25% over the second quarter of 2015. Third quarter G&A expense totaled approximately $0.18 per MCFD which is down 16% over the second quarter of 2015. Third quarter midstream gathering and processing expense totaled approximately $0.71 per MCFD, which is down 7% over the second quarter of 2015. All-in, our cash operating costs were approximately $1.25 per MCFD in the third quarter of 2015, down 14% over the second quarter 2015. Again, in this environment we must be focused on delivering more with less and while we are pleased with all the progress our teams have made to date, we do expect operational costs to continue to trend lower during 2016 and beyond. Operationally, strong results from our existing production base, robust productivity from our recently tied-in dry gas wells and efficiency realized on the completion side, have resulted in our production track well ahead of expectations this year. We are extremely pleased with the assets' strong operational performance and the team's execution. However, in the light of the continued weak natural gas pricing, Gulfport has made the decision to voluntarily curtail approximately 100 million cubic feet per day of volumes beginning November 2015 through early 2016. Currently, excess volumes are flowing into an area of our dry gas gathering system that has temporary, limited end-market accessibility out of the basin and this short-term voluntary curtailment will allow us to optimize our near-term realized price. In spite of this curtailment, we reiterate our 2015 production guidance and will likely end the year towards the high-end of our expectations. While we expected our third quarter differential to swing wide of our guidance, with production during the quarter exceeding expectations it was more extreme than anticipated. Looking ahead, our temporary voluntary curtailment and the anticipated increase in seasonal demand as we approach colder weather, are both factors we anticipate will narrow our differential during the fourth quarter. We have provided updated realization guidance for the year and now expect our natural gas production to realize approximately $0.68 to $0.72 per MMbtu off of NYMEX during 2015. Our third quarter oil price came in higher than expected, driven by the benefit of utilizing MarkWest condensate stabilizer, allowing us more opportunities for better pricing for our Utica volumes and the premium LL pricing for our Southern Louisiana volumes. Our results year-to-date have led us to reduce our anticipated oil differential and we currently expect average $7 off of WTI during 2015. Our realized NGL price remained low during the quarter largely driven by the continued deterioration in the northeast NGL markets, and higher than anticipated non-operated NGL production coming online during the quarter. Gulfport as well as our peers, have begun to see some near-term improvement to prices due to higher seasonal demand and believe we will end the year towards the lower-end of our previously issued guidance. As a reminder, Gulfport operating activity is being directed to the dry gas window of the Utica and we do anticipate that our NGL exposure will decline over time. In the third quarter, we realized significant hedging gains of $29.6 million. We continued to monitor the future curves and will opportunistically layer on additional hedges and basis swap to provide certainty to our realizations and cash flows as opportunities present themselves. For 2016, Gulfport has swapped 380 million cubic feet per day at 346, locked in a significant amount of our anticipated cash flows next year. In addition, during the third quarter Gulfport strategically entered in to propane hedges, locked in a base load of 1,000 barrel per day at $0.48 per gallon, starting October 2015 through December 2016. We are well positioned through our strong hedge book as we plan for 2016 activity in this current low commodity price environment. To further support our realizations, as we stated on our August call, we are committed to securing additional firm arrangements as our volumes grow. Gulfport recently added an incremental 120 MMbtus per day of firm capacity to support incremental volumes to 2016. We continue to believe that the [indiscernible] commodity prices will yield additional opportunities for well positioned companies such as Gulfport to cost effectively secure firm arrangements and solidify realizations. On the midstream front, as we look for third-party midstream provider on our newly acquired acreage, one of our top priorities was to create a collective midstream solution that would allow us to reach all of our firm takeaway points from virtually anywhere on the combined systems. A few weeks ago, we announced we executed an LOI with Rice Energy to form a midstream joint venture to develop gas gathering and water services assets to support our development and potentially additional third party operators in Belmont and Munroe counties. Gulfport has a long history with Rice and we believe the JV creates enhanced alignment with our midstream provider, providing certainties to timing of infrastructure build out and further predictability to Gulfport's production profile. Rice not only provided the highest [IE] [ph] solution but also provided Gulfport with significant optionality as we plan the build out of our dry gas gathering systems. Currently we have separate distinct gathering systems in the play, each with their own unique connectivity through our firm transport. As part of our midstream joint venture with Rice, work is already underway to provide complete connectivity of our gathering systems and interchangeability of molecules across our firm portfolio. Upon completion in early 2016, we will have the ability to move production across all systems, and at that time plan to begin flowing the curtailed volumes to the premium end markets. Lastly, with regard to 2016 capital outlook and production growth, we continue to run a wide range of scenarios at today's commodity price and although no conclusion has been made, we are prepared to discuss how we at Gulfport view the world today. In August, we provided you with two bookends of activities. On the aggressive end of the spectrum, we could run a five-rig program and grow production around 50% year-over-year while spending $625 to $675 million on D&C CapEx. On the other end, in maintenance capital mode, we believe we could hold production flat from 2015 to December 2016 and grow 2016 average volumes around 25% year-over-year while only spending approximately $300 million. It is very important to note here that our decision to accelerate our completion activities in 2015, which is offset by halting the frac crew during the first quarter of 2016, would reduce each of the above bookends by approximately $60 million. So which direction are we leaning today? We remain strong in our commitment to funding E&P CapEx through operational cash flow and available sources of liquidity while maintaining conservative leverage metrics. While in August we were leaning towards the higher end of the range, further deterioration in commodity prices has us at this point directionally moving downward toward the middle of the suggested levels of activity. We are unique in that we have a very strong liquidity position with over $751 million available to us at quarter-end. That provides flexibility as we plan for the remainder of 2015 and look towards 2016. Additionally, Gulfport has a large base load of hedges locked in at an attractive price for 2016 ensuring a significant amount of our anticipated 2015 cash flow. The Utica continues to prove itself and its [capital] [ph] resource and our strong financial position allows us to remain nimble as we look towards the future and provide us with the options to adapt and thrive in any commodity price backdrop. In today's market, I believe what our industry needs is a more measured pace of growth. We are consciously curtailing production, laying down a completion crew during the first quarter of 2016 and foregoing the addition of a fifth rig, which will all lead to essentially slowing down our growth because we think it's a sensible thing to do. Our hope is that our peers, some by choice rather than by necessity, will do the same. Reiterating a few key points here. This quarter we had a big [feet] [ph] on production and drove every single expense item down, including our well costs which are industry leading. We stand poised to deliver on our full-year expectations including coming in at the high end of our production guidance of 125% production growth year-over-year. The decisions we have made to curtail production are temporary until the [Juniper] [ph] line is completed in late February. At that point, we can turn the 100 million cubic feet per day that we have curtailed from wells that were online as of November 1, as well as the volumes associated with the additional 15 wells we will have completed and have that behind pipe by the end of the year. Our decisions to temporarily curtail volumes are simple. We do not feel it was appropriate to produce more modules in 2015 just for the sake of growing in excess of our already strong guidance. While we could have done that, it would have been at the cost of our realizations. Bottom line, by temporarily delaying that production we will get a better price. Our reason for accelerating completions ahead of winter are simple as well. It saves us $500,000 per well. Both of the decisions are temporary in nature and have MPV-positive impact for shareholders. In closing, we have spent the past decade and a half thoughtfully and strategically building a business that supports sustainable return based investments. We have been cycle tested before and grew stronger during those times. I expect this cycle will prove no different. This concludes our prepared remarks. Thank you again for joining us for our call today and we look forward to answering your questions.

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

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

Mike, obviously your production was running, I think ahead of what I had or I think anybody had, especially when you look at that October average. My question is, is it again just the efficiencies? Is it some of the existing wells are continuing to flow as the newer wells are coming on? I am just trying to, maybe a bit more color as far as what's pushing these volumes. I mean again, we knew that the Utica wells were good but again, by this 706 number, I don’t think anybody realized it was going to be quite this good.

Yes, I agree. Good question. It was actually a combination of the strong well performance that we were seeing, particularly from the dry gas wells that we brought on but also just our operational efficiencies that accelerated some production as well. I would say, well performance got us to the top end of the range but efficiencies knocked it out of the park.

Got it. And then just secondly and is my follow-up. As far as just now when you move to the newer Paloma or AEU area, would that dry gas, I mean for early expectations, should we think about on what some of the other dry gases are doing to date, or how are you looking at -- I know it's very early on these wells. You haven't drilled any yet. But just how you think these will stack up versus some of your existing dry gas wells?

Well, it's still early yet but I think you just, Neal, need to look at the type curve as it relates to those particular pieces of acreage because we broke, as you know we broke out the dry gas type curve into areas. So we believe, based on everything we have seen to date, based on information from our peers, that that's what we should expect in the AEU area and also the Paloma area.

Thank you. Our next question comes from the line of Don Crist with Johnson Rice. Please proceed with your question.

I just wanted to drill down some on the cost savings that you have got this quarter. The 6% to 7% in cost savings on well cost. What drove that? Was that just drilling days or frac days and how much of that is sustainable going forward versus service cost reductions?

Good morning, Don. This is Ross. Most of the efficiencies that we -- cost savings that we got are through the efficiencies that we gained on the drilling side as well as completion side. We are now currently about 20 days on every well that we are drilling pretty consistently. And we have moved from about three days -- or, I am sorry, three stages per day to eight pretty consistently and sometimes we will hit nine or ten stages per day. So we feel likes that is certainly sustainable. We are always working to increase those efficiencies and we always work with our vendors to try to get our cost down as well. But we feel like that we will continue to realize some savings as we go forward.

Okay. And just looking at 2016. On a four rig program with that amount of drilling time per well, do you think you would be somewhere in the neighborhood of 50 wells compared to the 61 that you are forecasting to complete this year?

The thing is, we will be more efficient next year than we were in 2015. And so we with a four rig program versus a five rig program, we can certainly get more with four rigs than we could have and we did probably in 2015. But I don’t know that I can quantify exactly for you, Don. Aaron has a comment as well I think.

Yes. Don, I will give you, we will put out 2016 official guidance after the first of the year. But just based on the drilling efficiencies that Ross's team has seen and just the upgrading of the rigs that we are using now, 50 wells next year with four rigs should be highly achievable.

Okay. And just one more if I could sneak it in. Is there any other trigger point behind bringing those curtailed volumes on other than the midstream? Or is it, you know if gas prices spike in the next couple of weeks, would you bring that back sooner?

Hi, Don, this is Ty. We have firm arrangements coming in November-December, rest of the year, as well as the ones that we mentioned into early next year. So, yes, if we see a price spike we will definitely be able to continue because we are not stopping the completion. This is just a matter of providing this option value when the prices do spike. If they do, we will be ready to respond.

Thank you. Our next question comes from the line of Jason Wangler with Wunderlich. Please proceed with your question.

Just kind of up in Appalachia, I guess with what you have been able to add on the transportation and gathering side there, is it mostly just an ability to, assuming things are tight, obviously to try and get things out of basin. Is it simply going and finding some of the takeaway that is not being used but is contracted? And I guess are you going directly to the E&P or somebody that is contracted there, because it seems like you guys have been very diligent on getting some of these additional takeaways. Just curious on how that looks and where you see it maybe going forward as you are trying to match production with how much you can move out of basin.

We are always trying to match production with the takeaway on the basin. I think we also value flexibility to the extent that we can continue to provide clarity. It's happened to be that, yes, some of these projects are coming on and different operators, peers have different schedules and what not. And so we are diligently looking through those and trying to find where we can add value and move the production. At the same time, this is a marketplace that is volatile and so we want to make sure we have flexibility to respond because we are nimble and so we can respond quickly when things change.

And, Jason, I might add to that. You know, of course there is firm transportation but there are other ways to augment your portfolio as well. There are firm sales arrangements and you know we are taking a lot of inbound calls from folks who are interested in purchasing volumes of gas on a long-term basis. So we are evaluating all those options, firm transportation obviously and long-term commitment. I think in this commodity price environment what we are hearing is that some of the Appalachian guys will be potentially laying down additional rigs which will again provide opportunities for us in the release market for those folks who have excess FTE. So I think there is going to be lots of opportunities going forward for us. It is just like the $120 million that we just picked up, I think we will be able to get whatever it is we think is appropriate.

That's helpful. And just as we look at '16, without trying to get anything out of you there, just more looking at the acreage position. How do you see that playing out as far as where are we now on the held by production side and where do you see that kind of going as we move throughout even this year, and just from a planning perspective looking at 2016 and beyond?

Well, certainly at some point, probably later this year, we will talk about the total acreage that we have held as of the end of the year. Keep in mind, the majority, almost all of our acreage has five-year leases with five-year options. The 30,000 acres we acquired this year from AEU has a really easy HPP requirement with a small drilling commitment every year. Obviously, as we adjust our drilling schedule, our leasehold requirements may increase, that’s certainly something that we look at. We are okay paying renewals instead of drilling and we will do that. We are doing that in a small way this year as well. But make sure you understand we have a strategy to HPP, our acreage in the primary and secondary term. So it's something that we focus on but, again, we have been drilling for a while now so we have got quite a bit held.

Thank you. Our next question comes from the line of David Deckelbaum with KeyBanc. Please proceed with your question.

You gave us a nice update and a reminder about the bookends you provided last time on guidance and I know you guys are coming out with more formalized '16 view in the beginning of the year. You talked about basically the $60 million deduct from whatever those bookends would be on the spending side. Given where you are right now and it appears that, that spend is going to be coming in mostly in 4Q 2015. You are already ahead of where your '15 plan was supposed to be on the production side and now you are curtailing volumes and you went into the color on that. Do you feel like the bias now is higher for the production growth bookends for '16? Because it appears that with the efficiency improvements and well performance here, that previous guidance of holding production basically flat quarter to quarter for 25% year-over-year growth might be easier to exceed given how strong these falls are coming on?

So I am sorry, David, your question -- in my scripted remarks I mentioned that we were going to come in at the high end of our guidance for 2015. You know, right now, 2016, of course it all depends on the level of activity that we decide is appropriate. We are certainly going to deliver growth next year. We are just trying to be thoughtful about how much growth we should deliver in this kind of commodity price environment. You know we gave a range of growth for the bookends, 25% to 50%. You can do the math if we are talking about the middle of that. To your point, we are more efficient with our activities and so we could exceed those expectations from the middle of the bookends, but I think we are just going to have to wait and see what our final level of activities are next year.

And David, it's Aaron. Let me add one thing. We did talk about the curtailment exiting this year and it will go on for just a little bit of next year. But we still feel like the bookends production growth wise that we gave on the second quarter call, the production growth is still accurate net-net. So don’t let the curtailment kind of give you any noise on the production growth on the edge of the bookends.

And just one more comment, David. We keep [commenting] [ph] that the curtailments are temporary. So we talked about bringing back 100 million a day into February. In addition to that I mentioned in the script that we have 15 ducts sitting waiting to be completed as well. So we have got a fairly robust level of activity that we can bring on.

I appreciate that. Thank you. The other question I had is, it sounds like with some of the gathering infrastructure where you are producing in around the curtailed area, was some of that just delays from choosing midstream partner and getting a deal like that done? And are there any other areas where you are currently bringing wells online or drilling right now that would be waiting for gathering lines to hook up into your more favorable firm lines getting to better end markets?

Yes, this is Ty. I would say that the solution that we are putting in place today is not delayed. In fact it's being expedited just as normal. What happened though was when we looked at earlier this year we had some solutions that were going to be put in place but when we started to acquire AEU and Paloma, those acreage positions, it allowed us to think in a new scope and scale. It allowed us to bring in some solutions that were not just for short-term benefit but for long-term development. And so what we are putting in place we are really excited about with the partnering with Rice. It definitely brings a solution that is integrated, that brings flexibility to where we develop our, the acreage we develop, brings transparency to the services we are provided and the cost of the services. It also brings a scalability so that we can develop at different paces and again continue to meet the cost benefit as well as the realization that we are committed to.

Thank you. Our next question comes from the line of Mike Kelly with Seaport Global. Please proceed with your question.

Question is on the differentials. You took the full year guidance up for this metric but I think you said, Mike, in your prepared remarks that you expect Q4 differentials to narrow versus Q3. And I was just hoping you could give a little bit more color on that. Maybe exactly what you expect for Q4 and then how you expect this to trend going into 2016. Thanks a lot.

Hey, Mike, this is Ty. First of all, I would probably reference you to Slide 33 in our deck, because that helps with the conversion between MCF and MMbtu. We do expect improvement. One, from the curtailment and two, from just the firm arrangements we are phasing in towards the end of '15. And as far as going into '16, we haven't provided -- we will give a little bit more clarity once we have provided that guidance, but I think the $0.65 to $0.70 range is probably achievable. Again, I will reserve that for the full guidance. And then as we get beyond that '16, I would say that we are getting back to that what we have in our slide deck with the long term economics of that $0.65 differential. We feel comfortable with that direction. So, hopefully, that gives you some clarity as we look in '15, '16 and beyond.

Yes, that helps. Thanks. And then kind of sticking on the same subject here. Just fixed transport in general, what's a good kind of ballpark number to take in term of gas and bring it down to the Gulf Coast now? How much do you have to pay for that and how do you think about your willingness to commit to a long-term agreement on that front given gas prices recently tested $2 here? Thanks.

Yes, I guess, general is that, you we don’t feel like you have to commit to that. There is ways to get value out by different arrangements other than just producer taking on some OFT every time. So we are committed to exploring those options. I think you have seen that we have been creative in trying to make sure we get strong realizations and we give clarity to our investors, but at the same time all the while delivering growth. And so if there is more follow-up there we can do it offline, but that's kind of how we approach the marketplace today.

Thank you. Our next question comes from the line of Jeoffrey Lambujon with Tudor, Pickering, Holt. Please proceed with your question.

Just a few follow-ups from me. First, what kind of flexibility do you have to add back activity should commodity prices improve? Just kind of recalling the comments on maintaining that optionality, and at what prices might you guys look to do that? And then also any detail you can provide on the forays you are now in terms of contracts or leading edge [indiscernible] etcetera would be helpful.

Okay. Again with the amount of liquidity that we have available to us we can be very flexible, very nimble and respond quickly to changes in commodity prices. I think right now we think where commodity prices are today, and I emphasize today, I think it's unlikely that we would add a rig. But if prices change we can always ramp up, okay. There is equipment certainly is available and we are the most active driller in Utica and we pay our bills so people want to work for us. So we can do that if we need to. We can respond quickly. I would say, again, we are trying to be efficient with our capital next year. You have seen us saving $500,000 a day or a well by avoiding winter operations. So we are trying to create as much opportunity to have as much drilling activity as we can next year. We are focused on our capital efficiency. We are focused on drilling wells faster, completing wells faster. And so we can get more with less as I mentioned in the script. But if prices dictate, we can add back a rig fairly quickly.

Appreciate the color. And then the last question from me. I understand the rationale behind the curtailments but if you can just help me balance that with plans for the Q4 completions being pulled in from Q1, plus the turn of lines that you have kind of waiting on completion. Just towards getting a clear picture of how long this may trend over the next few quarters. Again I know you have got, obviously, the curtailed volumes plus wells waiting on completion, but just trying to get a sense for what production might look like going into the early part of next year assuming the [Juniper] [ph] line comes on line in February as you mentioned.

I think a conservative way to think about it is probably flattish fourth quarter over third quarter and then again going into the fourth quarter or the first quarter over the fourth quarter. Obviously, we are going to be spring loaded so you are going to see a very significant ramp as we come out of the first quarter, second quarter, third quarter, fourth quarter. That's where you are going to see the ramp next year.

Thank you. Our next question comes from the line of Dan Guffey with Stifel. Please proceed with your question.

Thanks for all the color this morning. You guys have done a good job driving well costs down. Just wondering if you can discuss any drilling completion tests currently underway or on the horizon that are going to focus on continuing to drive enhanced recoveries across all zones of Utica.

Well, I think we are being fairly consistent in our processes right now. We certainly try different things. You know, we talked on the last call about experiments that we were conducting. We talked about our thoughts on down spacing. Generally last call was a call for us to talk about a lot of our conclusions with how we think the play should be developed going forward. It's not to say we are not continuing to test things on the completion side, the fracking side. We are certainly doing what we can. We are mostly looking, I will tell you everything is a cost benefit analysis. So we are mostly looking for ways to save money. We are trying a new casing program but we never want to do anything that sacrifices the quality of a well. So just trying to find that right balance between cost and benefit and we will continue to do that. And I think we have done a good job at that, having driven our well costs down another 7% just from August. And I think we can continue do that going forward but it will be small incremental efficiencies that we gain.

Thank you. We do have time for one more question coming from the line of Jeffrey Campbell with Tuohy Brothers. Please proceed with your question.

Good morning and congratulations on a strong production. The first question I want to ask you is, since it saves material amounts, do you think it's possible you might adjust your completions to avoid the winter weather going forward similar to what you are going to do this year?

I think it would be ideal if we could do that, but I think if we have a 8 or a 10 rig program, it's going to be difficult to avoid winter operations. And I am just talking hypothetically in the future, Jeff. You know, it depends on the number of rigs we have running. We always like to have this completion inventory in our hip pocket so that we can be efficient out there. Winter ops is very, very difficult and very, very expensive and, you know, El Nino is unfortunately not really affecting weather much in Ohio this year, so it looks like it's going to be another frigid cold winter up there. So we will do what we can to work around winter but I am not sure we can always avoid it completely.

Okay. I am just wondering the wells where you are suppressing the production, do you anticipate any elongation of decline rates based on the rate reduction? Is this something you are going to study?

Well, we have curtailed wells before, Jeff, when we have had operational issues with midstream. So we certainly -- it's easy to see a well's response to a curtailment. And I do want to make distinction just so that we are all clear. We are not shutting in wells. We are just curtailing volumes a little bit on a group of wells. But you can see responses from different indicators on the well pressures and other things that we look at, pretty quickly. So we would not expect any detrimental effect. And quite honestly, we wouldn’t do this if we thought there was a long term detriment effect to the well.

Right. No, actually I was wondering if there might actually be a positive benefit. Perhaps the decline rates might be able to shallow it as a result because you are increasing the rate reduction. But it sounds like you have done this before and it's probably already baked into your current decline assumption.

Well, we have and keep in mind, as you recall over the last couple of years, we moved to these managed pressure programs. So really, honestly, we have already done this. We choked wells back when we decided we wanted to reduce them in a different way. And so we have actually done it. It's not really any different than what we did under the managed pressure program.

If I could sneak in one last one. I just wanted to ask you, as you continue to concentrate on dry gas drilling, is there any internal discussion about selling any other portions of the portfolio as they continue to struggle for capital? Or conversely, would you add to those positions at the right price? Because we are hearing some market chatter about potential activity in the wetter portions of the play.

Oh, yes, there could be those opportunities. I am not sure [wet gas] [ph] spreads are there yet. But we are focused, Jeff, on developing the dry gas window. We have 247,000 acres to develop. A lot of that is dry gas. Even what we have in the wet gas is more dry gas in nature. The economics are better. We are not going to leave the basin if that's what you are asking. We are committed to developing the Utica. We have the largest position in the core. And much of that is in the dry gas window where the returns are the best. So I think it's unlikely to see us dilute what we think is a great position.

Okay. And just to be specific, I was really thinking more about the condensate part of the portfolio.

Condensate, we do not have an interest at this point in condensate acreage.

Ladies and gentlemen, we have reached the conclusion of our Q and A session. I would like to turn the floor back over to management for closing comments.

We appreciate your time and interest today. As we know this is a busy time for many of you on the call. Should you have any questions, please do not hesitate to reach out to our investor relations team. This concludes our call.

This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.