Jessica Wills - Manager of Investor Relations and Research Mike Moore - Chief Executive Officer and President Keri Crowell - Chief Financial Officer Mark Malone - Senior Vice President of Operations Paul Heerwagen - Senior Vice President of Corporate Development and Strategy Rob Jones - Senior Vice President of Drilling Ty Peck - Senior Vice President of Midstream and Marketing

Neal Dingmann - SunTrust Robinson Humphrey Tim Rezvan - Mizuho Ronald Mills - Johnson Rice David Deckelbaum - KeyBanc Capital Markets James Sullivan - Alembic Global Advisors Geoff Jacques - Iberia Capital Partners

Thank you, and good morning. Welcome to Gulfport Energy Corporation's second quarter of 2017 earnings conference call.

I am Jessica Wills, Manager of Investor Relations and Research. Speakers on today's call include Mike Moore, Chief Executive Officer and President; and Keri Crowell, Chief Financial Officer.

In addition, with me today and available for the question-and-answer portion of the call are, Mark Malone, Senior Vice President of Operations; Paul Heerwagen, Senior Vice President of Corporate Development and Strategy; Rob Jones, Senior Vice President of Drilling; and Ty Peck, Senior Vice President of Midstream and Marketing. 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. Information concerning these factors can be found in the company's filings with the SEC.

In addition, we may make reference to other non-GAAP measures. If this occurs, the appropriate reconciliations to the GAAP measures will be posted on our Web site.

Yesterday afternoon, Gulfport reported second quarter 2017 net income of $105.9 million or $0.58 per diluted share. These results contain several non-cash items, including an aggregate non-cash derivative gain of $59.9 million, and expense of $1.1 million in connection with the recent SCOOP acquisition, and a loss of $13.3 million in connection with Gulfport's interest in certain equity investments.

Comparable to analyst estimates, our adjusted net income for the second quarter of 2017, which excludes all the previous mentioned items, was $60.4 million or $0.33 per diluted share. An updated Gulfport presentation was posted to the website yesterday evening.

Please review at your leisure. At this time, I would like to turn the call over to Mike Moore, CEO of Gulfport Energy.

Thank you, Jessica. Welcome, everyone, and thank you all for joining us this morning.

As announced in the press release yesterday evening, during the second quarter Gulfport reported approximately $60.4 million of adjusted net income on $264.1 million of adjusted oil and natural gas revenues, and generated approximately $167.3 million of adjusted EBITDA and $145 million of operating cash flow. Gulfport delivered another successful quarter operationally during the second quarter, highlighted by 22% production growth over the first quarter of 2017 and had a very active quarter in both our Utica Shale and SCOOP asset areas.

In the Utica Shale the Gulfport team continues to make strides in the field marking the second quarter as the most efficient quarter at the drill bit with respect to spud to rig release and the busiest quarter from a tie in line perspective the company has experienced since earning the play in 2011. In the SCOOP, the integration of the assets is going very well and Gulfport turned to sales are first two operated Woodford completions in the play during the second quarter and continue to be pleased with the results from these wells as we accumulate additional production history.

We have been very active on the completion front in the SCOOP, recently beginning flow back on two gross operated Woodford wells and are in various stages of completion on an additional five gross operated Woodford wells. In addition, the team recently spud both the Springer and Sycamore well and is currently drilling ahead on these locations testing new development horizons on the Gulfport acreage.

When you couple the strong performance of Gulfport's assets year-to-date and the anticipated activity during the second half of the year, it has led us to increase our 2017 production guidance and we now forecast our 2017 average daily net production to increase approximately 48% to 53% over 2016 levels. On the operations front, in the Utica the team delivered solid results experiencing significant efficiencies at the drill bit and exceeding numerous previous records set in the field.

During the second quarter, we spud 28 gross wells utilizing six operated rigs. The well released during the second quarter had an average drilled lateral length of approximately 8,409 feet, up 3% over the first quarter and 12% year-over-year.

While we continue to push the limits with respect to lateral length, we are seeing drilling days decrease shaving of over two days from spud to rig release when compared to the first quarter of 2017. Normalizing to an 8,000 foot lateral, as assumed in our public type curves, during the second quarter we averaged spud to rig release of just 18 days, down 12% over the first quarter and 29% year-over-year.

And to my knowledge, is basin leading in the dry gas window of the play. We exceeded many of our previous drilling records during the quarter which provides a new set of expectation and goals for the team to focus on going forward.

We beat our spud to rig release record releasing the well in the dry gas window of the play in 13.7 days. We TDed the longest well to date for Gulfport in the play, measuring 21,230 feet and beat both our previous lateral and vertical feet per day records.

Overall, we had an exceptional quarter on the drilling front and I look forward to the remainder of the 2017 as I believe the team will improve upon these metrics even further. Turning to completions.

In the Utica Shale, we turned-to-sale 29 gross wells with an average lateral length of 7,802 feet during the quarter and as I mentioned, marked the most active quarter from a tie in line perspective in the Utica Shale for Gulfport to date. We completed a total of 981 stages during the quarter, a 40% increase sequentially which contributed to not only a solid second quarter but also positions the company for another strong growth quarter at the Utica Shale here in the third quarter.

In terms of activity. We ran on average 2.67 completion crews during the quarter and completed approximately 6.3 stages per day, up 35% from the first quarter of 2017 and a metric I believe we will continue to prove upon here in the warmer months of the year.

We are proud of our team's accomplishments this quarter and continue to push the technical limits as evidenced in the results today, ultimately driving efficiencies in the field, resulting in less time and location and overall lower cost. Incorporating both the drilling and completion activities during the second quarter of 2017, we estimate that Gulfport's Utica well cost during the first six months of the year has averaged approximately $1094 per foot of lateral.

These results include the completion of two one well pads in the dry gas window of the play. Excluding those pads, we estimate go-forward Utica well cost averaged $1,069 per foot lateral during the first six months of 2017, below Gulfport's average well cost in 2016 and our budgeted assumptions.

Lastly, alongside earnings yesterday evening, we provide an update on Utica well results an included production history from several recent turn-in lines across the Gulfport acreage position. As you will see, these wells demonstrate strong performance and notably, the wells remain consistent from north to south and east to west across the play.

Our Schubert Pad is Gulfport's first producing well in Jefferson County and our farthest northern well drilled to date. Our Jacobs Pad in Monroe County is located on the southern tip of the acreage and the Ward, Charlie and Valerie pads span Belmont County from east to west.

As demonstrated in the data, all of the wells are yielding solid results and speak to the highly de-risked natured of the areal extent of Gulfport's dry gas acreage position. In the SCOOP, as I mentioned, the integration of the assets continues to go very well and the team remains focused on identifying areas where we can improve upon operationally.

On the drilling side during the second quarter, three gross wells were spud on the acreage. The wells released during the quarter had an average lateral length of 8,804 feet, up 12% from the first quarter of 2017.

Normalizing to a 7,500 foot lateral as assumed in our public type curves, the wells in the second quarter had an average spud to rig release of approximately 64.8 days. After taking over the assets, one of the drilling team's initiatives focused on the high-grading of equipment for our rig fleet.

While we are in the middle of this process and due to contract timing, Gulfport is currently running six rigs in the play. However, we will be back to four operated rigs in the next few weeks as contracts expire.

Turning towards our exploration activities in the SCOOP. Gulfport recently spud both our planned Sycamore and Springer test discussed on our earnings call in May.

Gulfport's first Sycamore well is located in the heart of the acreage position on the western side of the wet gas window of the Woodford and is targeting the lower portion of the Sycamore formation. With regard to the Springer test, the well is located on the eastern side of the acreage position in the oily area of the play and is targeting the thick, porous, oil rich section of the upper member of the Springer.

Alongside yesterday evening's announcement, we posted a new investor presentation highlighting the specific locations for both the Sycamore and Springer wells currently drilling and also highlighted recent peer results. As you can see depicted on this Slide, the locations of the Gulfport's test will further delineate our position and de-risk incremental acreage in the play.

We continue to be encouraged by the activity of our peers, directed towards these horizons and look forward as Gulfport and other operators identify the scale and scope of these horizons across the position, potentially unlocking significant perspective resource and meaningful developable locations. In the SCOOP, during the second quarter Gulfport turned-to-sale two gross Woodford wells, our previously announced Vinson wells located in the wet gas window Southern Grady County.

These wells continue to perform strong and we recently provided 60-day production rates. The Vinson 2 has averaged a 60-day peak production rate of approximately 14.4 million cubic feet of gas equivalent per day and the Vinson 3 well has averaged a 60-day peak production rate of approximately $17.3 million cubic feet of gas equivalent per day.

We continue to monitor the production results compared to direct offset producers in the Vinson wells are outperforming the average of direct offset producers by approximately 27%. We are pleased with these results and look forward to accumulated more production history from our first two operated and completed wells in the play.

In addition to these results, we have been active on the completion front in the SCOOP, recently beginning flow back on two gross operated Woodford wells. Building upon the success we have seen on the Vinson pad, we continue to push the envelope beyond the historical completion methods in the play with our most recent turn in lines placing in excess of 2500 pounds of proppant per lateral foot, nearly double the amount of volumes when compared to historical practices for the area and slightly above our Vinson wells.

In addition, we are in various stages of completion on an incremental five gross operated Woodford wells and look forward to providing production data on all of these wells as they become available over the coming weeks. On the leasehold front, we are pleased to report year-to-date in Utica Shale Gulfport has acquired approximately 5,500 net acres in the core of the dry gas window of the play.

In addition, we closed an acquisition of mineral interest within our AMI with Rice Energy in Belmont County, increasing our NRI on over 5,000 acres by approximately 8%. In the SCOOP, year-to-date Gulfport has added approximately 2,600 net acres within our core operating area, bringing surface acres in the play to total approximately 49,000 net acres under lease today.

Before turning the call over to Keri, I want to quickly touch on the pricing dynamics in the northeast. As we have stated before, 2017 was always expected to be a pivotal year in Appalachia with the numerous capacity projects coming into service, ultimately leading to a structural improvement in local differentials.

While we and many of our peers have straight way from speculating on the exact timing of Rover, multiple other projects appear to be on time or even ahead of schedule with respect to their publicly provided in-service dates. We have clear line of site in the 2 Bcf a day of takeaway between now and November 2017 with an incremental 3 Bcf per day coming into service once the Rover pipeline is placed on line.

All to be sourced with local production. The basin is on the cusp of an additional 5 plus Bcf per day of pipeline capacity turning on line over the coming months and once in service, we expect to see Appalachian pricing shift in favor of the producer, advantaging Gulfport as our incremental growth volumes will price in basin allowing us to take advantage of basis tightening in the local markets.

I will now turn the call over to Keri to discuss the specifics surrounding the second quarter financial results.

Thanks, Mike. Our success in the field continues to provide support to our financial results highlighted by record corporate production and lower operating cost during the second quarter of 2017.

Total net production for the second quarter averaged approximately 1.04 billion cubic feet of gas equivalent per day, a 22% increase sequentially and a 56% increase over the second quarter of 2016. As Mike mentioned, continued strong well performance and robust activity in the Utica Shale led to another solid quarter and has also positioned the company well during the second half of 2017.

Our results year-to-date and anticipated activities for the second half of 2017 have led the company to update our 2017 production guidance and we now expect to average approximately 1.065 to 1.1 billion cubic feet of gas equivalent per day. In addition, we currently forecast third quarter production to be approximately 1.17 to 1.18 billion cubic feet of gas equivalent per day, in line with where consensus is today.

On the realization front, our second quarter of 2017 realized natural gas price before the effect of hedges and including transportation cost, settled approximately $0.70 per Mcf below the average NYMEX price. We have provided updated realization guidance for the year considering our results year-to-date and utilizing current strip pricing as the various regional pricing points at which the company sells its natural gas, and now forecast our realized natural gas price to average in the range of $0.62 to $0.68 per Mcf, below NYMEX settlement prices in 2017.

Before the effect of hedges, our realized oil price came in at $2.96 off WTI and our second quarter realized NGL price came in approximately 39% of WTI. We reiterate our full year guidance for both forecasted oil and NGL realization.

Our robust hedge portfolio continues to provide increased certainty to our future cash flows and based on the midpoint of our 2017 guidance, Gulfport currently has approximately 70% of our expected 2017 natural gas production swapped at $3.19 per Mcf. We have also been active in securing a base load for the outer years and today based on consensus estimates, Gulfport has approximately 60% of 2018 production swapped at $3.06 and continues to opportunistically layer on additional hedges on basis swaps to provide line of sight to our realizations and cash flows.

Turning to cost. The Gulfport team experienced another quarter of bringing cost lower in the field and during the second quarter, our per unit operating expense which includes LOE, production tax, midstream gathering and processing and G&A, totaled 1.03 per Mcfe, down 6% sequentially and 10% when compared to the second quarter of 2016.

Second quarter lease operating expenses totaled approximately $0.22 per Mcfe, down 13% sequentially and 10% year-over-year. Second quarter mid-stream gathering and processing expense totaled approximately $0.62 per Mcfe, down 1% sequentially and 4% year-over-year.

Second quarter G&A expense totaled approximately $0.13 per Mcfe, down 21% sequentially and a decrease of 34% year-over-year. We continue to expect all per unit operating expenses will decrease further as we progress through the year due to economies of scale in the Utica Shale and additional volumes contributed from our low cost SCOOP asset base.

For our 2017 program, Gulfport's D&C capital expenditures during the six months ended June 30, 2017, totaled $536.1 million, midstream capital expenditures totaled $23 million and leasehold capital expenditures totaled approximately $55.2 million. As planned, the second quarter of 2017 market an active quarter from an activity and capital perspective for the year.

We currently forecast similar to slightly lower D&C spend during the third quarter of 2017, decreasing very significantly in the fourth quarter and reiterate our capital budget for 2017 of approximately $1 billion to $1.1 billion. Moving on to the balance sheet.

As of June 30, Gulfport had approximately $120 million of cash on hand and $210 million drawn on our revolver. Our available liquidity totaled approximately $670 million, allowing flexibility as we carry out the remainder of our 2017 activities.

I will now turn the call back over to Mike for closing remarks.

In closing, 2017 is a pivotal year for Gulfport. Our 2017 development activities have allowed the company to reach a point financially and operationally where we can provide not only a strong rate of growth for 2017 but we believe places us in a position of growing at a healthy long-term growth rate within operational cash flow.

As a result, as we plan for 2018, Gulfport is targeting cash flow neutrality for the calendar year which at today's strip price we estimate would generate approximately 30% growth year-over-year. 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.

Mike, my first question maybe just on those last details you mentioned, on the cash flow neutrality for '18, a 30% growth. Could you talk about what type of rig count are you basing that off of on in both the plays and, again, are you assuming sort of the -- the most recent sort of differentials that you and Ty and everybody laid out.

Well, we are assuming the current strips differential expectations, certainly our hedge book for 2018, you know and I would say, as we look to '18, Neal, obviously we continue to be more efficient in the field. So the truth is, we can do more with less.

So I am not going to go into the specific details of how many rigs in each field. But I think you can make the assumption that we probably will have less rigs running.

Okay. And then to your point, I thought that was a good Slide on Slide ten where you laid out some of those Utica wells.

Could you talk about on that, just two things there? One, just on the completion, has that changed and just wondering what you are doing there, number one.

And then, number two, I know always in the past you always kind of choke those back just because of takeaway to make sure you had adequate takeaway. Maybe if you could have, Rob, or one of the guys jump in, or Mark, somebody talk about just sort of takeaway in how that pertains to the growth in the Utica.

Well, first let me address that. Historically, we haven't actually choked back wells because of takeaway and we had a time where we had a compression issue down in a very isolated area down south, that we had to choke wells back temporarily but never because really of takeaway.

And as far as completions and, Mark can jump in too, but I don’t think there is that much of talk about here. We have a mix, really, on the wells that are on that Slide.

We have a mix of new and old completions depending on -- and those completions depend on the lease geometry and so we adjust the completions depending on the particular issues that we have at that particular area. So mix of legacy completions and newer completions.

I wanted to, first kind of little bit on what Neal had asked about on Slide 10. This seemed an intentional move to kind of highlight the, I guess the consistent results you are seeing in the north and south at Jefferson and Monroe County.

So as we look to kind of 2018, how active is your development going to be in these areas. And maybe talk about maybe why you felt the need to kind of highlight the areas or if you feel like there is some kind of disconnect between what you see and what the market things about these areas.

Well, I think several things here. I would say first of all, Tim, we have a lot of wells.

And it's just physically impossible to continue to have and show in our presentation individual type curves on every well. So our presentation would be enormous if we continue that.

So we are trying to find a way to show well information on a more consolidated basis. Secondly, certainly this time we thought it was important as we had some newer results to show well performance, east to west, north to south, to help the market understand that we are seeing very consistent and encouraging results really across our dry gas acreage.

So that was really the idea behind the Slide. And as far as our activities, I guess you will continue to see us focus in the dry gas area, Eastern Belmont, probably next year.

Certainly lease explorations will be somewhat of a driver for us next year, but again details to follow on where our specific activities will be.

Okay. Thanks.

And then just on my follow-up. What do you see as the run rate to bolt-on additional leases in the SCOOP area?

Saw there were some additions recently. How consistently or I guess how competitive is that area getting now?

Well, we were certainly encouraged by what we were able to accomplish this quarter in both SCOOP and Utica, quite frankly, we have lots of brokers out in the field. They are working hard.

I think there is some runway. Average cost is still reasonable at $3500 an acre.

So I think there is runway, Tim. Time will tell, I guess, about how big that runway is.

Maybe one last question on Slide 10. When you look at the spread of those pads from north to south and east to west, any commentary about how some of those wells have performed, especially as you drilled to the northernmost and southernmost tips of your position given the consistency of the results.

I'm wondering if some of those are a little bit better as you would have thought some of the acreage grading to shift towards the edges of your position.

Well, you know, I would say we are very encouraged, particularly by the wells in the south. But I think also just the thickness in the north is certainly there.

The pressure improves in the south and I think what this chart shows is that although we have nuances, north to south, it's still delivering good wells in all areas.

Okay. And then shifting over to kind of the Springer and Sycamore slides.

You talked about the locations of those and on Slide 12 you have the map that kind of shows where they are. When we try to -- is there anything from an analog standpoint, is the Sycamore more potentially prevalent on the central to western part of your position and the Springer more prevalent on the central to eastern part?

Or is that just the way industry has drilled so far?

I think it's more indicative of the way industry has drilled so far. Obviously time is going to tell for us but I don’t think there are any conclusions to draw at this point.

And then just that last follow-up on that one would be, what would your eventual plans be for the Springer and Sycamore given the Woodford kind of 20% plus above plans? When you think the longer term, how do you think about fitting those incremental zones into a development program?

And that's it.

Well, that’s a good question. And I think one of the reasons, Ron, that we were excited to be able to push forward the development of the Springer and the Sycamore is so that we could think about what level of activities in those horizons we should have in our 2018 plan.

So I can't tell you how much it's going to be yet. Certainly it's an economic decision, it's optionality and it's whatever brings us the highest value well.

So we will have to see what we have. We will continue to watch the peers and fortunately we should have information in time to be able to include some of that in our 2018 activity, if that’s what we decide to do.

My question, again, I guess is on the '18 plan, as you mentioned that before Q&A started. Can you kind of give us a little bit of color what the thought process is here and you obviously have the balance sheet and liquidity.

At strip you are developing wells with very competitive returns. Is free cash neutrality more of a philosophical goal for the company now on sort of a repeatable basis and that’s sort of the best way you think that there is to create value for shareholders.

And then, I guess, if you could add any color on, would there be things that you do, does that free cash neutrality describe the E&P program and this is excluding midstream and leasehold spend.

Yes. Those are all good questions.

So it is, we do think about cash flow neutrality in terms of our D&C budget. Obviously, the other spends are minimal.

Midstream certainly minimal. Land, while we have some minimum commitments, discretionary spends on land would only be funded with other liquidity sources.

So really we are talking about the bulk of our budget and cash flow neutrality. Listen we think it's something that all companies should aspire to.

We have actually worked towards this for a long time. David, it's been a goal of ours.

With the level of activities that we have this year, it certainly propels us nicely into 2018 and sets us up to deliver, to be able to deliver approximately 30% growth in a cash flow neutral way. But we also think it's something that we can sustain going forward in future years.

So we are not just talking about '18, we are talking about '19, '20 and beyond. And we think we can deliver sustained double-digit in a cash flow neutral way going forward as well.

Okay. I appreciate that color, Mike.

Does that change, I guess the type of program that you are running, at all? I know that you alluded to, you can do more with less.

Is that the suggestion that you would just be more in development mode using larger projects and that there would be fewer one off rigs, or that you would be targeting the most efficient areas? Is there a change versus what you would be doing, say, the first half of this year, other than some of the SCOOP delineation and HBP?

I don’t think so. I think we consider ourselves kind of in development mode and have for some time now.

So I am not sure it fundamentally changes the way we think about the choices that we make for our programs. So I don’t think so, David.

Okay. And I could just sneak in one another one.

You guys have, I guess, several different non-core assets or other sources of funds. I guess they would be coming to you, Strike Force JV etcetera.

Can you go over some of the timing of when you would expect seeing some proceeds coming in the door from some of these sort of various opportunities that you have out there and, I guess, naturally you would be thinking of using those funds for some of the other things that you alluded like leasehold spend etcetera.

Yes. Obviously, we have lots of -- since we are targeting cash flow neutrality for our D&C budget, we have lots of options actually for those other liquidity sources.

Mammoth, no plans there. It's just about what the right time is, what brings the most value to our shareholders.

And so, no, specific thoughts or plans there. The Strike Force asset, I am probably limited on what I can say.

I think it's kind of tail on the dog but seems like there has been some messaging that could be a 2018 event. But we are not counting those sources into our liquidity sources for 2018.

So I know I am being vague here but there is no -- I guess, what I am trying to say is, there is no pressure for us, there is no guarantor ahead and we have lots of options that we can think about when and if those -- the timing is right on those.

To quick ones from me. You alluded to pipeline tie in there in November of '17 with 2 Bcf a day as incremental capacity out of Appalachia.

Just wanted to clarify, are you talking about [rain leech] [ph] there? And then maybe a smattering of all the smaller ones to get you up to the 2 Bcf a day?

Yes. This is Ty.

I mean we are talking about the TransCanada project as well as to expect to having a number of expansions on [Petco] [ph] system. So that gives us that 2 Bcf.

Got you. Just wanted to confirm that.

Thanks. And then I know you guys didn’t give a half year update on reserves or anything but can you guys just give a feel for what kind of TDP growth you have seen at midyear, with your activity being placed around in Q2.

And I am just thinking about how that feed into your discussions with your bank group or in the borrowing base going into October.

Sure. This is Keri.

You have seen our activity on 2Q, our turn in lines, and we expect around the same activity in the third quarter. So we do expect a large increase in our PDP coming up on our next re-determination.

We can't speak to where price [decks] [ph] will be but we do anticipate a large increase in our PDP reserves.

Okay. Great.

So no sense of where you guys are at at midyear, I think?

Not that we can address. No.

Just looking at the SCOOP, from the drilling days, I know it's still early days and you guys are just getting a handle on the acreage. But is there some type of target or something that you guys are looking to in '18 or beyond?

Geoff, this is Rob. On the drilling days in the SCOOP, first thing is that it has proved to be challenging, just as advertised.

We have been able to drill wells and in the similar days as most of our peers. Going forward, certainly we are making lots of changes.

We have upgraded some equipment. We have changed out some personnel.

So we are making lots of strides. The equipment we have upgraded, we are very pleased with.

And in the future we expect the days to come down and that’s certainly the goal with what we do in the drilling group.

And I would add to that, I think both groups, drilling and completion, have been working extremely hard here in the SCOOP. And as you probably recall, early days in the Utica, we were not that efficient and it took us a while to get down to the new records that both of our groups are setting today.

It feels like in SCOOP that we are making progress much more quickly the last, I would say the last six weeks, we feel like we have turned a corner with all the changes that have been implemented on both the drilling and completion side through [indiscernible] programs, through liners, through all kinds of things. The high grading of equipment.

And so we are already beginning to see lots of improvement out there. As to where we get next year, it's hard to quantify exactly but we are convinced that we are going to be much more efficient, not only in the back half of this year but '18 over '17.

We appreciate your time and interest today. Should you have any questions, please do not hesitate to reach out to our investor relations team.

Thank you and this concludes our call.