Jessica R. Wills - Gulfport Energy Corp.

Michael G. Moore - Gulfport Energy Corp.

Rob Jones - Gulfport Energy Corp. Mark Malone - Gulfport Energy Corp.

Ty Peck - Gulfport Energy Corp. Aaron M.

Gaydosik - Gulfport Energy Corp.

Jason A. Wangler - Wunderlich Securities, Inc.

Ronald E. Mills - Johnson Rice & Co.

LLC Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

David A. Deckelbaum - KeyBanc Capital Markets, Inc.

John Nelson - Goldman Sachs & Co. Holly Barrett Stewart - Scotia Howard Weil Jeffrey L.

Campbell - Tuohy Brothers Investment Research, Inc. Pearce Hammond - Piper Jaffray & Co.

Kyle Rhodes - RBC Capital Markets LLC

Thank you and good morning. Welcome to Gulfport Energy Corporation's third 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; Mark Malone, Vice President of Operations; Paul Heerwagen, Vice President of Corporate Development; Rob Jones, Vice President of Drilling, 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 condition, results of operations, plans, objectives, future performance, and business. We caution you that the actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors.

The 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 to our website. Yesterday afternoon, Gulfport reported a third quarter 2016 net loss of $157.3 million or $1.25 per diluted share.

These results contain several non-cash items, including an aggregate non-cash derivative gain of $22.4 million, a loss of $212.2 million due to an impairment of oil and natural gas properties, a gain of $3.8 million attributable to net insurance proceeds in connection with a 2014 legacy environmental litigation settlement, a gain of $6 million in connection with Gulfport's interest in certain equity investments, and an adjustable tax benefit of $0.6 million. Comparable to analyst estimates, our adjusted net income for the third quarter of 2016, which excludes all the previous mentioned non-cash items, was $20 million or $0.16 per diluted share.

During the nine-month period ended September 30, 2016, Gulfport's D&C capital expenditures totaled $369 million, midstream capital expenditures totaled $4 million and leasehold capital expenditures net of proceeds from leasehold sales totaled approximately $10 million. An updated Gulfport presentation was posted yesterday evening to the 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. Good morning, everyone, and thank you for listening in.

As announced in the press release yesterday evening, during the third quarter, Gulfport reported approximately $20 million of adjusted net income on $171.3 million of adjusted oil and natural gas revenues and generated approximately $94.7 million of adjusted EBITDA. Gulfport had a solid third quarter across the board, demonstrating our commitment to deliver on the expectations provided to our investors and the Street.

We reported strong third quarter production of just over 734 million cubic feet of gas equivalent per day, ahead of our previously issued guidance of 685 MMcfe to 705 MMcfe per day and representing a 10% increase over the second quarter of 2016. This increase was driven by strong well performance, minimal downtime and our 20 net turn-in-lines during the third quarter.

Continuing with this momentum, during the fourth quarter, we expect to be well in excess of our previously provided exit rate growth of 15% and currently forecast production will average approximately 765 million cubic feet to 790 million cubic feet of gas equivalent per day. This level of production equates to an exit rate growth of approximately 19% to 23% fourth quarter 2016 over fourth quarter 2015 and should put us right above the midpoint of our previously provided full year 2016 production guidance.

To provide some additional color, I would like to turn the call over to Rob Jones and Mark Malone to further discuss our third quarter results and give an update on our current operations.

Thanks, Mike. Good morning, everyone.

This is Rob. During the nine months period ending September 30, we invested approximately $369 million on drilling and completion activities, largely allocated to our ongoing activities in the Utica Shale.

The Gulfport team has remained focused on improving efficiencies in the field and we continue to benefit from improved cycle times, longer laterals and further well cost reductions. On the drilling front, during the third quarter, we drilled nine gross wells, bringing the total number of drilled during the first nine months of the year to 31 gross wells.

From January 1 through September 30, the wells have averaged a lateral length of 8,520 feet and an average spud to rig release of 25 days. Well costs for the last two quarters have been the lowest since inception.

All recorded drilling metrics are trending in the right direction as compared to our 2015 results. As we stated on our second quarter call, we signed up a fourth drilling rig, which began operations during the month of September.

This rig is sourced from the Bakken Shale with little mobilization costs to Gulfport. Sourcing specialty shale rigs and quality crews from other basins enhances the overall set of equipment available in Appalachia.

And this has been critical as we continue to push the limits on lateral length. In addition, the team continues to plan and make accommodations for incremental activity expected in the near future and has multiple high spec rig options as we possibly look to expand our fleet.

Now I'll turn it over to Mark.

Thanks, Rob, and good morning. On the completions front, efficiencies and cost savings are comparable to what we're seeing on the drilling side of our operations.

During the third quarter, as planned, Gulfport brought online a record number of turn-in-lines totaling 21 gross operated wells in the Utica Shale and completed some 1,350 stages. During the nine-month period ended September 30, Gulfport has turned-to-sales 43 gross wells with an average lateral length of 8,485 feet and completed these wells at just under nine stages per day, which, to my knowledge, is well ahead of our Utica peers and demonstrates the benefits of our vertical integration strategy.

We're continuing to adopt new technologies as they become feasible. For example, we recently began employing a rig-less toe-prep technology that has enabled us to cut our pre-frac well prep cost by more than 50%.

Incorporating the drilling and completion efficiencies that were just mentioned by Rob and I, we estimate that during the first nine months of the year, Gulfport's well cost has averaged approximately $1,085 per foot of lateral, trending approximately 5% to 10% below our budgeted estimate of well cost and the number is presented in the slide deck. The efficiencies and cost savings we're seeing on the operations front are also being realized in the income statement for our per unit lease operating expense.

In the third quarter, LOE totaled approximately $0.26 per Mcfe, down 12% over the third quarter of 2015, largely driven by the team's initiatives to reduce water disposal, water disposal cost, labor costs associated with more reliable facility design and our continued focus on driving down cost of services in materials. Looking ahead, we remain committed to further optimizing the efficiencies within the field over the last two years, further identifying opportunities to reduce costs and continue to push the technical limits of our operations.

Thank you for the time today. And I'll turn the call back over to Mike.

Thanks, Mark. I would like to applaud our drilling and operations team as they remain focused on identifying ways to drive our KPIs in favorable directions and our overall cost structure lower, improving margins and adding significant value with each dollar that we invest.

As we look to add incremental activity and increase our total amount of invested capital, we remain focused on locking in the long-term benefits of today's low-cost environment, providing an operational edge on the key components of our business. To ensure we continue to see consistent well cost reductions, I am pleased to report that we have locked in approximately 70% of our drilling and completion costs at attractive terms for the remainder of 2016 and 2017, mitigating the risk associated with an increasing commodity price backdrop.

In addition, securing these services goes beyond protection against inflationary pressure, but also provides Gulfport access to consistent quality services, which we believe will aid in further efficiency gains and complement our overall growth profile. Our midstream and marketing group continues to work towards optimizing our current firm portfolio to enhance the value received for all of our products.

Reflecting this, Gulfport's blended average realized price during the third quarter before the impact of derivatives and including transportation cost averaged approximately $2.35 per Mcfe. I will now turn the call over to Ty to provide our detailed third quarter realizations and discuss the status and outlook on our gathering system development and interstate pipeline build-out.

Thank you, Mike, and good morning. On the realizations front, before the effective hedges, our oil and NGL realized prices during the first nine months of the year have come in as expected.

And we reiterate our expectations for 2016 and currently expect to realize approximately $5.50 to $6.50 off of WTI for oil and $0.25 and $0.29 per gallon for NGLs during 2016. Gulfport's year-to-date realized natural gas price before the effective hedges and including transport costs have settled approximately $0.63 per Mcf below the average NYMEX price.

And we reiterate our full year average basis differential guidance of $0.61 to $0.66 per Mcf off NYMEX monthly settled prices. Gulfport remains committed to delivering strong realizations and believe that our disciplined and diversified portfolio approach to both markets, term and structure will continue to allow our molecules to price favorably relative to the peer group.

In the near-term, we continue to utilize our firm commitments to price the majority of our molecules out of the basin and believe we have rightsized the portfolio in conjunction with our anticipated growth profile. We believe the challenges facing Appalachia Basins today will be alleviated once the numerous capacity projects come online.

And we are of the opinion that this incremental capacity announced to move volumes out of Appalachia is no longer a question of if, but now a matter of when. While it seems like Nexus and Rover receive all the headlines, we feel confident that approximately 3 Bcf per day of capacity, which includes Rex enhancement, multiple TETCO expansions and Columbia Leach/Rayne XPress, remain on schedule with their publicly provided in-service dates.

When you include Rover and Nexus as well, we estimate 6-plus Bcf a day of capacity will be placed in-service between now and year-end 2017, all three sourced with local production, providing the significant uplift to Appalachian pricing and validating Gulfport's view on the structural improvement of the in-basin differential over the long-term. Looking towards next year, assuming the current strip, we estimate our differential will be similar in 2017 to 2016 with potential to improve.

And our in-basin exposure will be less than 5% of our 2017 forecasted production, which includes risking the announced in-service dates of our incremental firm capacity. That said, we continue to actively monitor all of the major pipeline expansions out of the Northeast, adapting and capitalizing on opportunities created through the ever-changing flow dynamics within the basin.

With regards to our gathering and compression activity, as we discussed in our second quarter call, Gulfport installed pad level compression on a select group of wells during the third quarter to validate reservoir response to decrease line pressure and aid in the size of our large scale field level compression. As expected, we achieved a forecasted sizable improvement resulting from the targeted pressure drop within the isolated portion of our Larue (13:02) area and field level compression remains on target to begin phasing in around year-end 2016.

Meanwhile, on the gathering front, as we look to increase our activity in the near-term, we have worked very closely with our third-party midstream providers to ensure that we remain well ahead of our long-term lead items associated with the buildout of our dry gas gathering systems. Gulfport continues to benefit from teaming up with reliable midstream partners.

And we remain confident in their ability to construct the necessary infrastructure to remain on target with our planned operations and tie-in dates under the either rig scenario provided on the August call. I will now turn the call back over to Mike.

Thank you, Ty. As you can see, operationally, we are hitting on all cylinders.

As our continued efficiencies and economies of scale are driving operating cost lower, we are also seeing per unit corporate cost decrease, further expanding our overall margins and bolstering returns. Our goal remains unchanged, and we continue to work to become the lowest cost producer within the Utica Basin.

During the third quarter, per unit G&A expense totaled approximately $0.15 per Mcfe, down 16% over third quarter of 2015 and 21% sequentially. In addition, our interest expense was approximately $0.19 per Mcfe, down 20% over the third quarter of 2015 and 29% sequentially.

Our total levered per unit cost, which includes LOE, production tax, midstream gathering and processing, G&A and interest, totaled $1.33 per Mcfe and is down 11% over the third quarter of 2015. We believe that this has additional room to trend even lower as we realize economies of scale from our planned incremental activity and as our volumes grow within the dry gas areas of the play.

I am very proud of the continued hard work and commitment of all our teams across the organization who came together to deliver our strong results. And it leaves me very encouraged by the momentum we have created as we head into 2017.

With regard to our 2017 capital outlook, while we have not yet finalized the specifics of our anticipated full year 2017 program, we continue to refine our thoughts surrounding the potential six and eight-rig scenarios provided on our second quarter call. As the world sits today, given our hedge position and where commodity prices are currently trading, we feel confident in establishing a six-rig program as a base level of activity for 2017 with the potential to add additional rigs throughout the year.

Rigs five and six have already been contracted with rig five moving to location as we speak and rig six scheduled to begin operations in December. The current plan is to provide formal 2017 guidance after the first of the year once we've had a good initial look at supply/demand balances as we head into the winter following a year of remarkably low activity levels across the industry.

So while we're not providing specific activity level guidance today, we do feel very comfortable communicating that a six-rig program represents a minimum level of activity for us during 2017. As we think about 2017, with respect to our hedge portfolio, we are very cognizant of the fact that our 2017 activities provide a meaningful impact to 2018 volumes.

We have put in place a solid base of hedges and currently have over 50% of 2017 expected production hedged at approximately $3.12 and a solid start to building out the 2018 position. Given the current supply levels and the demand expectations as we enter the drought season we see an increased opportunity as we head into the winter months to expand our hedge portfolio, locking in a more meaningful level of cash flows for our 2018 activity, mitigating our risk and further securing a portion of our expected returns.

Our philosophy of maintaining a strong hedge book is an integral part of our business. We view hedging as a risk mitigation tool, not a profit center, and maintaining an active hedging program is key to supporting the long-term development of our assets.

Our strategic commitment to the balance sheet has provided us with the ability to pursue our 2017 growth plan. And I would now like to turn the call over to Aaron to provide more color on the financial state of the company.

Thank you, Mike, and good morning. As it sits today, I believe the balance sheet has never been stronger and our continued dedication to preserving the financial strength of the company has resulted in a strong liquidity position that we have today.

As of September 30, Gulfport had approximately $365 million of cash on hand and our revolver of $700 million remained undrawn. Our total liquidity of over $850 million provides Gulfport with significant flexibility and uniquely positions Gulfport from a balance sheet perspective to adapt quickly as we look to carry out our future plans and increase activity as we enter into 2017.

We remain strong in our commitment to funding our 2017 activity through operational cash flow and available sources of liquidity, while also maintaining reasonable leverage metrics. At today's strip, Gulfport generates a very healthy cash flow profile next year.

And assuming our current contemplated activities for 2017, we would expect to remain at the low end of our leverage target of 2 times to 3 times debt to trailing 12 month EBITDA. We're always focused on augmenting the strength of the balance sheet in all areas of our business.

And subsequent to the third quarter, Gulfport issued $650 million of 6% senior notes due 2024 with proceeds used to repurchase all of our outstanding 7.75% senior notes due 2020. This transaction reduces our annualized interest cost by approximately $5 million and manages any near-term maturities, further strengthening the balance sheet to allow for financial flexibility as we finalize our future development plans.

Lastly, Gulfport recently contributed its 30.5% equity interest into the Mammoth Energy Services initial public offering. And, as of October 19, Mammoth is trading on the NASDAQ under the symbol TUSK.

We're very pleased to see this investment go public and believe that our strategic ownership in Mammoth to mitigate our operational risk through vertical integration has proven to be an accretive investment for Gulfport shareholders and will continue to add value as commodity prices improve. With that, I will now turn the call back to Mike for closing remarks.

Thank you, Aaron. In closing, I believe the message that we delivered today validates a number of reasons to be confident about investing in Gulfport Energy.

Our proven execution, established team, solid balance sheet and overall platform allow us to take advantage of the unique high-quality asset that we have in the Utica at a time when the macro environment is working in our favor and the natural gas market is improving. We have worked diligently to mitigate a significant amount of the potential risk that coincide with ramping activity and increasing commodity prices.

We have locked in 70% of our expected well costs, vertically integrated key areas of our operations, secured a large baseload of hedges and continued to optimize our diversified marketing portfolio around project timelines. Lastly, as we have looked to ramp activity, we have remained conscious of keeping a sound balance sheet.

Our equity offering completed in March and the refinancing of a portion of our senior notes enable us to fund our anticipated 2017 drilling and completion activity without going to the capital markets. This concludes our prepared remarks.

Thank you again for joining us for our call today. And we look forward to answering your questions.

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

The update. Mike, as you add the fifth and the sixth rigs, could you just talk about your thoughts on where that six-rig program goes throughout the year next year?

Is it really just focused dry gas or just maybe some indications of what you see that way?

Yes. Our current plan obviously is to allocate almost all of those rigs to the dry gas window.

I think as it stands right now, we have three-quarters of a rig allocated over in a wet gas window. But obviously we're going to be focused on the dry gas next year.

And, I guess, just similar to that question as you look at obviously trying to focus on pad drilling but having some acreage holding as well. Just how you see that playing?

I guess could we look at it at the same way as far as how many rigs are drilling on pads versus maybe holding acreage or how you think about that?

I'll let Rob and Mark jump in too, if they'd like. But, listen, holding acreage is something that we're all focused on for the next few years.

So, certainly, we have to consider the acreage that we need to hold. So we have adjusted.

In some instances, we will be adjusting our program a little bit, so that we can hold as much acreage as possible. So you will see us doing things like, in some cases, maybe some senior well units and then some other things as well.

But, certainly, we have a plan to hold all of our acreage under a six-rig scenario, under a seven-rig scenario over the next couple years. So we're a little further ahead in some of our peers out here.

So we don't see holding acreage – the acreage that we want to hold as a problem for us, Jason.

That's great. Thanks.

I'll turn it back.

Hey, guys. Couple questions.

A little bit of a follow-on maybe to Jason's. But you talked about selling so much Virginia acreage and adding to Ohio both, I think, upfront activity and also acreage.

Give a little bit of a lay of what you're able to accomplish here? Are you adding acreage in and amongst your current locations and potentially allowing for longer laterals?

Is that part of the process?

Well, certainly, Ron, we are seeing opportunities for bolt-on acquisitions over in the Ohio Utica where we're focused. And, quite frankly, over the next two years to three years with lease expirations, there's quite a bit expiring among all of us out there.

Obviously, we're going to hold ours. We do see opportunities.

Most of it will be bolt-on type opportunities that yes indeed will help us build out our units in a different way and potentially allow us to drill longer laterals. When we come out with our final 2017 plans, you're probably going to hear us talk about lateral lengths that are longer than you've seen historically.

And part of that is because of the opportunity set that we have out here. And really I just wanted to make a comment on the West Virginia sale.

Really this is about taking the money that we had invested over there and putting it back where – in an area that we have known returns. Acre for acre, we're getting full-term acreage versus acreage that had a couple years into its expiration.

We have known infrastructure over in the Ohio Utica, so infrastructure could or could not be a problem obviously over in the West Virginia development. And so really we're just high-grading our portfolio, taking the money over to an area that we feel like we're going to have an opportunity for some bolt-ons.

Okay. And then you started to touch on it.

Another question was going to be versus the 8,000 or 8,100 foot laterals, looking ahead, do you think you would be able to – is that going to extend out and from your prior answer we should expect to wait until early next year to see how your lateral lengths look through the 2017 program?

Yes. I think, Ron, if you look back historically to our development of Utica, what you saw was our commitment even early on to drilling long laterals, even our first wells.

And so, I think, also if you look back you'll see that each year our laterals have gotten longer and longer. And that has to do obviously not only with the ability from a technical perspective to go out further, but also it has to do with continuing to add to our acreage in a bolt-on fashion and continue to drill longest lateral possible.

I think we all agree that longer laterals are better. Now, there are technical limits.

And so, in some cases, there are reasons you can't go too far but we'll continue to push the window on that as much as we can.

Okay. Great.

And then last question. On the contract standpoint, sounds like you contracted or have agreements now on the rig side to get you through the end of 2017 and through your vertical integration via TUSK, et cetera.

Is that the same across all the services in terms of protecting against potential increases or are you starting to see some pressures in particular areas?

Ron, that's a great question, but I think I'll let Rob and Mark take that one.

Thank you, Ron. This is Mark Malone.

We aren't seeing service cost increase in our area. We do believe we saw prices reach bottom in 2016.

For that reason, we've been actively soliciting extended terms from selected quality service. And so we're securing contracts and letter of agreements for services increase for all of 2017.

Yes. This is Rob as well.

Gulfport has maintained drilling activity in the Utica play since 2012 and now that this kind of consistent activity makes Gulfport a coveted client for many providers. We can provide service companies with continued work commitment and return Gulfport secure great pricing and high quality crews with knowledge of our processes that continue to drive efficiency and safe operations.

Multiple companies will also provide additional discounts with a promise of additional workload.

And so, Ron, I guess, to follow-up to that. We've been working on this for some time as we developed our view fundamentally on 2017 and what made the most sense for us.

And so, I think, Rob and Mark have done a great job of locking in our services, not only our major services that we need, but also smaller services and supplies as well. So I talked about 70%.

I think you're going to hear us talking about probably something higher than that by the time we get to early next year and we talk about our final plan. So we're doing that to take risk off the table post-creek (29:51).

Obviously, as rigs get added back, there is always the potential for prices to start going up. So it's just actually another way to mitigate our risk just like we do with our hedging program.

Great and thank you so much.

Thank you.

Good morning, guys. Nice quarter.

Say, Mike, just a follow-on just to Ron's last question, just on well costs in general. I was looking at that slide 15.

Could you maybe just comment a little bit further then? Are you saying that – I think you saw it on a per foot basis there when you break it out between your condensate areas, your wet gas and then your three dry gas areas on a per foot.

How you see that maybe today and going forward? Are you saying that most of that should be locked in or maybe just what's your suggestion around that versus what we're seeing on those slides?

Yes. That's a good follow-up.

I should have covered that in Ron's question. But, as mentioned on the call – on the scripted comments, Rob and Mark have gotten our costs down to $10.85 a foot.

And you'll admit – you've got to remember that most of our activity this year – in fact, almost all of our activity this year has been in the dry grass window. So if you compare that to cost per foot in the slide, we've made a lot of strides this year to get our well costs down.

And I think we can continue to do that as well. I'll turn it over to Mark and Rob to add some additional colors also.

This is Mark again. We've taken advantage of the service costs over the lower market in 2016.

As mentioned, Rob and I have been involved in completion activity for about 30 years now. And I don't think we expected to see the bottom of efficiencies that we can gain through completions and drilling activities.

So it remains our focus to drive down costs with each well drilled. And while operational cost issues do occur, cost reductions come in many forms.

Yes. This is Rob.

I'd add to that. We're currently at a point that we think we're extremely efficient on our operations.

Our focus now turns to optimizing that efficiency. Primary cost reductions come through many things, activity levels, pricing through scale, certainly redundancy of operations that creates speeds through knowledge of operations and relying on our experience to minimize costly mistakes.

We also continue to review new technologies. These technologies focus our efforts and utilize the best applications.

Examples include recently we've been experimenting with smart starts that eliminate our TCPs. And we've been doing some hybrid batch drilling to eliminate a bunch of fluid swapping when we go from air to mud.

So – sorry about that. Mark, something else?

No. I was just going to add that we're honing in on specific operations as well.

Facilities is a good example. We've recently created a facilities department that's focused on construction costs, offsite assembly, equipment rotation and then some go forward specific designs.

All of these things over time will equate to additional savings.

Great color guys. Just, Mike, one last follow-up.

I guess given what you mentioned, Mike, now about the hedges, now about the costs, as we look into 2017, I mean what uncertainties do you assume? It seems to me like most – I mean you've got the cost locked in.

You've got the hedges locked in. I'm just trying to think uncertainty-wise or volatility-wise maybe what keeps you up at night?

Neal, it's interesting because obviously we have a situation here where we have warmer weather later into the fall, delayed winter. Fundamentally, with all the work that we've done, we certainly don't see anything that's changed from a fundamental standpoint.

I think the only thing that we have going on here is a little bit of a delay to winter. Weather forecasts are that winter is going to show up.

It's going to be very cold once it gets here. So, as you pointed out, we've locked in a good hedge book for 2017.

We have mitigated cost increases through locking in over 70% on the cost side. We have a great FT portfolio which allows us to move 95% of our product out of the basin.

So we've worked really hard to minimize our risk for 2017. And so that's what gave us the confidence to add the fifth and sixth rig now when we have the opportunity to do that.

Rob was getting calls from folks who had equipment and it was the equipment we wanted with the crews that we wanted. And so with all that taken together, I think, it gives us the confidence that six-rig is a great base program for next year.

I am not saying there is no risk, but we've certainly taken a lot of risk off the table.

Thanks, Mike. Great details and nice quarter.

Thank you.

Good morning, everyone. Thanks for taking my questions and nice quarter.

Actually I wanted to follow-up on some of the discussions around the cost per foot savings. Next year, I guess, when you look at the mix of sort of a base case six-rig program, how much more incremental savings could we see on a cost per foot basis just from going more into pad development or, I guess, what's the mix of multi-well pads in 2017 versus what it would have been in 2016?

Well, I do think there is room for improvement, but you've got to keep in mind that we've been in pad development now for some time. So I wouldn't necessarily say that's going to be a driver for us.

We've been trending lower throughout the year. Mark and Rob are working hard to continue that trend.

We haven't built any of that yet into our forecast for 2017. So I think when you hear us talk about our final plans, you'll probably hear us talking about different kinds of well cost for 2017, but – so that's some upside yet to come in the way that we talk about 2017.

Mark, Rob, would add anything to that?

Oh, I'd just like to reiterate the comments made earlier that we're continuing to focus on efficiencies and we run a pretty efficient operation. We've been focused on efficiencies for the last couple years.

And, as Rob mentioned, now we're trying to optimize those efficiencies. We're also employing new technologies.

We're going to make sense of couple of items that Rob mentioned. So we continue to look at opportunities for new technologies to apply and operational efficiencies that we can optimize.

So I think we'll continue to see cost savings as we go forward outside of those secured through just service pricing.

I appreciate that. Mike, just one more.

I know lots have been asked already, but just on the confidence in the six rigs and looking at the eight-rig program. I assume there is plenty of equipment that's available out there.

But, as we get into winter, if things look bullish, what percentage volumes would you want to have hedged for 2018 before pursuing a more aggressive ramp or is that not necessarily a requirement in your risk mitigation if you feel like you have some decent tailwinds behind you on the macro side?

Well, if we're talking about a hedge book for 2018 then certainly – and you can see this historically as well. We would want to be probably 50% plus hedged by winter end 2018.

So we definitely would want to build a little more robust hedge book as we think about 2018. As we get into 2017, I've talked about the fundamentals and how we think about 2017 in our risk mitigation.

Keep in mind that unless we add a rig, a seventh rig or an eighth rig by March or April of 2017, we're not impacting production for 2017. We're really impacting production for 2018.

And my point in saying that is we could add CapEx by adding rigs, but not production. So you've got to make sure that we can fund that with the sources that Aaron mentioned that we like to use which are cash flow and liquidity that we have on hand and cash on hand.

So, that's one thing. And in my earlier comment, by the way, I would want 2018 hedged by winter in 2017.

I think I said 2018, so I stand corrected there.

I appreciate that. And just one other quick one.

Just you talked about the eight-rig scenario. Where do you guys model like your peak development in terms of rigs for the acreage that you have now?

We have a lot of different iterations of development thoughts and ideas. I'll let Aaron jump in here.

Really, David, I think, we've talked about in the past and it's consistent. As we look forward at the strip, looking at the balance sheet that we have, having the leverage targets that we've got, I mean staying within the leverage goalposts and making sure that we have more than ample liquidity to fund a program, that's what drives that development cadence.

And then, as Mike mentioned, it's not just a forward year price deck. It's also a multi-year price outlook, because, as we discussed, we have a very strong focus on hedging to lock in economics and cash flow to fund that program.

Thanks for the color, guys.

Good morning and thank you for taking my question. The last week or so notwithstanding Dominion South prices have actually been pretty weak to start the quarter here.

I believe all of your 4Q turn-in-lines are in the dry gas fairways. So I guess my question is just given that price weakness, will that be impacting your decision at all to maybe make those completions a little later in the quarter?

Hey, John, this is Ty. I think the point is that we have a good firm portfolio.

Yes. We've seen the prices drop from NYMEX, but they're actually coming back, I think, in this quarter.

But it's here regardless. We're going to flow under our firm portfolio and prices will be reflected as we guided to earlier this year.

So no risk as we think about production for the quarter?

Yes. I guess if you're looking at – yes, as far as if you're looking at fourth quarter that's the way it is.

And as far as 2017, if you're asking about that, then as we said in the scripted comments 95% of our production is going to be sold under those firm arrangements.

Great. That's helpful.

And then just one question on the comments around locking in service costs. I apologize if I missed this.

But you can see above maybe current weak spot prices in order to get those contracts locked in. Just curious, because typically we hear that locking in service pricing usually has op-outs or escalators.

And so just curious how you're able to lock in pricing for 2017?

Yes. This is Rob.

I can speak on the rig contract side. We're in a cycle here where the contractors are more favorable in getting their equipment back to work.

And we've been able to access very high quality shale rigs from other basins with very little mobility costs to Gulfport. So on the drilling contract side, it's been very favorable to get these rigs back to work and really able to lock them in through entirety of 2017 and actually favorable rates, even compared to 2016, which was at sometimes surprising to me.

This is Mark. I might add that we – there are various services.

We have pumping services locked in through 2018 as well as sand. As far as supporting services, as Rob mentioned earlier, we've been an active operator in the Utica since 2012.

So the cyclic nature of our business – a lot of service companies want to work for a company of this kind that have continual activity and we're sort of approving that. So, we're able to lock in some of these terms with the prevalence of picking work activity, which will certainly help.

And I might add to that. These aren't just verbal commitments.

We have letter of agreements and actual contracts with vertically integrated companies. But I might also add.

We've been the most active driller over the past few years. And this is where, I think, our balance sheet and our activity levels, not only historically, but going forward has given us a strategic advantage in talking to our service providers.

Obviously we're focused on the highest quality service providers that we can get. We're very happy with our service providers.

But, I think, in turn, they are happy with us. And so I think this gives Rob and Mark the ability to have good, solid discussions with these folks.

And so we haven't actually seen push back on the pricing extending the term. They've been more than wanting to do that for us.

And just to be clear, are there still escalators potentially on the pumping services or those are going to be held at the agreed upon rate?

As far as pumping services, this is – again these are contractual agreements for 2018 as well the precedent (44:41).

Perfect. Thanks so much for the color.

Take care.

Thank you.

Good morning, gentlemen, and Jessica.

Good morning, Holly.

Most of my questions have actually been asked and answered, but I did have one on the capacity side. So just thinking, Mike, about the higher rig scenario, our math suggests that from a capacity versus production standpoint you'd be a bit exposed to the local market in 2018.

Just trying to get a sense of how you guys are thinking about that. Are you comfortable with the local market exposure?

Would you sort of beef up your FTE capacity?

Ty, do you want to take that?

Yes. How are you?

This is Ty. So as we look into – as we said actually in the scripted remarks, again, it's not a question of if these projects are going to be done but when.

And you're looking at three BCF with projects that are basically – what we see as executable on time. Things are – we have line of sight into the other ones that we feel like we have line of sight into, are still on schedule so far is what they're saying.

So with that even when we risk some of those things out internally here, we feel like in 2018 the pipelines come on and the takeaway is adequate. In fact, we'll be trying to catch up with supply.

So that allows for as always expected from Gulfport's portfolio that our incremental production would be into that basin marks that would be improving long-term going forward.

Just a follow-up to that. Would there be a better – good pricing quantities for you guys for that rate exposed capacity – sorry for that exposed production?

Yes. I don't know if we have that clarity yet, but we'll get more into that as we get into next year.

Okay. Great.

And then maybe just one housekeeping item on the G&P costs for the quarter. Was there anything to speak of there?

I'm assuming it was just more processing costs since you completed eight wet gas wells?

That's right. So as we completed some wet gas wells, those have the processing and fractionation and the additional costs as they have NGLs with them.

And so we saw those come in on the later part of the quarter and is reflected in that G&P cost. As we go forward, again, we think that it will continue to be in line as we bring more dry gas wells on.

Okay. Great.

Thanks, guys.

Good morning and congratulations on another strong quarter. Mike, I think, last quarter, you spoke about experimenting with some bigger completions.

I was just wondering how is that going and how it might eventually relate to well spacing.

Yes. I'll let Mark take this one.

Good morning. We'll most certainly use – let me back up and say that we've been operating in the Utica Shale for about five years now.

We've done a great deal of modelling and a great deal of experimentations. But we almost certainly end up using more sand, more proppant in 2017 as it makes sense to do so.

I have to say though that fracture stimulation design is not as fundamental more sand is better. Fracture stimulation design has always driven by ample drainage area, lease position, well economics and offset productions.

So, again, Gulfport will use more sand where modelling indicate it's appropriate and where it makes technical sense.

Okay. Thank you.

Schlumberger was very proud of an 18,500 foot well that successfully D&C'd in the Utica condensate window. Thinking higher level, does drilling ultra-long laterals have the potential to improve condensate returns enough to compete for capital?

I'd have to say, first of all, we haven't drilled a well on condensate window out there for a while, Jeff. Obviously, it could help.

I'm not sure what current costs for a normal lateral would be for us over there. And, obviously, we have limited condensate acreage available to us.

So that's hard for us to comment on.

Okay. Thank you.

I could add – this is Rob. I could add to that.

Drilling the 18,000 foot lateral in the condensate area is much different than drilling an 18,000 foot lateral in the dry gas area. We have much higher mud weights, deeper TBVs (49:38).

The limits that we'll be pushing down in the dry gas area is a whole different animal than drilling an 18,000 foot lateral in the condensate area.

Right. I appreciate that.

That's why my curiosity was confined in the condensate. Thanks for the color.

Thank you.

Thanks and good morning and congrats on a good quarter. Just two quick questions from me.

Mike, how do you see the A&D market right now in the Utica, both on number, potential deals and where valuations are, just your big picture thoughts?

Well, the A&D market certainly has been interesting. I think more for Gulfport, generally speaking, all the deals that we've seen out there were a good fit for the companies that executed those deals.

We think, for us, primarily, our focus should be organic. That's the most cost-effective option, so bolt-on activity, which we've already executed on and will continue to do that.

We should be able to demonstrate that in the upcoming quarters. We're going to see more and more of those opportunities as people face a significant amount of lease renewals out here over the next couple years.

And we've got a lot of acreage out here. We've got a lot of acreage in areas where we surround some of this other acreage that could become available.

So we're pretty focused on that and think that's going to be one of our better opportunities going forward.

Thank you. And then my follow-up is – thanks for all the helpful color on the services you do locked in to help mitigate any kind of cost inflation.

Is that the limit your ability – say, we did have a warm winter and then you wanted to slow things down if gas prices are pretty weak. Does that in any way limit your flexibility?

Well, I thought someone might ask that question. So it's interesting because I answered, if you recall, my response to Neal's question about all the reasons why we don't think we would have to do that.

Rob has structured the contracts in a way that we have two contracts that currently do not go to the end of 2017, so just four of the six. So we do have some flexibility there.

We can do that. But keep in mind, we're hedged.

We've mitigated the cost side. We talked about 95% of our product going out of the basin.

So I really think it's an unlikely scenario where we pull back. And then lastly and most importantly maybe just looking to fundamentals, I think, the U.S.

gas supply and inventories, while we're having this warmer weather right now, I think, it's a temporary blip, and we'll get back on track very quickly.

Thanks so much, Mike.

Thank you.

Hey. Good morning, guys.

Most of mine have been answered. But I think on the last call you mentioned testing some higher proppant concentrations going to 2,500 pounds per foot to 3,000 pounds per foot.

Can you give us a sense of what that $1,085 per lateral foot cost you mentioned in the press release would go to with that type of completion design?

Well, obviously, there would be some change to that. But it probably would not be less – it probably would be less – thinking off top of my head, it would be less than the $100 per foot change, so not really a material change.

And then I think, additionally, we're trending down actually. So the $1,085 is a trend down over the year.

And I think we're actually going to see that continue to come down, as Mark and Rob consistently frac nine stages a day and drill wells at just over 20 a day. So incrementally, it's not that much of a change.

Okay. Appreciate the color, guys.

Thank you. 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 your call.