Jessica Wills – Manager of IR 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 Ron Mills – Johnson Rice and Company David Deckelbaum – KeyBanc Capital Markets Jason Wangler – Imperial Capital John Nelson – Goldman Sachs Tim Rezvan – Mizuho Securities Marshall Carver – Heikkinen Energy Advisors Holly Stewart – Scotia Howard Weil Dave Kistler – Simmons, Piper Jaffray Drew Venker – Morgan Stanley

Thank you, and good morning. Welcome to Gulfport Energy Corporation's third 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 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 third quarter 2017 net income of $18.2 million or $0.10 per diluted share. These results contain several non-cash items, including an aggregate non-cash derivative loss of $37 million, and expense of $33,000 in connection with the recent SCOOP acquisition, and a loss of $2.7 million in connection with Gulfport's interest in certain equity investments.

Comparable to analyst estimates, our adjusted net income for the third quarter of 2017, which excludes all the previous mentioned items, was $58 million or $0.32 per diluted share. An updated presentation was posted to the yesterday evening to the website in conjunction with the earnings announcement.

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 third quarter Gulfport reported approximately $58 million of adjusted net income on $302.5 million of adjusted oil and natural gas revenues, and generated approximately $195 million of adjusted EBITDA and $168.1 million of operating cash flow. Gulfport produced approximately 1.2 billion cubic feet of gas equivalent per day during the third quarter representing 16% production growth over the second quarter of 2017 and 63% growth over the third quarter of 2016.

Our solid production results year-to-date are driven by the continued strong performance of both our Utica Shale and SCOOP asset and bolstered by an active turn-in-line schedule year-to-date in both plays. On the operations front, in the Utica during the first nine months of 2017 we spud 77 gross wells utilizing six operating rigs, the wells release as an average drilled lateral length of approximately 7,882 feet and were normalized into an 8,000 foot lateral as assumed in our public type curve, we average the spud rig release of 19.3 days down 50% over our full year 2016 results.

We continue to break many of our previous drilling records set in the field, beating both our vertical and total footage per day records during the third quarter of 2017, overall we’ve had a solid year on the joint in our efficiencies realized in 2017, set us well as we enter 2018, allowing us to plan to do more as a drill bet with less overall rigs running. As we plan for cash flow neutral program for 2018 during the fourth quarter we began to decrease our rig count in the Utica as contract expire and today Gulfport has four operated rigs running in the play.

Turning to completions in the Utica Shale, during the first nine months of 2017, we turned to sale 52 gross wells with an average lateral length of 7736 feet, in terms of activity we ran an average of two completion cruise during the first nine months of the year and completed approximately 5.2 stages per day, as a result, as of September 30, we had completed a total of 2,470 stages during 2017 representing substantially all of our 2017 completion activity, we currently anticipate to turn-in-line 15 gross 11.7 net wells during the fourth quarter. However, the large majority of the capital spending associated with the forecasted turn-in-lines took place during the third quarter of 2017, these wells mark the completion of our 2017 frac schedule and we do not have a completion crew running in the basin today, incorporating both the drilling and completion activities during the first nine months of 2017.

We estimate that Gulfport Utica well cost is average approximately $1,122 per foot of lateral. Our average well cost year-to-date reflects shorter lateral lengths during the summer months, however we expect to see lateral lengths increase in the field during the fourth quarter of 2017, realizing economies of scale and resulting in an improvement in our per foot of lateral costs.

In the SCOOP we continue to see progress of the drill bit and since taking over the asset mid-February as of September 30, 15 gross wells have been spud on the acreage during 2017, the wells released to-date have had an average lateral length of 7,174 feet and were normalized to a 7,500 foot lateral as assumed in our public type curves, the wells have a average spud to rig release of approximately 69 days during 2017. The team has been intensely focused on identifying areas of improvement including seismic reprocessing, horizontal targeting, pit selection, casing placement and rotaries [ph] durable utilization.

These initiatives have improved our GL steering and target percentages of above 90% for the third quarter and leading net results leave us very confident in our ability to reduce drilling days in 2018. In the SCOOP during the first nine months of 2017 we turned to sell eight gross wells with an average stimulated lateral length of 7,517 feet, over the past few months, we have announced additional production results on six gross liquid rich Woodford wells located in the wet gas window of Central Grady County alongside yesterday’s earnings announcement we provided 30-day production rates for our Pauline 3, Pauline 4, Pauline 5, Pauline 6 and the EJ Craddock 8 wells.

We continue to be very pleased with these results and look forward to accumulating more production history from all of our recent turn-in-lines in the play. Turning towards our exploration activities in the SCOOP earlier in the year we elected to include both the Springer and Sycamore tests in our 2017 development program to organically delineate additional resource across the acreage.

During the third quarter we drilled and completed Gulfport’s first Springer test the [indiscernible] well located in the South Eastern Grady County, we are in the very early stages of flow back and look forward to providing initial results in the coming weeks. On our Sycamore tests in South Central Grady County, we recently completed drilling and are in the processing of rigging down a location.

We plan to complete the well during the fourth quarter of 2017 and provide early results around the end of the year. In addition, throughout 2017 we have been active on the technical side with additional seismic, well cores, and G&G activity in the play, incorporating these additional exploration activity, we have updated our 2017 budget to reflect an incremental 35 million of capital in the SCOOP.

On the leasehold front, we have been very successful this year in our trading efforts and adding lease hold organically on the ground within units schedule in our near-term development plan, this strategy has allowed us to focus our leasehold spend on the higher returns potential for deploying capital and year-to-date in the Utica Shale, Gulfport has acquired approximately 10,700 acres in the core of the dry gas window the play partially offset by approximately 8,500 acres we have consciously chose to let expire due to be announced outside our development plan. In addition, as we announced in our earnings calls in August, earlier in the year we closed on an acquisition of of mineral interest within our AMI with Rice Energy in Belmont County, increasing our net revenue interest on 5,000 acres by approximately 8%.

Lastly in the SCOOP, year-to-date Gulfport has increased our leasehold position by approximately 4,100 acres within our core operating area, when we couple this with an active trading effort, the activity has led to a significant increase in our working interest on wells spud during 2017 and we now estimate operated wells spud this year to be approximately 109 net wells in total between the Utica Shale and SCOOP equating to an incremental 22 net wells spud when compared to the midpoint of our previously provided guidance, while this does increase our anticipated spend this year, the incremental working interest positions Gulfport wells we plan for 2018, based upon actual year-to-date and forecasted fourth quarter of 2017 activity we do expect this additional spend will be partially offset by a reduction in approximately 2.4 million turn-in-lines and we have updated our 2017 capital plans to reflect an additional $75 million in connection with the increase in working interest and related leasehold spend. Our updated 2017 capital budget forecast approximately $860 million on operated drilling and completion activities, in addition we have updated our expectations for full year 2017 and based on year-to-date and forecasted fourth quarter activities, we now forecast to spend approximately $125 million on non-operated activities approximately $45 million on the midstream build out associated with the strike force and approximately $130 million on leasehold expenditures during 2017.

Lastly while we do expect a slight reduction in turn-in-line we currently forecast 2017 full year production to be trending towards the upper end of the previously increased guidance range of 1.065 to 1.1 billion cubic feet of gas equivalent per day, highlighting the continued strong performance from both Utica shale and the recently acquired SCOOP assets. Before turning the call over to Keri I want to quickly touch on marketing dynamics in the Northeast, as we have stated many times we expect the 2017 to be a pivotal year in Appalachia with the numerous capacity projects coming into service, ultimately leading to a structural improvement in local differentials and I am pleased to report that we are experiencing the start of this transition today.

Over the past few months we have witnessed 1.2 Bcf a day of takeaway we placed into service including [indiscernible] expansion and Rover phase 1A which Gulfport holds capacity and we have clear line of sight into an incremental 3.5 plus Bcf per day of pipeline capacity turning on line between now and the end of first quarter of 2018, including TransCanada Leach Rain Express, TEDCO there in Southwest and Energy Transfer Completion of Rover. Once in service we expect to see Appalachia pricing shift advancing Gulfport as incremental growth volumes in 2018 will be priced into basis tightening local market which we see reflected in the forward pricing today.

In the interim at the end of third quarter realized prices we continue to benefit from 90% plus of our volumes flowing under firm arrangement receiving premium pricing when compared to in basin marks today. I will now turn the call over to Keri to discuss the specific surrounding the third quarter financial results.

Thanks, Mike. Total net production for the third quarter averaged approximately 1.2 billion cubic feet of gas equivalent per day, a 16% increase sequentially and as Mike mentioned was driven by continued solution performance of the existing asset base and turn-in-lines in our Utica Shale plays.

On the realizations front, during the first nine months of 2017 our realized natural price before the effect of hedges and including transportation cost, settled approximately $0.71 per Mcf below the average NYMEX price. Based upon our results year-to-date and utilizing current strip pricing as the various regional pricing points at which the company sells its natural gas, we reiterate our full year guidance and continue to forecast average in the range of $0.62 to $0.68 per Mcf, below NYMEX settlement prices in 2017.

During the first nine months of year before the effect of hedges, our realized oil price came in at $3.28 off WTI and our realized NGL price came in approximately 47% of WTI. Based upon these results given the strength we have seen on the liquids front in all of our operating areas including the Utica, our LOS price set in Louisiana volume and liquid rich SCOOP asset, we have updated our full year guidance for forecasted oil and NGL realization and now expect to realize approximately $3.25 to $3.75 of WTI for oil and approximately 45% to 50% of WTI for NGL during 2017.

Our robust hedge portfolio continues to provide increase certainty to our future cash flows and we have been very active in securing a base load for the outer years with additional 2018 and 2019 volumes added across the majority of our products during the third quarter. Today based on consensus estimate, Gulfport has approximately 70% of 2018 production swapped at $3.06 and continues to opportunistically layer on additional hedge and base the swap to provide line of sight to our realizations and cash flows.

Turning to costs, Gulfport experienced another quarter of operating costs turning lower and our per unit operating expense which includes LOE production tax, midstream gathering and processing and G&A total $0.98 per Mcfe during the third quarter, down 5% sequentially and 14% when compared to the third quarter of 2016. Third quarter LOE totaled approximately $0.18 per Mcfe down 17% sequentially and 30% year-over-year, third quarter midstream gathering and processing expense totaled approximately $0.53 per Mcfe relatively flat sequentially and down 7% year-over-year, third quarter G&A expense totaled approximately $0.12 per Mcfe down 9% sequentially and a decrease of 24% year-over-year.

We continue to expect our per unit operating expense will decrease further as we progress through the year as well as into 2018 due to the economies of scale in the Utica Shale and the growth from our SCOOP asset. Moving on to the balance sheet, in connection with Gulfport borrowing base rate determination and taking into account the reserve added to drill bit since the spring, Gulfport’s lead lenders have recommended an increase in the company’s borrowing base from $1 billion to $1.2 billion with elected commitments under the facility to total $1 billion, in addition subsequent to the third quarter, Gulfport completed an offering of $450 million of 6.38 senior notes due 2026, a portion of the net proceeds of approximately $445.3 million were utilized to repay the outstanding borrowing under our revolving credit facility with the balance to be used upon the remaining anticipated out spend for 2017.

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

In closing, as we exit 2017 and head into 2018 our key priorities remain unchanged, we are committed to a disciplined capital program for 2018 and remain devoted to cash flow neutrality with yesterday’s strip price we continue to estimate we generate approximately 30% growth year-over-year. This concludes our prepared remarks.

Thank you again for joining for our call today and we look forward to answering your questions. Operator, please open up the phone lines for questions from the participants.

Good morning all. Mike, my first question is more on M&A you all did certainly a solid job, you can tell, during the quarter of adding working interest in the Utica.

So my question is will you continue doing this and if you could just talk about just general acquisitions in the Utica and SCOOP going forward.

Thanks Neal. This quarter beginning late summer, our land folks worked really hard and we’re to fill in the units that were in our near-term development plan and brought those units up to 96% working interest I think, you know going forward Neal our plans for 2018 those units are already pretty filled out.

So, while we are always doing some mom and pop leasing trying to fill in those last bits in our units, those units are already pretty robust, so I think the opportunity there is limited going forward, but again you will see small things here and there certainly as we fill in those last remaining pieces. And as far as M&A I think was second part of your question, Neal I think our approach to that is not different than what we said before and we have a lot of acreage to drill, we have a lot of locations and I think we are pretty head down focus on the development of that acreage.

Okay, one last one if I could. Mike, could you just talk about if you believe that obviously with what's going on with Rice in equity, a potential change in midstream partner that caused you to change, potentially change your operating plan there anyway and as well as anything about that midstream JV if that would have any particular or potential changes.

Hey Neal this is Ty, I will answer lease operational portion of that. We have been working with Rice from day one here on the announcement and even invited them last week just making sure all our contracts are good, we still like is still in good position, our design is good, so that’s largely that design is under, already under construction and then just basically the operation which the operational side which we feel confident at ETG is a good operator, so as far as the operational plan we don’t –it’s just about execution, it’s not about change or anything.

Thanks, Mike. Thanks, Ty.

Thank you.

Hey, good morning Mike on the 2018 seeking to cash flow neutrality in that 30% growth can you talk a little bit about how that fits into the much higher working interest you have in your late 2017 and 2018 programs, I see you’ve already gone through from 6 to 4 rigs on the Utica what does that pretend for activity because you will end up being able to drill more net wells with fewer gross trying to marry that expectations for CapEx?

Okay, yes, we haven’t, I know we haven’t given a lot of details, information on 2018 yet, this dynamic with this increase working interest and the additional CapEx spend to do that, really puts us in a even better position for 2018 is just higher working interest on these wells that we are bringing on, certainly so it allows us to think about activity levels in a different way. What you are going to see exiting this year and going into next year, is a higher level of ducts, so next year we have the ability to drill less and complete more, generally I would tell you that, where it stands today, certainly we’re going to have less drilling activity, so I think we are perfectly thinking about approximately 2.5 rigs in Utica and we will probably stick with the 4 in SCOOP.

Does that answer your question?

Yes it does and then as we look at the SCOOP with the plan be to maintain 4 rigs and given the strong wet gas results in the Woodford with the focus remain on the Woodford or given the upcoming results in the Sycamore and Springer how could you -- how would you think about potentially folding those zones into the development program and successful?

Yes, that’s a good question. So I do think, our program next year will be focused on the Woodford wet gas, obviously we have all seen the results of those wells, we brought on to-date and we have more to come before the end of the year, we have been testing the Springer and Sycamore.

We have a Springer well to talk about hopefully in the next couple of weeks -- by what we see so far is still in flow back, Sycamore probably will be towards the end of the year, we will include some Springer and Sycamore testing as well next year and just stay tune for details of specific level but probably heavily weighted towards Woodford wet gas.

Do you have a number of wet gas wells that are also, it sounds like, in terms of you had the big pulling pad, any kind of direction or quantification of what to look forward in terms of Woodford results over the next [indiscernible]?

We have another -- is it six well pad, yes, coming on.

Great, thank you.

Good morning Mike, and everyone, thanks for taking my question. Mike, hoping to just follow-up some of the earlier questions today, you just discussed kind of keeping 4 rigs, running on the SCOOP next year and perhaps two or so in the Utica, with higher working interest in the Utica, kind of how do you reconcile that with this current view of in basing gas being evacuated and potential base improving?

How do you think about capital allocation and I guess right now is it based on current strip and I guess if you saw that in basin improvement into 2018, but we see a greater share going into the Utica and I guess all of this is kind of rolling up into should we expect your 2018 program and 2019 program to be exclusively rate of return driven or are there some other goals that you are trying to achieve right now?

So certainly we are return driven as are most companies and just also keep in mind, when we talk about less activities in Utica, you have to factor in the efficiencies that Rob and Mark have been able to achieve up there, so we can do more with less, we do have acreage to hold in Utica. So we always try to find the right plan that allows us to do as we -- but to your point I think, as we look to 2019 and beyond we will be getting to close to fully held in Utica.

So I think that could be a different analysis. We are encouraged by the pricing in the Northeast for 2018.

And we do think there is an opportunity for improvement. But you also got to remember, we are getting very good pricing in our SCOOP area as well already.

And we do have additional margin that comes from those. So it’s finding the balance between the two areas.

It’s slower to drill in SCOOP, faster do drill in Utica. We can do with less.

So again, staying within that cash flow neutrality is probably the lean governor next year. Certainly returns are also critical, but right now the returns that we see for the two basins are right on top of each other, so, not as much of a concern right now.

Got it. And I guess if I could just ask one more?

As this philosophy of becoming free cash neutral is influencing decisions now, should we think about the ‘18 program as a one-year matching program with growth kind of being a coincident? Or when you are planning right now, are you thinking about sort of a three-year program of what you could deliver within cash flow?

And have you sorted out sort of the three-year production CAGR that you could achieve within cash flow?

Yes. No, we actually -- you can never plan in a bubble.

And so, we always plan out the next 5 to 10 years. So we always think about what ‘18 program does to ‘19 and ‘19’s program does to 20.

You always have to consider that. So we are certainly committed to cash flow neutrality from this point forward.

And we think we can achieve that. We said earlier 30% growth for 2018 and then ‘19 and beyond double digit growth.

We have a plan. It’s on paper.

We think we can achieve that. So we’re committed to this.

This is the new go-forward.

Okay, thanks, Mike.

Thank you.

Good morning all. Mike, as you mentioned doing more with less, can you maybe just talk about these efficiencies and maybe just specifically the drilling times in both the Utica and the SCOOP kind of maybe from the beginning of the year when you budgeted this year to kind of where you are looking at them now as we think about these change in rig counts?

Yes, this is Rob. I can answer that.

Certainly on the Utica side, we continue to make strides. Our drilling days for the third quarter is the single best quarter since we’ve been here.

So, the guys in the Utica have done a great job. And our days continue to get better in that when you spend less days on location that’s what we are looking for.

On the SCOOP side, it certainly has been challenging to say the least. For the year, we are at about 69 days per well which is kind of in line of what we budgeted.

We have been working on everything in the SCOOP. We had some recent successes for some wells much less than 70 days which is very encouraging.

We are working on consistency. We have got the right equipment in place.

I believe we’ve got the right people and we will continue to bring days down.

I would add we haven’t necessarily reached maximum efficiency in Utica, but the bigger step change has probably been recognized. I know Rob is continuing to push his folks as is Mark out there to continue to find ways to roll faster and complete faster, but small or incremented --- middle changes probably going forward, our leading edge wells as Rob mentioned out there have been very very good.

SCOOP I think is the bigger room for improvement for us. And we’ve already seen that on the leading edge wells as you might have heard in the comment.

The ability to steer and stay within zone 90% of time, that’s huge. And this play is very faulted fractured system here.

And, the more you can stay in zone using the geo-steering tools, the better off you are and the faster everything goes. It helps on the completion side.

So we’re really excited about the opportunity for improvement in the SCOOP. And we kind of feel like it’s going faster than expected, but it’s still going to take awhile.

Okay. I appreciate color.

And then just had some good success in the Woodford well so far, now that you guys have gotten a little bit more detail, I guess on the Springer and Sycamore, how are you looking at the completion and even the landing of those wells versus the Woodford? Is it very similar or are you doing a lot of different things as you start to kind of ramp up on those two formations?

This is Mark Malone. I can answer that, Jason.

Rob and I what we have we employed is a what we consider to be an optimized frac design for the Woodford, which has been roughly £2500 per foot. We apply that in our first Springer well as well.

And even though we are in early phases of flow back, we are pleased with the results thus far. So we’ll be announcing those things.

So again our intent is probably stay aggressive on the volumes that we are placing and continue to look at spacing options and how different frac designs might be employed based on this.

And we are certainly -- Mark has certainly been pushing the window on frac sizes down here. So, we are using the larger jobs.

And really if you look at the wells that we brought on line today, they are performing -- continue to perform above the type curve, and quite frankly, above offset wells as well. So we are really encouraged that we are going in the right direction on frac down here.

Quite frankly, we were told that it couldn’t be done. And we didn’t agree with that and I think we’ve proven that it can be done.

Appreciate it. Thank you, I’ll turn it back.

Thank you.

Good morning and thank you for taking my questions.

Sure.

I was just wondering if you could talk about what sort of choke management practices you are employing on the SCOOP wells? Obviously, the early time production rates have it seem like they are trending well above your type curve.

Just trying to get some sense of to what extent they are being choked back?

Well, I mean -- I am sorry, this is Mark Malone again. We are entering into the SCOOP play watching -- operators.

And we have a lot of working interest in some wells residing very near. So we didn’t start from scratch here.

We are taking the lead from our working interest partners and offset operators. So it’s right now we’re trying to determine what kind of liquids we are going to have with lot of these wells.

We are very pleased with the fact that these first wells were so liquid-rich. So it’s a work in progress.

I think this is where I am going with them. We will continue to optimize the choke management program as we progress and as we define these different windows and what kind of fluid volumes we anticipate.

Yes, at this time does that mean you currently think that it -- you could choke back the wells up a bit more or is it still kind of TBD?

Again, like I said we didn’t start from scratch. I mean we feel like where we are right now is a pretty good spot.

Again, we will continue to look at it as we progress and we will manage the gas wells little different than then the [indiscernible] wells of course. But right now, I think we are right up.

I think we are pleased with it. And certainly the wells are responding favorably to the management program.

Hey, John, it’s Paul. Similar to the approach we took in the Utica, I think we were very proactive in the Utica in taking a conservative approach.

With regard to choke management, we were a thought leader on that that approach in the Utica. We are coming down into the SCOOP here with a similar type approach.

So I think we are erring on the side of conservatism coming in here.

Okay. And then, I guess two maybe more housekeeping type question.

The 2.5 rigs and 4 rigs kind of early time thoughts on ‘18. Does that sound roughly like a 35 - 45% allocation to SCOOP, 65% to Utica, that sound kind of in the ballpark from a capital standpoint?

Hang on, we are looking at that right now. Yes, what’s your next question?

I guess just tough share seem to be trading a bit better. Is there any incremental appetite to monetize those or potentially use on the horizon?

Yes, you may or may not have seen our registration statement filed this week by Mammoth but that does give Gulfport the ability to sell stock from time to time under the S-3. So, I guess they have had lot of momentum lately.

We are really excited about the new opportunity that they have and what that means for that stock for us. And so, we’ve always talked about selling some shares along the way and that’s probably what you will see us doing at some point.

Okay. I will let something else hop on.

Thanks.

Thank you.

Hi, good morning folks. Thanks for taking my question.

I want to first start on the SCOOP, I understand that Springer and Sycamore tests are clearly to important to understanding the resource, but I think a lot of people would argue it’s equally is important to understand the quality of the Woodford across your entire leasehold position, so your drilling to-date has been fairly concentrated in the pulling pads. When can we expect to see you drill some wells kind of more than northern and western edges and maybe across the border into Carbon County?

Well, I think I agree, I don’t disagree with you. This is the play that has some variation and we have a lot more tight curves across the play.

What we’ve given you is some average type curves by area because that’s the best way for the market to look at it but we’ve done some stuff north and south and you will see us do some things in different areas next year along with additional Springer and Sycamore tests being -- the play again keep in mind there is 3000 penetrations out here. So it’s not like the expertise is not lineated but there can be variation and we do have to certainly identify where all the best sweet spots are for our acreage…

Hi, Tim. It’s Paul.

I point you to Slide 09 in our slide deck and hopefully this kind of gives you some color with regard to the de-risk nature of the Woodford here. If you look about map on the top left corner of Slide 09, the position has been peppered with well control.

So in terms of understanding the Woodford, I think we have a very good understanding from our rock property perspective. Coming in here, I think the dynamics that we brought to this, the table is certainly bringing in the modern completion techniques within its completions and the rock has certainly responded well to that.

So I feel like we got a pretty good grasp of the position as a whole, with that said to your point next year the drilling across the position while it will be fairly concentrated within the wet gas one of the Woodford, it will be across pretty wide geography of the position. So I addressed the question you had.

Okay, that’s helpful. I appreciate the color.

And then, Tom just back on kind of the CapEx issue I think you messaged last quarter on free cash neutrality was received fairly well by investors but I guess the wildcard here is what the other spending will be. If you think about the CapEx, so you kind of put an increase here on 2017 spending here that came out last night, so I guess what assurances can you give to investors that we want to see kind of a large or surprising kind of stand on leasehold in 2018?

Well first of all, I’ve already indicated that this opportunities that is a very limited going forward on the unit, the new looking units that we have scheduled to drill next year, so that’s number one. As to other spend next year, I think you can think about around $150 million, which is kind of what we went into this year for leasehold at midstream and I think you got to remember.

Well, first of all, when I say we are committed to cash flow neutrality, Tim, I mean we are committed to cash flow neutrality. So please consider those words, but also we got to think about our liquidity source as well we’ve already talked about the tough stock and you know, that’s worth I think 220 million to Gulfport that’s the source of liquidity for us, I’ve already indicated that there could be a possible dropdown of Midstream, next year that is certainly a possible even net inflow for us, so we have lots of levers to pull, we can pull back our completions, we can do lots of things down, but we are committed to that.

Okay, okay. Thanks for the comment.

Thank you.

Hi, Marshall.

I'm sorry I was muted. Thank you and thinking about the cash flow neutrality next year.

If you did have a sale or something like the Strike Force JV or some of the shares, would you consider that cash inflow that could then be spent on CapEx or is that or can you talk about cash flow neutrality you are talking strictly within cash flow from operations?

Well, when we are talking about cash flow neutrality, I think everyone knows we are talking about GNC CapEx. But look Marshall we are already delivering 30% growth next year under our cash flow neutral program for BNC.

If there is a net inflow of cash from these liquidity forces that we have. I'm not sure I think drilling more wells or completing more wells to deliver even higher production growth is appropriate.

So I think we have other opportunities that would be better. There is a host of things that we could do.

We could add leasehold and either play and there are other opportunities as well. So I don’t think adding more production growth is the appropriate thing to do.

Good. Thank you and in terms of the Strike Force JV is, how much is left?

How much has been spent there? How much has left to spend?

I think our spend if you are asking what our spend estimate is for next year? I think, we are looking at around 50 that absent a net cash inflow from a possible drop down but that would be the growth spend.

Okay. Thank you.

And then, final question.

And that should, I think that should finish it off. That’s probably the end of the answer.

All right, thank you. And one final one, you talk about not much room for the working interest to move up in '18 within the Utica, is that’s already really close to 100% or?

That’s it. The units next year are already close to I think 90%, so there is just not much room.

Okay. Thank you very much.

Thank you.

Good morning gentlemen Keri, Jessica.

Hello, Holly.

Maybe just one, there has been a lot of talk on the activity that the client rate count and no completions in 4Q, the increase and no wells being drilled in 4Q, any give or a little color on the dock? But maybe could you just give us some commentary on kind of what is historical dock levels in the Utica versus kind of where we are going to end up exiting 2017?

Yes, that’s a good question. Actually, we are looking at that to make sure we can give you some quick answer there.

So typical dock inventory that we like to carry more -- carry is around 20 docks, looks like the way it stands right now we are going to go into 2018 with approximately 60 docks.

Wow, okay. Great.

And then, maybe one for Ty just on reconciling the basis number 3Q is I think better than most people were forecasting and given your guidance, it looks like you are anticipating a fairly decent 4Q, given where things are settling out, can you just kind of help us reconcile what you are seeing right now for 4Q?

Yes, sure. July and August was rough -- there are a number of factors, pipelines were always pushed up significantly on that.

The demand was roughly light and then we had strong production growth and so as we went into September, we really start seeing some change with regards to pipeline coming on. So the pipeline that came on have limited receipts.

We were one of those exiting directly and so that has helped as well as we have just enable to with our connectivity on the midstream and our diversity on the downstream be able to move the gap in the areas that we were able to be take advantage of the premium as these pipelines continue to come on. And then, as we look into fourth quarter and the first quarter the pipeline that we come on that they don’t only come on in a phase in approach, but we are going to be seeing in upwards of 5 BCF with the expansions at the receipt point, and so do see that based on price or based on volumes going to those new projects, which will by design for Gulfport will allow us to as we move in '18 backfill into some of that area that has been vacated under this new capacity coming on.

So it’s been slower start but usually that as we go into fourth quarter as we go into next year and we do think that is a fundamentally strong story, which Gulfport will be positioned and to take advantage of.

Great. Thanks guys.

Thanks Holly.

Good morning guys. Just a quick follow-up on the dock question, can you split that dock mix between Utica and SCOOP for us in terms of 60 breakdown?

Probably 90% Utica Dave.

Okay, okay. That’s helpful.

And then, when I started to think about it, you said you have no frac crews running up in the Utica right now. How difficult it would be to add crews?

How quickly can it be done? And are there any concerns about securing efficient crews there and obviously you have relationships already but, just kind of curious to kind of get a grasp on that?

Really, it is Mark Malone. I can address that.

We are working on adding up crews now and for your call we have the agreement in place with Mammoth, which secures two crews for long-term and that we’ve got 2018 and if you remember last year we are in the 2017 I have worth my 90% of all our services locked up cross lines. We are working towards that in for 2018 right now.

So we currently have all four crews locked up that we plan to run in Q4.

So we are secured for our 2018 needs. I just want to reemphasize what Mark just said and so that’s not an issue for us and I'm sure you know, what other folks are doing about their 2018 activities, but we got ahead as it early just to make sure that we could get the quality crews and the timing that we needed and so that everything is locked them up.

That’s great. I appreciate and then one last one just we kind of think about getting that 30% growth rate yet working interest are up and well.

We start thinking about well it’s necessary to be turn to sales, can you sort of break that down for us in terms of maybe both Utica and SCOOP or how you are thinking about that? I don’t that’s a lot of detail, I can’t tell you directionally the first half of the year is going to be busier probably just because of all the completion activity we are going to have going on but do you have the…

Yes, directionally Dave what I tell you that it’s going to be slightly lower year-over-year on the term line activity, but one thing I’d highlight is because of that dock inventory. The number of rigs and the number of completions will be somewhat decoupled because we do have the benefit of those docks to drop on.

To that point, it would seem like, CapEx certainly could be buy a significantly lower year-over-year as we say, any color you can give on that, given that you are not going to be incurring those BNC?

There you go. It should be lower, significantly I'm not sure I would use that word.

But we are just trading, we are trading. In this case, we are trading some drilling dollars or some completion dollars.

Okay. I appreciate the clarification guys.

Thanks so much.

Thank you.

Good morning everyone. I was hoping Mike you talk about how sensitive the capital allocation next year is to oil prices and if oil prices are $60 or $65 range.

Whether that would materially change anything about capital allocation between SCOOP and Utica?

It doesn’t Drew. It doesn’t really change anything from us.

We are obviously the oil side of the SCOOP, liquid side of the SCOOP is priced in a very robust way. So we do like to make the disclosures in both of our play, I think you got to remember that in Utica, our activity is focused in dry gas window that’s for a lot of our equity and so I don’t think.

I don’t think oil prices really affects allocation of activity levels. We do have wet gas window, wet gas acreage in Utica we can go back to at some point in time and well we see some sustained improvement in oil and liquid prices up there will consider that.

I think we are pretty fixed on our program for next year. Drew, one thing I would add is the conversed side of that is in the northeast we are looking at a de-bottlenecking of the original basis up there.

So obviously seeing that material improvement in basis pricing on the gas side does provide an uplift as well. So you kind of have to look at those two pieces together.

Okay. Thanks.

Just a follow-up to another question, just wanted to clarify, make sure I heard that right. Someone was asking if prices were higher next year whether that would materially change your plan, did I hear that right that you were saying probably wouldn’t -- capital plans wouldn’t change it for next year?

Drew, it would not probably change your plans.

Okay. Thanks.

Thank you.

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 our call.