Jessica R. Wills - Manager, Investor Relations and Research Michael G.

Moore - President, Chief Executive Officer & Director Ty Peck - Managing Director, Midstream Operations Aaron M. Gaydosik - Chief Financial Officer

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Ronald E. Mills - Johnson Rice & Co.

LLC Jason A. Wangler - Wunderlich Securities, Inc.

David William Kistler - Simmons & Company International Drew E. Venker - Morgan Stanley & Co.

LLC Ipsit Mohanty - GMP Securities LLC Kyle Rhodes - RBC Capital Markets LLC Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.

Biju Perincheril - Susquehanna Financial Group LLLP Subash Chandra - Guggenheim Securities LLC Jeff S. Grampp - Northland Capital Markets

Thank you, and good morning. Welcome to Gulfport Energy Corporation's year end 2015 earnings conference call.

I am Jessica Wills, Manager of Investor Relations and Research. 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; 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 a full year 2015 net loss of $1.2 billion or $12.27 per diluted share.

These results contained several non-cash items, including an aggregate non-cash unrealized hedge gain of $83.7 million, a loss of $1.4 billion due to an impairment of oil and gas properties, a gain of $10 million attributable to net insurance proceeds in connection with a 2014 legacy environmental litigation settlement, a loss of $101.6 million associated with the impairment of our Canadian Oil Sands assets, a loss of $4.5 million in connection with Gulfport's interest in certain equity investments, and an adjustable tax benefit of $11.8 million. Comparable to analysts' estimates, our adjusted net loss for the full year of 2015, which excludes all the previous mentioned non-cash items, was $16.2 million or $0.16 per diluted share.

Gulfport's E&P capital expenditures and leasehold acquisitions for 2015 totaled approximately $747 million. 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 2015, Gulfport produced approximately 548 million cubic feet of gas equivalent per day and reported a $16.2 million adjusted net loss and $625.3 million of adjusted oil and natural gas revenues, approximately $361.7 million of adjusted EBITDA and approximately $338.7 million of operating cash flow. 2015 was another transformational year for Gulfport and our prudent planning for the year led to solid results, all of which were accomplished while protecting and maintaining the strong financial position of the company.

As we had hoped, our continued operational execution led to opportunities to expand our position in the Utica and, during 2015, we completed two pivotal acquisitions adding approximately 59,000 net acres in the prolific dry gas window of the play. On the cost side, our heightened focus on efficiencies throughout the year led to cost reductions across all areas of the business.

Gulfport's per unit operating cost, including LOE, production tax, midstream gathering and processing, and SG&A trended lower throughout the year, decreasing 35% over 2014 and exiting the year at approximately $1.19 per Mcfe. In addition, we substantially reduced our D&C costs per lateral foot by approximately 20%, firmly establishing Gulfport as a leader in the basin with regard to well cost, a status I am very proud of our team for accomplishing and even more proud of the reductions they continue to pursue.

Gulfport's asset base provided another year of production growth increasing 128% over 2014, driving an industry leading 83% overall increase in proved reserves. In spite of significant price driven revisions in the condensate window of the play and reductions in anticipated activity levels in the near-term, Gulfport's production growth from our dry gas position in 2015 led to a 54% increase in proved developed reserves and a 96% increase in proved undeveloped reserves over our 2014 report.

Our growth in 2015 reserves further solidified our confidence in our acreage position in the core of the Utica and strengthened the reserve base as we enter the spring borrowing base redetermination season. To provide clarity for the market and our investors, we elected to conduct our spring borrowing base redetermination ahead of schedule.

For our sector as a whole, we believe the decline in lender price decks, coupled with reduced D&C CapEx spending during 2015, will result in headwinds during this spring redetermination season. With that in mind, we are pleased to announce that Gulfport's robust reserve growth and strong hedge position enabled us to reaffirm our borrowing base.

As mentioned in our earnings release, we have received approval from Gulfport's lenders that the company's borrowing base is reaffirmed as $700 million. I think Gulfport will be one of the few companies with this outcome, and I believe this speaks to the significant strength and quality of our assets.

To wrap up my comments on 2015, we were committed to exiting the year strong. And at year-end, Gulfport's net debt-to-trailing 12-month EBITDA ratio was approximately 2.4 times, in line with the expectations we provided in February 2015.

We have a strong liquidity position to fund our anticipated 2016 activities. At year-end 2015, based on our reaffirmed borrowing base, and approximately $113 million of cash on the balance sheet, we had over $634 million of liquidity.

Our 2015 results continued to be a testament to the quality of resource we have in the Utica Shale, a basin we believe generates some of the lowest-cost molecules of natural gas in North America. I would like to applaud the Gulfport team on their ability to remain nimble as we navigated through 2015 and their dedication to executing on a program that enabled us to maintain a sound financial structure which has positioned us well as we enter what looks to be another challenging year for the energy sector.

For 2016, our core philosophy stays the same, and we continue to be dedicated to capital discipline, conservative leverage and creating long-term value for our shareholders. Our top priority was to create a plan that allows us to develop our assets while keeping the balance sheet strong and preserving financial flexibility.

As we're contemplating appropriate levels of activity for 2016, our focus was devoted towards developing a program that was efficient with our capital available while maintaining reasonable leverage metrics. Based on our 2016 capital budget, we believe our high-quality asset base in the Utica will benefit from our solid hedge position and allow us to deliver an attractive rate of return while growing production not only year-over-year, but also exit-to-exit, leaving the company well-positioned going into 2017.

So with this in mind, let's move on to the specifics of our 2016 guidance. Gulfport announced yesterday evening that our board of directors has approved a capital budget for 2016 of $425 million to $475 million, a decrease of approximately 36% to 43% from our 2015 budget.

This budget includes approximately $335 million to $375 million on our drilling and completion activities, which includes approximately $90 million to $100 million of non-operated activities in the Utica Shale largely allocated towards our joint development AMI with Rice Energy. Outside of D&C CapEx, we expect to spend approximately $30 million to $35 million on the midstream buildout associated with the joint venture with Rice and approximately $60 million to $65 million on leasehold expenditures during 2016.

In our presentation uploaded to the website yesterday evening, we have provided a map that highlights our 2016 locations and, as you can see, all planned activities will take place in the dry gas phase windows of the play. This year we expect to drill 29 to 32 gross wells equating to 19 to 21 net wells and turned-to-sales 44 to 48 gross wells equating to 28 to 30 net wells on our operated acreage in the Utica.

In addition, we currently plan to participate in two to three net wells drilled and eight to nine net wells turned-to-sales on our non-operated acreage during 2016. As we managed through this commodity cycle, Gulfport is dedicated to developing our acreage position in the near-term in a way that maximizes returns and minimizes acreage renewals.

With this in mind, our 2016 plan is to focus less on in-field development and more on minimizing lease exploration and acreage renewals through optimization of our unit development. Given the decrease in commodity prices in our rig cadence during 2016, we are shifting our development program to 1,000-foot inter-lateral spacing, which will allow us to increase the acreage held by production with each wellbore.

Although this does affect our total number of net undeveloped locations, we firmly believe this has not compromised the long-term NAV given the current commodity outlook. While this strategy does reduce inventory at the end of our development schedule in years 21 through 26, it is more than offset by a decrease in capital dollars required to preserve the opportunity set through lease renewals and incremental HBP drilling.

This is obviously something that can be reevaluated when commodity prices move higher and capital is less constrained. During 2015, we witnessed dramatically increased productivity in all phases of our operations, and during 2016 we hope to build on these, both the drilling and completion side, which could potentially lead to additional cost reductions throughout the year.

On the drilling front, to generate the 29 to 32 gross operated drilled wells, Gulfport currently expects to run an average of 2.5 rigs during the year. In addition, the non-operated activity occurring on our acreage during 2016 will equal approximately a third of a rig, bringing Gulfport's estimated total operated and non-operated average rig count during 2016 to approximately 2.8 rigs.

Regarding completions, we plan to marry up our drilling and completion pace and tailor our activities during 2016 to align with our planned operated rig count. Lastly, throughout 2016, we plan to maintain an adequate DUC inventory.

We exited 2015 with 33 gross wells in inventory, and while we will build upon this during the first quarter, until we resume completion operations in April, Gulfport currently forecasts to exit 2016 with approximately 23 to 29 gross wells in inventory. At this level of capital spend, Gulfport anticipates production to be 695 million to 730 million cubic feet per day, an increase of 27% to 33% over 2015 and an increase of 15% fourth quarter 2016 over fourth quarter 2015, placing Gulfport in a strong position going into 2017.

When we planned for 2016, we adhered to our conservative philosophy pertaining to leverage, and growth was an output, not a target. Based on our projected 2016 operated cash flows from the capital budget, at current strip prices, we estimate our net debt to trailing-12-month EBITDA ratio will remain within the company's target of two to three times at year-end 2016.

We've recently announced that Rice completed the lateral that connects two existing dry gas gathering systems on which Gulfport currently flows the majority of its dry gas volumes. The completion of this lateral provided Gulfport with the ability to end our previously announced voluntary curtailment of approximately 100 million cubic feet per day, which at the time had limited access to end markets outside of the basin.

First flow commenced on the lateral on February 1, and at that time, Gulfport began steadily alleviating the curtailed volumes. In addition, the completion of the lateral also provided Gulfport with the capacity to begin the process of turning to sales the 15 gross wells that Gulfport held in inventory that were drilled and completed during late 2015.

During the first quarter of 2016, Gulfport expects production to average 670 million to 685 million cubic feet equivalent per day. We remain committed to obtaining strong realizations, and before the effect of hedges, the company expects basis differentials to range $0.61 to $0.66 per Mcf off of NYMEX monthly settled price for natural gas.

This differential is based on our current firm portfolio and expected 2016 production using current strip prices. In addition, Gulfport expects to realize approximately $0.18 to $0.22 per gallon for natural gas liquids, and approximately $7 to $8 off of WTI for oil.

As a reminder, Gulfport's firm transportation expense is accounted for in our reported realized price. In terms of cash costs, we continue to realize economies of scale as we develop this very prolific resource and, during 2016, we anticipate per unit cost will trend lower.

Utilizing the midpoint of the ranges provided, Gulfport estimates that per unit cost will decrease approximately 14% over full year 2015. For modeling purposes, we anticipate per unit LOE, production tax, and midstream gathering and processing, to begin 2016 at the high end of the ranges and directionally move towards the low end of the ranges provided by year-end 2016.

As I stated, our main priority during 2016, while we continue to develop this world-class asset, was to maintain the strength of our balance sheet. And at Gulfport, we firmly believe that a strong balance sheet works hand in hand with a well executed hedging program.

Historically, Gulfport targets to have 50% to 70% of expected 12-month run rate total production hedged, and where we settle in the range is determined by the company's fundamental view and outlook on the commodity. Obviously, we are in challenging times today, and based on 2016 guidance and our near-term view on the commodity, Gulfport currently has nearly 80% of our expected 2016 natural gas production swapped at $3.29 per Mcf.

As you can see on slide 14 of the presentation, this level of pricing provides over a 50% rate of return throughout the dry gas phase window of the play. Maintaining a strong hedge book is an integral part of our business strategy, and our significant hedge position, not only in 2016 but also the large base level in 2017 and beyond, secures a strong rate of return for a large portion of our anticipated near-term activities, and insulates us from the current commodity price environment.

Gulfport is well-positioned to not only navigate this lower commodity environment but remain nimble to adjust our plans should there be a change in the commodity, either direction. When we entered the Utica, we were sensitive to the structure of our midstream arrangements, and the fact that all of our gathering and processing contracts are structured as acreage dedications rather than minimum volume commitments truly differentiates us from the majority of the Northeast producers.

Our sensible approach to firm commitments provides us with the near-term ability to move molecules out of a depressed in-basin market and with the long-term flexibility to adjust activity as needed as we were mindful to right-size the portfolio. Lastly, our staff continues to remain well ahead of long lead planning items, which preserves the company with the option when warranted to increase our activity levels promptly.

Our strong financial position has enabled Gulfport with the flexibility to adapt, plan and succeed in a volatile commodity environment. I would like to quickly touch on the macro natural gas market before turning to Q&A.

North American shale rig count and Appalachia rig count have decreased over 60% in the past year with less than 50 rigs running in all of Appalachia today, down from 130 at the peak. I think it is safe to assume that based on the companies that have reported 2016 plans so far and the ones who will report in the coming weeks, it is conceivable that this number will go even lower.

Although I know the industry has experienced significant efficiencies on the drilling side in the past several years, with activity across the basin drastically declining, at some point, we believe this suggests that lower activity must correlate to lower supply. Based on EIA data, it appears that in the late summer or early fall 2015, Northeast natural gas production began plateauing at around 19 Bcf per day.

We firmly believe this data suggests that the supply and demand balances will reset and when it does, producers such as Gulfport, who can achieve an attractive rate of return even at lower commodity levels, will continue to capture market share. In closing, while we certainly cannot ignore the commodity environment we face today, we feel the highest value proposition for our shareholders in 2016 and beyond is a balanced approach.

We continue to believe that the strength of our balance sheet, our current liquidity, our hedge portfolio and our well thought-out midstream and downstream strategy uniquely positions Gulfport in 2016 to not only withstand the challenges associated with the current commodity price environment but also consider our development strategy from a true pure economic standpoint. By building on the strength of our balance sheet while also living within reasonable credit metrics, we plan to continue to develop this asset in a thoughtful manner that generates the highest net asset value for our shareholders.

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

Good morning, guys. Mike, I wanted to drill down on just two slides, if I could.

First, on slide 14, could you talk a little bit about – I know you mentioned, I think, the 2.5 rig plan, I assume most or all of that will be in the dry gas east. Is that correct?

And if so, could you just discuss that slide 14 that talks about the single well economics? Does that have all-in costs?

I know versus some others that back out some things, if you could address sort of where you're going to drill and then the economics behind these wells.

Okay. Sure, Neal.

First of all, the activities that we have scheduled for this year, you're right, will be at least partially in the east window of the dry gas area, but we'll also have some activities in the central dry gas area as well. And then as far as the returns there, those are all-in costs, includes everything less G&A.

So it obviously continues to show that we have – we're able to deliver good returns. We talked about in the scripted comments our operating costs of $1.20, and our F&D costs are about $0.65, so break even around $1.83.

So we're able to deliver some good returns even at today's commodity price environment. We feel pretty good about that.

Okay. And then just lastly, around slide 18.

I like that slide where you show your basic exposure in the realized pricing. You mentioned, and I think it was on that February 2 release, obviously now you have that JV, that commencement with Rice going on, and I think it commenced on February 1.

Is that playing into this? I noticed on that slide 18 that obviously the basis impact continues to lessen into 2017 and onto 2018.

Is that based on kind of what you said, Mike, on your scripted comments about now having more choices on the end market? Or if you could just talk a little bit about the basis impact and the FT variable cost on that slide and maybe is that a result of that latest Rice or what all is that driven by?

Yeah, Neal. This is Ty.

So what that is on 18 is our firm portfolio. We feel very confident that the firm portfolio we put together, we need to show the value of that.

And so what we did was, we took 18, the slide 18, and broke that down a little bit so you can see basis impact and then our firm cost both in demand and variable. As far as our JV with Rice, it's more about reaching this firm portfolio and making sure that all the areas that we have new exposure to, new acreage on, we can reach these firm outlets.

And so, yes, it does help us get to that – but it's – to reach this firm portfolio, but that's how that's related.

Got it. Got it.

Great optionality. Thanks, guys.

Thank you.

Good morning, Mike.

Hi, Ron.

Just to drill down a little bit more on the tighter – I mean, on the wider spacing, the 1,000 feet versus the 750 feet, from an acreage standpoint or maybe a capital extension standpoint, any way you can provide some color on how much that improves from a capital spending standpoint versus acreage maintenance – and you noted that years 21 to 26 don't mean much to NAV, but that move to 1,000-foot spacing, and what would drive you back towards that 750-foot?

Okay. It's a good question, Ron.

So really what we're doing here is trying to navigate as efficiently as we can through the capital constrained market. It obviously has nothing to do with well performance or type curves.

And remember, all the scientific data that we had when we moved to 750-foot spacing indicated that the propped half-lengths were 330-foot, and that certainly seems to be evident in everything that we're seeing. But what we're trying to do, with this plan, is hold as much acreage as we can with the levels of activity that we have scheduled for 2016.

It's certainly not intended to be a permanent change to 1,000-foot spacing, but a temporary change in response to the commodity price environment that we're living in today. So we're trying to be as efficient as we can.

We did do an extensive NPV model and find that it's NPV-neutral to us. But I guess to put it, to quantify it a little bit for you, in terms of 2016, it's going to save us about, probably $30 million, if that helps.

Okay, great. And then from a just activity standpoint, or on the leasing standpoint, how was your activity driven?

Do you have particular areas whether it's Paloma or AEP or maybe some legacy Gulfport acreage with maintenance issues, or what drove the move to 2.5 rigs?

Well, Aaron, I think, can take that one for us.

Yeah. So, Ron, really as we thought about the budget for 2016, the first benefit we had was that we had a pretty strong hedge portfolio in place, so having 480 million a day, almost 80% of our natural gas production hedged at $3.29 per M was a key factor.

But really the driving factor after that was to make sure that we were working within our balance sheet, and the key focus there was making sure that our leverage metric was staying within that two times to three times guidepost range that we target. And that's what kind of results in the budget that we were looking at and really that's how we got to the 2.5 average rigs running for the year on the operated side.

Great, thanks, and congrats on the hedging all the way through 2018 that you guided.

Ron.

Hey, good morning. Maybe to dovetail on Ron's there on the hedge side and having them so far out is, is there a certain metric we should look at as what you're trying to do?

I mean, 80% this year is obviously a pretty good number. I think you're maybe pretty full here, barring a huge move in prices.

But just as we look at the rolling book, is there targets that you guys look at?

Well, I think – and Aaron can jump in here too as well. And you know us – you know us for a long time, Jason.

So you know that historically we typically are in the 50% to 70% range. And the variance inside of that range always have to do with our macro view on the commodity for the upcoming years.

And so where we're concerned, we'll hedge more aggressively, where we're less concerned, we'll hedge less aggressively. So you try to find that balance.

You do have to have a macro view. Certainly, for 2016, I think we all agree that it will be a challenging year, and it's important to have a really, really good strong hedge book to mitigate the current strip prices.

For 2017, I think we've got a really good start on a base level of hedges. I'd love to be able to tell you what percentage of our production for 2017 that that represents, but obviously I can't do that yet.

But just know that we're very focused on 2017. We hope that there might be some recovery in 2017, so we have to decide obviously internally if we want to add additional layers of hedges and at what point we do that.

So it all depends on our macro view of the commodity.

Sure. Okay.

And then just on the leasing side, is that going to be focused really around just getting the book that you already have, just kept it in place? I assume that it's just maintenance leases picking them back up versus going out and making new leases.

I think there's probably not much left out there, but just wanted a comment on that.

Yeah. We call that leasing activity.

But really, Jason, honestly, it's mostly almost all renewals. There is just not – there's not much left.

There will be a little bit to build out units of new leasing but not much. We continue to be very active on the trade front with other operators as well trying to be efficient with the acreage that we have that we may not get to right away.

So all operators, including Gulfport, certainly are continuing to trade acreage back and forth. But you can think about that number really, Jason, as a renewal extension number and not a leasing number.

Perfect. I appreciate it.

Thanks.

Thanks, Jason.

Good morning, guys, and congrats on another strong operating quarter.

Thanks, Dave.

A quick question kind of going back to the decision to move to 1,000-foot spacing and reduction in locations. You highlight that that could be temporary in nature.

What would you need to see on a pricing front to move back to 700-foot spacing?

I think, I don't know if I can give you an exact price, Dave, that makes us consider going back. Obviously we'll continue to evaluate that as we move through the year and then as we look forward into 2017.

I think we'd want to see some sustained improvement in pricing. I think we'd want to be able to make sure that we have the appropriate hedge book in place to take advantage of that.

And so if we saw things improving and they appear to be improving on a longer-term basis, certainly we're going to go back to that as quickly as we can.

And Dave, it's Aaron. Let me follow-up on that.

Price is part of it, but also just the development pace that we have, and thinking about leasehold budgets, et cetera. That's also driving our decision of what the right time will be to think about whether or not it makes sense to go back to that 750.

Absolutely. And just kind of thinking about that, at 1,000-foot and what you'll do this year, ultimately maybe that impairs going back to a certain section on 700-foot spacing.

Can you talk about the progression of how much of that inventory it might remove permanently? And maybe an offsetting question to that would be, at 1,000-foot spacing, could you look at enhancing your frac design and maybe increasing the recoveries of those wells on a 1,000-foot spacing?

Yeah. It's a good question, Dave.

And so when you think about a year's worth of activity, the number of gross wells that we're drilling, and I think your implication is you can't go back in between and put another well, so how many locations are you losing? I don't know.

Maybe five to 10 this year, Dave. So it's pretty de minimis in the big scheme of things when you consider that when we had 750-foot spacing, we had 1,300 locations.

So really not material in the big scheme of things, and again, we hope that this is relatively temporary in nature. So we wouldn't be thinking about this on a permanent basis.

Okay. I appreciate that.

Second part of that question though was, do you think you could enhance your frac designs and maybe at 1,000-foot increase the recovery so total recoverable resource remains unchanged?

Well, that's interesting because, remember, again, as I said earlier, the propped half-lengths indicated 330-foot – or 330-foot were the propped half-lengths, so listen, this is still a new play and we all are continuing to tweak frac design here and there to determine the optimal design. We all have our recipes that we like, and that's generally what we stick to.

But sure, I mean, there's always an opportunity to improve things out here. And quite frankly, in most other shale plays, the first wells weren't necessarily the best wells.

The best wells came four or five years later when people continued to improve their completion designs. So certainly that's an opportunity set for us, and our guys are certainly working on it.

We have – as you know, we have more wells drilled than anybody in the southern part of the play. We have a lot of data and we've got some different things scheduled for this year.

So we'll continue to look at that, but we have a big inventory. Keep in mind, we have a 20-year-plus inventory, so we've got a lot of time to make a lot of good wells.

Sure. I appreciate that added color, guys.

Thank you so much.

Good morning, everyone.

Good morning.

I was hoping you could just give some more detail on what the requirements are to hold leases. It sounds like it's not the conventional single well per section to hold a lease.

Well, I'm not sure of your question exactly. I'm sorry.

Say that again.

I'm just curious as to how much drilling you need on a given lease to hold the acreage. You alluded to spacing the wells wider to preserve capital, but hold more acreage.

Yeah, but we're kind of talking here about full field development versus a one-well pad design. So it's really hard to think about it that way because you have these multiple well pads, and because of that, you don't hold quite as much acreage.

So I'm not sure it's quite that easy.

Okay. All right.

Thank you.

Thank you.

Yeah. Hey, good morning, guys.

Good morning.

It seems to me that with the activity focused around the dry gas, the dry gas east window around your newly acquired acreages, the working interest is lower than prior. When we think about going forward in 2017, what is the working interest?

Does it improve beyond what you have right now or does it going to stay focused in that region of 65%, 70%?

Hey, Ipsit, it's Aaron. One thing to keep in mind is that the stuff that we are drilling today, there is a lot of focus on the dry gas east, a lot of the stuff coming online is stuff that we drilled prior, and so just kind of understand that balance as we think about the difference in the working interest.

So a lot of stuff coming online is within that Rice AMI, and so those just have, as we've talked about in the past, a lower working interest than stuff that we may have picked up as part of that Paloma acquisition last summer.

Okay. And then it could be a little far stretch right now to talk about the other windows, but just specifically on the wet gas window, which still a year back looked very good on the rate of return basis, what's the outlook in moving any activity towards that side?

I'm not sure exactly what it's going to take for us to go back to the wet gas window. The returns that we're seeing over the dry gas window, the number of locations that we have, give us a lot of running room over there.

So certainly some improvement in liquids prices condensate will help us think about that. But this – we've got to be – in this capital constrained environment, we've got to be return driven, and we have the luxury of having this multi-phase window opportunity set out here in the Utica, which I think is pretty unique among our peers.

So we can adjust our activities depending on where the best returns are, and that's what we're going to have to do until commodity prices improve.

Yeah. Ipsit, it's Aaron.

We will have a few completions in the wet gas side later this year, but that's just a function of DUCs that we had in inventory as we exited 2015. But from a pure spud point of view, as Mike mentioned, it's all about relative return, and right now the best relative return is in the pure dry gas area.

All right. Thank you.

Hey, guys. Good morning.

Just curious if you've had an estimate on the percentage of your acreage HBP to year-end 2016 assuming your base plan, and maybe if you had that by window?

Well, I don't know if I have it by window. I think at year-end, I think we have about a third held, Kyle.

We probably – until we did the Paloma and AEU acquisitions this year, that number would have been higher. But obviously, we've now got more that we have to take care of, but probably about a third.

That's at year-end 2015 or year-end 2016?

Year-end 2015, and I don't have an estimate for year-end 2016, in case you're going to ask that.

Okay. Got that.

And then, I guess, I think you may have addressed this in the prepared comments, but just wanted to make sure I had this right; as you guys shift more activity over to the dry gas area exclusively, is there anything we should be aware of in terms of minimum commitment (41:01) volumes in your wet gas or condensate areas? Or is that not an issue for you guys?

This is Ty. I think the thing to highlight there is that in the deals that we've done, we've been able to obtain anchor status, which affords us the most competitive rates out there in the area in the basin, as well as a structure that we prefer, which is the acreage dedication, which allows us to drive decisions based on economics and have that flexibility around that as opposed to trying to fulfill or catch up to a minimum volume or take-or-pay type arrangement.

Yeah. And Kyle, just to reiterate, from the very beginning, we were extremely focused as a corporate strategy/philosophy that we not burden the company with minimum volume commitments, so that we can do what's best for the shareholders in regards to our joint activities so we are not committed to filling commitments with uneconomic volumes.

So we feel very, very good about our ability, our good fortune and strategy of avoiding those minimum volume commitments.

Great. Appreciate it, guys.

Thanks.

Thank you.

Good morning. Thanks for taking my questions.

Just a few follow-ups on the spacing. Can you talk about how you arrived at the 1,000-foot number instead of something wider that may have potentially allowed you to go back in infill?

I know it's temporary in nature, but just wondering if that carried any weighting in terms of the decision to go to 1,000 as opposed to something wider?

No, it really didn't. We were given up so few locations with the 1,000-foot spacing.

It just didn't feel like wider – wider spacing that we could eventually go back to was really that material. So we did not consider going to wider spacing.

Okay, thanks. And then, you mentioned development pace also driving the spacing decision.

Just thinking about the CapEx range, should we think about that as purely driven by only timing? Or is it more like the pace and the timing are driven by commodity prices?

So if prices are kind of towards the high end of whatever bands you may use in setting your budget, would you spend towards that high end? Or is that the range for the overall CapEx number pretty agnostic to commodity price at this point?

Well, if you think about 2016, maybe it just depends on your time horizon, and it's Aaron talking. For 2016, things are pretty set.

We like our hedge book. We like where we are, but we've thought a lot about the plans and so that we feel pretty good about that.

Thinking for 2017 and beyond, as Mike mentioned earlier, part of it is commodity prices, but part of it is also just a function of what level of rate activity makes sense to stick within our leverage goal posts. So that's kind of what's driving our decisions over the longer term.

Hey, Jeoffrey. Just one comment I want to add to make sure that I clarify, because it is an important comment.

Remember, we have found historically that it doesn't work to go back to an existing producing pad. So from a spacing perspective, it doesn't really matter if it's a 1,000-foot or 1,400-foot, it's really inefficient to go back.

There's too much risk. And so it's good operationally, it's not good for the reservoir, and so there's a lot of reasons we'd not go back.

As you recall, early on in the play, we were going back to the pad and drilling additional offset wells, and it just doesn't work very well. So that really wasn't a consideration.

Okay. Thanks a lot for the detail.

Thank you.

Hi, good morning. Thanks for taking my questions.

Mike, I was trying to understand is the lease renewal needs, is that tied to infrastructure buildout as well? I'm trying to understand, if you're able to add a rig or two, how should we think about the lease renewals dollars going lower?

Yeah, I'll talk a bit. And then I'll have Ty jump in here as well, but the answer is no.

It's not tied to infrastructure. Ty's done a good job of making sure that we stay ahead of that.

And so we've never been in a position where we can't develop acreage or we can't turn on our wells into sales lines when we're ready to do that. And that's just by a lot of strategic planning and foresight, but I'll let Ty comment here as well.

Yeah, this is Ty. I'd just add to that that we work when we go out and look for these partners that we're going to develop on the Midstream site, one of those prerequisites is that we can work to make sure that we are efficiently getting tied to the areas that we need to get tied to.

And we're working on, if not a weekly basis, it's almost even a daily basis to make sure again that there are no wells waiting on pipe. So it's a big focus for us on the Midstream side.

Yeah. What you don't see or know is, there are long lead times in activity plans that we have so that we can work with our midstream groups and make sure that they understand where our planned activities are going to be and give them plenty of time to build out everything.

So we are having conversations, for instance, about 2017 already. So those are some of the things that go on behind the scenes that you guys don't always see.

Got it. So I'm sure you guys have looked at – when looking at your HBP needs, drilling single wells per section versus these multi-well pads, and is the reason not to drill the single well pads because of what you just talked about I think in the previous question about going back and drilling offset wells?

Yeah. Again, it's the same answer.

It just doesn't work. We don't think it works to go back and infill.

It's not good operationally. It's not good from a reservoir perspective.

We found out, Biju, as you remember early the hard way that it's just a very, very efficient way to do it. So while it sounds good in theory to try to hold acreage that way, from an operational standpoint, from a reservoir standpoint, it just doesn't work.

Okay, great. Thank you.

Thank you.

Yeah. On the density question, I guess my understanding was that you want to optimize that day one, just because it's so difficult to come back and do the proper density or infill density because of communication between wells.

Is that a risk that's overblown in this case? So if geologically you can do even denser than 750, that would be very difficult to achieve once they're drilled on 1,000?

I think if you look at some of our early wells, you'll see that it's not overblown. It's a real operational risk.

And so we've drilled enough wells that we know it just does not work, from a reservoir perspective, from a communication perspective operationally, and so it may seem illogical to you, but because of this particular rock communication system, it just doesn't work.

Okay. This answer might be obvious, but are there any sort of ways to optimize value in this environment from Grizzly or Mammoth or South Louisiana?

I think, you're right. The answer's probably obvious.

Listen, we'd love to be able to monetize those assets. I don't think this is the environment to do that.

We are having some discussions and thoughts on what to do with Grizzly. Certainly there's some value there.

We just need to figure out how to extract it and at what commodity price we can extract it. But Southern Louisiana is a little different because it does generate its own cash flow for its own activities.

So it's not a physical or financial distraction to Utica. And as long as we can do that, as long as we can have a maintenance CapEx program in Southern Louisiana and they're using their own money for their activities, we're okay with that.

And we can hold production, we hope, mostly flat in doing that. And I think the answer is, the short answer is, we're going to have to wait for some commodity price improvement before we're able to think about monetizing either one of those.

Okay. And final one for me.

Can you remind me what the offset rules are in Ohio? Is it 500 feet off the lease line?

That's right, 500 feet off the lease line. Correct.

Great. Okay.

Thank you.

Thank you.

Good morning, guys.

Hi, Jeff.

More of a, I guess, housekeeping one on the 23 to 29 gross DUCs you guys expect to have at the end of 2016. Do you have a net on that or maybe spill it between operated versus non-operated?

Yeah, we have. I don't think we have a net.

We have the gross. I'm sorry, Jeff.

Gross is all I have with me today. I don't have net.

Okay. That's fine.

And then, more on the...

You can follow up offline if you want.

Sure, will do. And then, on the – I noticed the Utica net acreage was down maybe about 10,000 or so from your last update.

So I guess, kind of two-parter. One, just kind of wondering, should we expect some future kind of leakage as you guys maybe let some condensate or kind of non-core stuff expire?

And then, on the CapEx side and leasehold dollars, should we expect there – that to be a fairly recurring expenditure for the next couple of years as you guys maybe extend or renew some things that you want to retain?

Yeah. I think that's a good – I'm kinda back in to your question – that's a good number, I think, to use for the next few years, Jeff, as you think about our renewals and extensions.

The 10,000 less acres are oil and condensate expirations quite frankly that we decided not to renew. And then there's a little bit of trading activity where we're maximizing our acreage positions by trading acres back and forth, and there may be cases net-net where you lose a little to gain better acreage.

So it's a combination of the two.

Okay, perfect. And then just last one for me on M&A.

I don't think it's been hit on too much here. Is it fair to say that given what you guys are doing in terms of the wider well spacing and allocating some dollars to renew and extend that – the bar is probably pretty high for you guys for deals that make sense.

Just given that it seems like you guys would probably be unwilling in this market to take on any acreage with any meaningful drilling commitment. Is that kind of a fair statement or accurate of how you guys are looking at things?

Well, I'd say, drilling commitments are – I guess, I don't mind taking on drilling commitments as long as they're minimal. And when we got the AEU acreage, obviously we had a 10-well drilling commitment with that per year, which is easy to do.

Drilling commitment is something certainly that you have to pay attention to on M&A opportunities. But there's a lot of things you have to look at as well.

Is the acreage core? What's the renewal term?

I think if we took on acreage that has drilling commitments, it would have to have meaningful reserves and production which would encourage us to have higher activity levels.

All right. Great.

Thanks for the color.

Thanks, Jeff.

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This concludes our call.