Jessica R. Wills - Manager, Investor Relations and Research Michael G. Moore - President, Chief Executive Officer & Director J. Ross Kirtley - Chief Operating Officer Mark Malone - Vice President, Operations, Gulfport Energy Corp. Ty Peck - Managing Director, Midstream Operations Aaron M. Gaydosik - Chief Financial Officer.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. Don P. Crist - Johnson Rice & Co. LLC David A. Deckelbaum - KeyBanc Capital Markets, Inc. Jason A. Wangler - Wunderlich Securities, Inc. John Nelson - Goldman Sachs & Co. Stark Remeny - RBC Capital Markets LLC.

Greetings and welcome to the Q1 2016 Gulfport Energy Corp. Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Jessica Wills. Thank you. Ms. Wills, you may begin..

Thank you, and good morning. Welcome to Gulfport Energy Corporation's first quarter of 2016 earnings conference call. I am Jessica Wills, Manager of Investor Relations and Research.

With me today are Mike Moore, Chief Executive Officer and President; Aaron Gaydosik, Chief Financial Officer; Keri Crowell, Chief Accounting Officer; Ross Kirtley, Chief Operating Officer; Mark Malone, Vice President of Operations; Paul Heerwagen, Vice President of Corporate Development; and Ty Peck, Managing Director of Midstream Operations.

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 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. Yesterday afternoon, Gulfport reported first quarter 2016 net loss of $242 million, or $2.17 per diluted share.

These results contain several non-cash items, including an aggregate non-cash derivative loss of $7.7 million, a loss of $219 million due to an impairment of oil and natural gas properties, a loss of $23.1 million associated with the impairment of our Canadian Oil Sands assets, a loss of $7.7 million in connection with Gulfport's interest in certain equity investments, and an adjustable tax benefit of $191,000.

Comparable to analysts' estimates, our adjusted net income for the first quarter of 2016, which excludes all previous mentioned non-cash items, was $15.1 million or $0.14 per diluted share.

Gulfport's D&C capital expenditures for the first quarter of 2016 totaled approximately $74.5 million and leasehold expenditures totaled approximately $19.7 million for the quarter. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with yesterday's earnings announcement. Please review 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 first quarter, Gulfport reported approximately $15.1 million of adjusted net income on $164.6 million of adjusted oil and natural gas revenues and generated approximately $96.7 million of adjusted EBITDA and $83.2 million of operating cash flow.

The first quarter was another solid operational quarter for Gulfport, highlighted by strong production from our Utica Shale assets and our continued focus on efficiencies that led to decreases in cost across the board.

In addition, Gulfport improved upon our already solid balance sheet completing a successful equity offering, which provides us with the flexibility and optionality should we continue to see improvement in the forward curve.

Total net production for the first quarter averaged approximately 692 million cubic feet of gas equivalent per day, ahead of our previously issued guidance of 670 million cubic feet per day to 685 million cubic feet per day.

As we discussed in February, during the first quarter, Rice completed ahead of schedule the lateral but now connects two of our existing dry gas gathering systems, which allowed us to end our previously announced voluntary curtailment.

In addition, while we did not have a completion crew running during the first quarter, we entered 2016 with an inventory of 15 gross drilled and completed dry gas wells from our 2015 program, which were all turned to sales and flowing by March 31.

Following the first quarter, Gulfport brought back a completion crew in the Utica and began executing on our planned 2016 completion activities in the play.

We currently forecast production during the second quarter to average approximately 664 million cubic feet per day to 692 million cubic feet per day and reiterate our full year production guidance of 695 million cubic feet per day to 730 million cubic feet per day.

During the first quarter, before the effect of hedges and including transportation cost, Gulfport's realized natural gas price settled approximately $0.70 per Mcf below the average NYMEX natural gas last day settlement prices for the quarter.

As you can see from our production results, we've brought online significant volumes during the first quarter within a matter of weeks and, when coupled with an unusually warm winter, we came in slightly above the high end of our previously provided differential guidance.

We currently forecast a similar natural gas differential during the second quarter. However, we reiterate our full year basis differential guidance of $0.61 to $0.66 per Mcf off of NYMEX monthly settled prices.

We believe we will experience stronger differentials in the latter part of the year and continue to be very focused on and committed to obtaining strong realizations.

In addition, before the effect of hedges, our first quarter oil and NGL realized prices came in as expected and we reiterate our expectation to realize approximately $7 to $8 off WTI for oil and $0.19 and $0.22 per gallon for NGLs during 2016. On the hedging front, we realized a significant gain of $65.4 million in the first quarter of 2016.

In an effort to further protect the balance sheet and provide certainty to our realizations in cash flows during 2016, specifically over the summer months and the shoulder season, we recently layered on additional hedges for the year and currently have approximately 82% of our expected 2016 natural gas production swapped at $3.20 per Mcf.

For 2017, we have a large base level of hedges to secure a healthy rate of return for a portion of our anticipated activities and currently have approximately 355 million cubic feet per day swapped at $3.08 per Mcf.

Turning to cost, we remain focused on improving efficiencies in the field and continue to see economies of scale as our dry gas volumes grow.

With regard to well cost, our efficiency gains and further cost reductions from our service providers have resulted in savings of approximately $300,000 per well on future well costs relative to our estimates provided in November 2015 and we continue to pursue additional reductions.

In addition, as you can see in our financial results released yesterday evening, all operating expenses continue to trend lower as well.

During the first quarter, our per unit operating expense, which includes LOE, production tax, midstream, gathering and processing and G&A totaled $1.08 per Mcfe, which is down 9% over the fourth quarter of 2015 and 28% over the first quarter of 2015.

First quarter, lease operating expense totaled approximately $0.26 per Mcfe, which is down 13% sequentially and 41% year-over-year.

First quarter midstream processing and marketing expense totaled approximately $0.60 per Mcfe, down 7% sequentially and 10% year-over-year and first quarter G&A expense totaled approximately $0.17 per Mcfe, down 6% sequentially, and 40% year-over-year.

As we stated on the fourth quarter call, we expect all per unit expenses will decrease further as we progress through the year due to our focus on cost initiatives in the field and the addition of incremental dry gas volumes, ultimately improving overall margins.

We have provided a detailed breakout of our updated well cost and operating expenses by phase window on slide 23 of the presentation posted to our website yesterday evening and assuming today's strip pricing, we estimate wellhead returns in excess of 40% throughout our dry gas phase window of the play.

Moving to the balance sheet, Gulfport remains committed to keeping the balance sheet strong and preserving financial strength and flexibility for the company. During the first quarter, Gulfport successfully completed an equity offering raising net proceeds of approximately $412 million.

Proceeds from this offering provide us with significant flexibility as we prepare for 2017 and contemplate the appropriate levels of operational activity.

As we look toward a potential rebound in natural gas pricing, this additional liquidity allows Gulfport to adapt quickly should we chose to begin adding back activity within the basin and ensures we do so while adhering to our core philosophy of capital discipline and conservative credit metrics.

Conversely this serves as an insurance policy in a lower for longer pricing scenario. As of March 31, Gulfport had approximately $454 million of cash on the balance sheet and an undrawn revolver resulting in over $925 million of liquidity.

Before we move to Q&A, let me touch on the current state of the natural gas environment and the key leading indicators we are closely monitoring as we think about our 2017 activities.

Number one, as we discussed in February, the North American shale natural gas rig count had decreased in excess of 60% over the past year with less than 50 rigs running in all of Appalachia at that time.

Today this number has decreased even further with the most recent Baker Hughes data showing less than 40 rigs running in the Northeast, which is down from over 130 rigs at the peak of the cycle. We continue to believe the dramatically lower rig activity must at some point correlate to meaningfully lower supply growth.

Current EIA data continues to indicate that production in the Northeast is plateaued at around 19 Bcf per day. And while the Northeast production supply growth is slowing, we are seeing evidence of material declines in production from associated gas, conventional gas in higher cost shale basins such as Haynesville, Fayetteville and Barnett.

Net-net, North American gas supply appears to be demonstrating early evidence of a rollover. Number two, meanwhile the demand side equation as we enter 2017 is encouraging.

The increased demand from power generation, colder gas switching, start-up of the LNG exports and increased exports to Mexico are materializing today, increasing the overall demand pool for North American natural gas. This data suggests that the supply and demand rebalance is no longer just wishful thinking.

The natural gas markets are becoming more efficient as time passes and numerous key indicators are all pointing towards an improvement in pricing during 2017.

As the macro environment continues to improve, we are preparing today to implement the appropriate operational and financial strategy that will allow us to increase activity levels promptly when warranted to ensure that Gulfport will be an active participant in an upward swing of the commodity cycle.

In summary, our high quality assets, low cost structure, strong balance sheet and current liquidity have uniquely positioned Gulfport to not only endure the challenges during a depressed commodity price environment, but also be poised to capture the value associated with improved pricing and accelerated activity should natural gas prices strengthen.

This concludes your prepared remarks. Thank you again for joining us for our call today and we look forward to answering your questions..

Thank you. At this time we will conduct a question-and-answer session. Our first question comes from Neal Dingmann with SunTrust. Please proceed with your question..

Nice quarter, Mike.

Mike, obviously, it seems to be all about efficiencies and cost here at least near term, could you give me an idea of – you've obviously seen cost and efficiencies continue in the last several quarters, I mean, if you had beyond sort of guidance for this year, can cost continue to run at this pace? I guess, two things, one the service cost, do you see those continuing to go down at the kind of the level they have been? And two, do you continue to see the efficiencies out in the Utica as we've sort of witnessed the last couple of quarters?.

Yeah. That's a good question. Since November, we've seen about $300,000 reduction in our leading edge AFEs. And just to remind you, since the peak of the cycle, including the most recent savings, we brought down well cost by 34% to 40%. So, these cost savings that we've seen over time are both from efficiencies and also from continuing RFD processes.

In fact, we just finished another round, and I will have Mark jump in here and Ross and talk about that as well, that they have been working on over the past several months.

So I do think there's some additional savings both through service cost reductions, but also mainly probably at this point through efficiencies, but I'll let the guys jump in and comment as well..

Good morning, Neal. This is Ross. Savings that we're seeing, as Mike mentioned, are across the board. We've attacked every line item on AFE. We've also seen some efficiency gains on our operations both on the frac side and completion side and also on the drilling side. That's something that we're attacking daily.

We talk about it daily, and I think early on in the play, as you will remember, we were able to knock off days off of our curves, and now we've gotten awfully efficient, so we're looking just at knocking off hours.

And as Mark said, we'll continue to look at all the efficiencies across the board, and I feel like we will continue to gain efficiencies, some of the costs, we're seeing some of the RFPs that we've gotten are getting close to the bottom, but we'll continue to work on that as well..

Hey, Neal. This is Mark Malone. Just like Ross said, we're seeing less days in location. That really, quite frankly, is a definition of efficiency for us, less pad days equates to less cost or quite a bit of saving.

So over the last year, as an example, we had a goal set on the frac side at six stages per day and at the end of the year we came in just under that, around 5.9.

But if you do the math on that relative to where we are today, eight stages per day, that knocks down, if you do the math on average well, you can go from about 36 days on pad to 22 days on pad. That equates to significant savings. So those are kind of efficiencies we're seeing on all phases of our completion work..

Great color. Go ahead, I'm sorry..

Not to overkill this, Neal, but just one comment I do want to make is while we continue to work with service providers and drive efficiencies down, we're certainly not making any decisions that would sacrifice well quality. So we're going to make sure we keep delivering industry leading wells. So we'll cut cost where we can.

We do postmortems of every well that we drill to see where we can be more efficient. But we'll never sacrifice well quality in doing it..

And, Mike, I'll try to limit it to one last question today. Just on completions, I'm wondering you mentioned about bringing that completion crew in.

What's your thoughts, is that you'll run that through rest of the year? If you could just talk about maybe frac plans, completion crew plans for the rest of the year as well as dugs (17:19)?.

Yes, so we're going to run -- it looks like we're going to have two completion crews running. We've got one now. They can handle actually most of the activity that we need.

We may bring in a second one at some point in time, but with the efficiencies that Mark mentioned from our completion side, I think that completion crew can handle everything we need to do this year..

All right. Thank you, all. Nice update..

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

Good morning. If I could drill down a little bit on NGLs, your realizations in the first quarter came in a little bit better than we were expecting and slightly better than the full-year guidance anyway. Can you talk about any impact that Mariner East may have had? I know it came on right at the end of the first quarter.

But is it expected to alleviate some of the NGL pressure in that area? And how does that look going forward, especially during the mid-part of the year when NGLs are normally weak?.

Ron, this is Ty. Yes, so we have seen some strength in the NGL market largely due to propane exports, Mariner East has definitely benefited as well as the export facilities down in the Gulf Coast. And so we expect that strength to continue through the year, which will help.

But I would say it is going to be offset somewhat in the fact that we're going in the December time when the demand in the northeast particular starts to weaken. So I think that we're cautiously optimistic. One thing I will note too is that we are starting to pull propane unit trains out of Hopewell, which should improve our pricing.

So, again, we're cautiously optimistic that we'll get through the summer months here with the export strength in the Gulf Coast and Mariner East and then move into when the demand starts back, but at this point right now we're going to keep what the guidance we have out..

Okay. And, Mike, if I could ask just one more macro-centric question. Just on the personnel side, especially when it relates to the service companies, a lot of companies now are talking about ramping if gas spikes here going into the back-half of the year, assuming that we have a good winter.

Do you think that 30 rigs or 40 rigs could be added quickly in the area or do you think that there is more of a personnel gap especially on the service side that may hamper any kind of fast rebound in the industry?.

Well, I will let Ross jump in here too. I'd say, on our side we're certainly planning ahead on the long lead-time items if and when there is an opportunity to ramp up, getting ahead on permitting, utilization, pad construction. But from the service side, I will let Ross comment on that..

Hi, Don. It's Ross. As the activity has contracted, all these service companies will put their best personnel on the rigs. So they've got drillers in (20:54) positions and they've got superintendents in drilling positions. So the ramp up, if there is one that would occur, would be I think fairly easily done.

There's lot of people still in the industry looking for work. So we don't see that as being a big obstacle in anyway should ramp-up occur..

Yes, that's all the questions I had this morning. I'll turn it back. Thanks..

Thanks, Don..

Thank you. Our next question comes from Jason Wangler with Wunderlich. Please proceed with your question. Jason, your line is live. Our next question comes from David Deckelbaum with KeyBanc. Please proceed with your question..

Good morning, everyone. Thanks for taking my questions. Mike, I just wanted to get some color or your thoughts or observations. You refer to the cash on hand that you have from the recent equity issue and so obviously the balance is very clean right now. In the past you've been a bit of a consolidator. You'd done a few deals last year.

Is there any attractive acreage out there right now and how active are you guys in the bidding process and would you like to be using any other's equity proceeds to consolidate your position further or do you look at that as more as an option on redeploying that capital into the ground should commodity prices improve?.

Well, that's an excellent question. I think our thoughts on M&A activity really haven't changed, David. I think we're in a little different position than some folks because we have a large inventory of undeveloped locations. And we've been pretty vocal about saying we don't necessarily think we need more developed acreage.

Obviously we'd like to have an opportunity to get some production reserves and cash flow. Just I haven't seen the right kind of opportunities for us in the core area. So, I think, we're pretty heads down, focused on developing our acreage.

At the equity raise, while certainly could help us pick up acreage here and there, it was really a defensive posture for lower the longer scenario and also an offensive strategy to enable us to think about activity levels in 2017 in a different way..

one, is it really the right time to start thinking about putting rigs back to work to build up the backlog of activity for 2017, because as you alluded to earlier, a lot of these projects are long lead.

Are you guys toying with the idea of bringing in more rigs in the third quarter to kind of prepare for a winter of 2016, early 2017 or would this be sort of a decision point where you don't think about building that backlog up until the beginning of next year?.

Look, I think certainly you have to begin now thinking about 2017 and what's your thoughts are on levels of activity.

You can see from the well economics in our slide deck, we make really attractive returns at $3.00 gas over 40%, and I am sure for your own model you can see that between $3.00 and $3.50, we could certainly support a higher level of activity.

And again, as I mentioned just a little bit ago, we're trying to get ahead on the long lead time items that don't cost a lot money, creating a bullpen of pads, making sure we are ahead on midstream development, permitting. So I'd say we're planning ahead for an increase of activity.

As to when we make those decisions, I think a lot of things have to happen. So we're certainly watching supplies, we're watching gas price to make sure that this is not just a temporary phenomenon, watching inventories, watching winter forecasts. So a lot of things are indicators for us and as to what our thoughts should be about ramping up.

And so Aaron may have a few comments too on this..

Thanks, Mike. Hey, David, it's Aaron. I think, as Mike mentioned, we're encouraged with the fundamentals that we're seeing for 2017, but I think it's worth highlighting a couple more things on top of what Mike talked about.

The first is that, as we talked about in February, we expect to have pretty strong exit-to-exit growth this year at a rate of 15% year-over-year. And then secondly you talked about hedges for 2016, we actually have a pretty good hedge book in place already for 2017.

So we'd look to be opportunistic to layer on there, but we already feel pretty good about where we are, not just from an operations point of view but from a financial liquidity and hedging point of view as well for 2017..

Okay. That's all from me, guys. Thanks for the comments..

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

Sorry about that, I'm still learning how to use phones. Was just curious, Mike, you talked about in your prepared remarks about seeing some lower differentials later in the year. Is that specific to just seeing more infrastructure coming into the basin.

Are you, as you mentioned in your macro comments, expecting maybe some declines on the production side or just where you see that potential coming from? Just trying to get a better handle on that..

Hey, this is Ty. So I think what we're seeing is, as you look into the strip, you're seeing the price of NYMEX rise. That's bringing the end market pricing that our transport reaches up along with it. And so those spreads continue to get better as we get into later of the year as well as volume growth continues stronger as we get later into the year..

So then, Ty, is that more, like you said, the end markets because of your transportation getting it, whether it's Midwest, Gulf Coast, I guess, rather than necessarily an in-basin situation.

Is that fair to say?.

Yes, that is correct..

Okay. And then, again, I think Neal was asking you guys a little bit about the cost side.

I was just curious on the drilling side specifically, and as we all talk about adding rigs or ramping, where are you at as far as how long it's taking you to drill some of these wells versus maybe where you were a year ago, just maybe in terms of days? Just trying to getting a handle on what we could be drilling on a per rig basis as we get to later this year or obviously as we start looking to 2017..

Hi, Jason. This is Ross. You've been following us for a while, so you know that early on we were in the 35-day range and we feel very comfortable putting out there now with all the improvements that we've made, we should be in the 22 days to 21 days sometimes, 23 days, in that range, depending on lateral length and some of the complexities.

As you get eastern in the play, you've got higher mud weights, so obviously that's going to slow you down a little bit; but then a little bit southern, it's more or like our Belmont acreage. So you're going to drill it like you do the Belmont acreage, which should be a little less – there's a little less mud weight.

So it's something as Rob's group continues just to attack every line item in that performance metrics, so we'll continue to get those down, and we feel comfortable about that..

Great. I'll turn it back. Thanks for getting me back in..

Thank you..

Thank you. Our next question comes from John Nelson with Goldman Sachs. Please proceed with your question..

Good morning and thank you for taking my questions..

Hi, John..

There's been some scuttle about ET Rover the pipeline potentially slipping next year. I know you guys have some access on that.

I'm just curious, how would a potential slippage in ET Rover impact your potential 2017 acceleration planning? Would you be comfortable producing in local market or do you have confidence you could access interruptible markets? What are your thoughts around that?.

Hey, John, this is Ty. So, yes, we are in contact with ET Rover on a frequent basis. They continue to commit to that mid-2017 timeframe and so that is what we're going off of. That being said, should that slip just like with any of these projects we do, look at contingency plans.

I think last quarter we announced that we did some physical hedges as you would off of the area, and it's a rate that was attractive and under our transport cost and we continue to look at those opportunities as when those are in-the-money and where we think that they should be, then we take those precautions and we go ahead and set up a position there.

So, anyway, we feel like again Rover has continued to state that. But we are also looking at ways to mitigate should there be any slippage..

I guess, just maybe to press that at a high level, do you think that'd be a significant threat to accelerating 2017 or do you feel that those risks are manageable?.

Yeah, that's a good point. So, I would say that if you look at Gulfport's transportation portfolio, we have a diverse set of pipes that we hit, and so there is not one project that we're beholden to. We'd like to see all those projects go and that's kind of our strategy. As we see all those projects go that continues to benefit Gulfport.

But if there is one project that doesn't go over another, it doesn't impact Gulfport like it could if we were all-in to one project..

That's very helpful. And then for my second question, we've seen the asset market open up here recently, I'm not going to belabor the acquisition questions, but just as I think about potential non-core areas of your portfolio or assets that might struggle to compete for capital in the near term.

Could Louisiana or non-dry gas Utica be considered potential monetization candidates, and if so could we see something along those lines in 2016?.

Yeah. So, first of all, John, we've been pretty open about saying that we would like to monetize those non-core assets and we'd hoped actually that 2015 was the year, we could do that. However, quite frankly Southern Louisiana continues to operate pretty efficiently for us. We've allocated a maintenance budget to them this year.

And with a small amount of dollars they're able to throw up their own cash flow and certainly keep the production flat. And so I think my response to that is at some point we will consider monetizing those non-core assets, but our attitude is they're not a physical or financial distraction to Utica.

So as long as they continue to support themselves, we're not in the position I guess that we need to give them away. Obviously, it's hard to sell that kind of an oily asset right now, though there's been some improvement in oil prices.

But at some point we may have the right environment, but again we don't need it for a liquidity event, we've got plenty of liquidity. And so we have the luxury of being patient way into the markets we cover..

And how about non-dry gas Utica acreage?.

Well, are you talking about wet gas or are you talking about on condensate? Now we're going to hang on – we're hanging on to our wet gas acreage. We like our wet gas acreage. And we do think that – hope and think that prices will recover to a point where we start developing over there again.

Now we have strategically – certainly we're letting our oil acreage expire which is not very much. We never lease much over there. And our condensate acreage generally, we're not renewing those leases, although we do have an area that we like that we're going to hang on to. But we're still trading acreage with other operators back and forth.

So there are other ways to augment your acreage package other than just letting the acreage expire. But certainly we're not going to let wet gas acreage go and certainly not dry gas acreage..

That's very helpful. Thanks. I'll hop back in queue..

Thanks John..

Thank you. Our last question comes from Stark Remeny with RBC. Please proceed with your question..

Hey, guys, congrats on another solid quarter. I guess, I was just hoping for maybe some clarification on the differential impacts. There's been some news about the TETCO pipeline explosion.

Do you guys see that as a potential uplift in 2Q or are you kind of set on your FT sales so you don't see any significant impact?.

This is Ty again. Yeah, just for clarity sake, the TETCO outage did not impact us. That was an M3 issue. We sell into the M2 market and so we continue to flow physically those molecules into the pipe and have not been affected. I think there was a lot of moving pieces with that, with the new months, with the weekend norms and all that going on.

And so maybe that created the concern. I think it's interesting to note that we had some significant outages last quarter and one of those would be Rex where they actually had a down or outage of about Bcf on a 1.8 Bcf pipe.

Gulfport, we were able to move those volumes around and it just goes to highlight the diversity of pipes that Gulfport hits, and the way to mitigate these outages as they come on and as unplanned or planned. It's just via industry. And so back to our point, the TETCO outage should not be an issue for us..

Okay, awesome.

And then I guess, kind of working later into this year and maybe touching again on 2017, how do you guys look at your wet gas or any other well backlog, do you have a price maybe in mind or is that more just a factor of your decision to reaccelerate activity overall?.

Well, certainly most of inventory is in the dry gas window. I think right now our wet gas locations that we have left to develop are only 12%. We do have some wet gas pads and we probably will complete a few of those later this year.

But in a time when capital is precious, obviously you're going to stick to your most economic windows and right now, all of our activity is in the dry gas window and that's where it will remain for now..

Okay, excellent.

And then last one for me, just kind of retouching on the spacing question, given the improvements in 2017 strip, have you guys given any consideration of moving back to tighter spacing in the dry gas area or is this something where you're still shooting at 1,000 feet?.

Well, we're certainly still at this point at 1,000 feet. But look, we're encouraged by the movement in gas prices and we'll find the right time to go back to 750-foot spacing, because we do feel like that's the right way to develop this play. But for now, we're still focusing on the 1,000-foot spacing..

Okay, excellent. Well, thank you guys very much. Appreciate the color..

Thank you..

Thank you. At this time, I would like to turn the call back over to Mr. Mike Moore for closing comments..

Thank you, Latonya. We appreciate your time and interest today. Should you have any questions, please do not hesitate to reach out to our Investor Relations team. This concludes our call..

Thank you. This does conclude today's teleconference. You may disconnect your lines at this time, and have a great day..