Jessica R. Wills - Gulfport Energy Corp. Michael G. Moore - Gulfport Energy Corp. Keri Crowell - Gulfport Energy Corp. Ty Peck - Gulfport Energy Corp. Mark Malone - Gulfport Energy Corp..

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. Ronald E. Mills - Johnson Rice & Co. LLC Timothy A. Rezvan - Mizuho Securities USA, Inc. Jason A. Wangler - Wunderlich Securities, Inc. David A. Deckelbaum - KeyBanc Capital Markets, Inc. Marshall H. Carver - Heikkinen Energy Advisors LLC John Nelson - Goldman Sachs & Co. Jeffrey L.

Campbell - Tuohy Brothers Investment Research, Inc..

Greetings, and welcome to the Gulfport Energy Corporation First Quarter 2017 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Jessica Wills, Manager of Investor Relations and Research. Thank you. You may begin..

Thank you, and good morning. Welcome to Gulfport Energy Corporation's first quarter 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; 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 website. Yesterday afternoon, Gulfport reported first quarter 2017 net income of $154.5 million or $0.91 per diluted share.

These results contain several non-cash items, including an aggregate non-cash derivative gain of $106.8 million, and expense of $1.3 million in connection with the recent SCOOP acquisition, and a loss of $4.9 million in connection with Gulfport's interest in certain equity investments.

Comparable to analyst estimates, our adjusted net income for the first quarter of 2017, which excludes all the previous mentioned non-cash items, was $53.9 million or $0.32 per diluted share.

For our 2017 program, Gulfport's D&C capital expenditures during the first quarter of 2017 totaled $238.1 million, midstream capital expenditures totaled $10 million, and leasehold capital expenditures totaled $12.1 million. An updated Gulfport presentation was posted yesterday evening to our 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 for listening in.

As announced in the press release yesterday evening, during the first quarter Gulfport reported approximately $53.9 million of adjusted net income on $226.2 million of adjusted oil and natural gas revenues, and generated approximately $143.6 million of adjusted EBITDA, and $121.7 million of operating cash flow.

The first quarter was an eventful quarter for Gulfport, experiencing yet another solid quarter operationally, driven by our assets in the Utica Shale, and closing of the acquisition of the SCOOP assets from Vitruvian II Woodford, LLC on February 17, 2017, which provides Gulfport sizeable core positions in two of North America's lowest cost natural gas basins.

Our first quarter results reflect the team's continued focus on execution, and our ability to further increase efficiencies in the field, and deliver on results ahead of expectations.

Our first quarter production of 849.6 million cubic feet per day came in above expectations, driven by the continued strong performance of our Utica Shale assets, and the team's ability to track ahead of expectations for expected turn-in-line dates during the quarter.

In addition, during the quarter, we commissioned a field-level compression in an affected gathering area in the Utica Shale, and the initial results performed above expectation relative to downtime, and the response seen at the wellhead both contributing favorably to production for the quarter.

Since the SCOOP closing mid quarter, we had 43 days of solid performance from the SCOOP assets, and have been running four operated rigs on the acreage. On the realization front, we posted strong first quarter results, illustrating the benefits of our existing marketing portfolio in the Utica Shale.

To further complement this and secure the movement of Gulfport's anticipated SCOOP production, during the first quarter, we executed a firm transportation commitment with Midship Pipeline Company, a wholly-owned subsidiary of Cheniere Energy on the Midship Project.

With this agreement, we secured foundation shipper status with a minimum commitment of 135 million cubic feet per day, providing our molecules delivery to premium end markets beginning in early 2019.

All in all, we accomplished a lot during the first quarter, and are building upon this momentum as we look to carry out the remainder of our 2017 activities. On the operations front, in the Utica, the team continues to focus on identifying and increasing efficiencies, and had another solid quarter in the field.

On the drilling side, during the first quarter, we spud 26 gross wells utilizing six rigs. The wells drilled during the quarter had an average spud to rig release of 20.9 days, a decrease of 23% year-over-year with an average lateral length of 8,145 feet.

We continue to exceed our drilling records in the play; and during the first quarter, meet our average full well footage drilled per day, drilling an average of 1,191 feet per day, resulting in one well having the spud to rig release of just 16 days.

Turning to completions, in the Utica Shale, we turned-to-sales five gross wells with an average lateral length of 9,431 feet during the first quarter.

We began to ramp horsepower during the second half of the first quarter as planned in our budget provided in February, completing 637 stages during the quarter, and setting up for an active turn-in-line schedule for the second quarter.

Approximately 38% of our Utica completions during the first quarter included fracture treatment designs of greater than 2,500 pounds per foot, and our average for the quarter was 1,830 pounds per foot for all stages, demonstrating that we continue to push the envelope on our completion design in the Utica.

We continue to benefit in the field from our vertical integration efforts with Mammoth Energy. And to our knowledge, we together continue to run one of the most efficient crews in Appalachia today. In addition, to accommodate the rampant activity during the quarter, we chose to utilize an incremental crew with Evolution Well Services.

At Gulfport, we strive to be a technology leader in the space, always looking to enhance our processes, improving efficiencies in the field and the overall productivity of our assets, while at the same time being good stewards of the environment.

Evolution utilizes custom-designed electric equipment, and technical expertise to deploy 100% electrically powered frac spread.

The entire spread, containing 25,000 of available horsepower, takes up exactly one-third of the space of the conventional fleet, particularly valuable in Appalachia, where pad construction is challenging and costly due to the terrain.

In addition, the fleet is powered by natural gas fuel, less costly and a cleaner burning fuel than diesel; and can be sourced by our own field gathered gas. We are very encouraged by this technology and are excited to work with them as they complete their first pad in Appalachia.

Incorporating both the drilling and completion activities during the first quarter of 2017, we estimate that Gulfport's Utica well cost averaged $1,090 per foot of lateral, in line with expectations, and including the completion of a one-well pad, which increased the averages; it was burdened with the full pad cost.

Excluding this pad, we estimate Gulfport's Utica well cost averaged $1,052 per foot of lateral during the first quarter of 2017, approximately 2% below Gulfport's average well cost in 2016. In the SCOOP, we closed the acquisition on February 17, and have had a seamless integration of the assets into our portfolio.

Our teams got to work immediately, working towards identifying areas we can approve upon by applying our learnings from our operations in Appalachia as well as our staff's extensive experience of operating in the Mid-Continent region.

On the drilling side, during the first quarter, five gross wells were spud on the acreage, utilizing four operated rigs. The wells drilled during the quarter had an average spud to rig release of 62.4 days, and an average lateral length of 7,856 feet. Gulfport is currently running four rigs in the play.

And to-date, activity during 2017 has been focused on the Woodford. However, we continue to plan to test other horizons on the positions this year. In addition, we have started the regulatory process for permitting both the Springer and the Sycamore location, and plan to spud those wells during the summer.

As many of you have seen, Ward Petroleum, one of our peers and a private operator in the SCOOP, recently announced the Sycamore well in central Grady County, and the well is located right in the middle of the Gulfport acreage position.

The Lynda well had an initial rate of 2,800 Mcfe per 1,000 foot of lateral, and a strong oil cut of approximately 24%. In addition, Continental Resources recently announced two strong Sycamore results with the plans to drill an additional five to seven wells during 2017.

Lastly, Newfield announced an exploration initiative to test prospective horizons, including the effort to better understand the Sycamore and Caney in the SCOOP. We are very pleased with all these results and encouraged by the near-term increase in activity by us and other operators to identify the scale and scope of these horizons.

From a geologic perspective, the Sycamore is age equivalent to the Meramec and Osage horizons currently being developed up in the STACK, and is sandwiched between the Woodford and Springer Shales in the SCOOP. We estimate the Sycamore to be over 250 feet thick across the Gulfport position, presenting a significant future development target.

As we look towards Gulfport future development plan, the Sycamore represents not only a significant upside to prospective resource across the acreage, and a meaningful increase to develop hole locations, but also a potential contributor to increasing the liquids mix of our current production base.

Today, we estimate Gulfport holds approximately 40,000 net reservoir acres in the Sycamore. On the completions front, Gulfport recently completed and turned-to-sales two gross wells located in a wet gas window in southern Grady County. These wells were drilled by Vitruvian and marked Gulfport's first completions in the play.

We have a large sample set of wells completed at sub-1,000 pounds per foot. And as we designed the completion for this pad, we elected to push the envelope right out of the gate beyond the standard Generation 4B design, establishing a barbell curve with respect to our operated results.

The Vinson wells were completed, placing an average of 2,400 pounds of proppant per lateral foot, nearly double the amount of proppant volumes when compared to historical practices for the area in any of the offset producers.

The team in the field executed this enhanced design according to plan with a peak efficiency of six stages in the 24-hour time period, and an average of 3.6 stages per day.

When we compare this to the recent results from our peers in the play, this level of activity is in line with the most efficient operators in the play, albeit the design on this pad included significantly more proppant than what we have seen from our peers, highlighting the efficiency of our team.

The Vinson 2 has a lateral length of 8,539 feet and was completed with 48 stages. While we are still in the early stages of flowback, the well has reached a 24-hour initial production rate of approximately 14.6 million cubic feet a day of gas, and 57 barrels of oil per day.

The Vinson 3 has a lateral length of 8,475 feet, which was completed with 47 stages and reached a 24-hour initial production rate of approximately 16.9 million cubic feet of gas, and 48 barrels of oil per day.

Again, it is early in the producing life of these two wells, but we have witnessed several key indicators during the flowback of the wells that indicate these wells to be top performers relative to their offsets.

We currently estimate that the bottom hole flowing pressure of the Vinson wells may be as much as 900 psi greater than the average of the offset producers.

In addition, despite flowing these wells more gingerly than the standard practice of our peers, the two Vinson wells started producing gas over 48 hours earlier than all of the other offset producing wells.

Finally, in our analysis, we normalized production from all wells to a 7,500-foot lateral length and found that after approximately 500 hours of flowback production, the Vinson wells are outperforming the average of direct offset producers by approximately 30%, and outperforming the current wet gas type curve presented in our public slide deck by as much as 35%.

Bear in mind, we are still early in the flowback process, and we would expect these wells to continue to clean up and potentially improve further beyond the rates provided today. We are pleased with the results from these new wells.

And while it is still early, we would expect both of these wells to be among the top wells completed in the play to-date. On our call in February, we discussed the current service cost environment and our focus on locking in the benefits of lower pricing.

Beginning in May 2016, Gulfport locked in approximately 85% of our Utica drilling and completion cost for 2017, and continue to work towards extending that even further into 2018.

In the SCOOP, we recently completed an RFP to secure the major AFE line items through 2017 and beyond, reaching out to not only previous vendors for the asset, but also leveraging Gulfport's buying power and key vendor relationships from the many years of continuous operations in Appalachia, including our vertical integration partnerships.

We have four rigs contracted in the SCOOP, two locked in for the remainder of 2017, and two up for renewal early in the fourth quarter, which our team is actively engaged in extending the contracts into next year.

With regard to pressure pumping, by leveraging Gulfport's historical vendor relationships and optimizing the well design, on our first operating completion of the play, we were successful in placing nearly double the amount of proppant at a cost of approximately 20% less per stage than the average historical completion cost of the operated wells.

We were very pleased with this performance and have services secured to accommodate our frac schedule for the remainder of the year. While we do expect some service cost inflation, which was included in our 2017 budget, we have been active at locking in the major line items of the AFE.

More importantly, we have been working diligently towards putting in place initiatives to further improve upon efficiencies in the field, which we believe would more than offset any increases that we may realize.

For example, first, we are indentifying the optimal landing zones that hold not only the best ultimate recovery, but also the highest drilling penetration rate to decrease drill days. Second, the team is reviewing fracture fluid additives, proppant types, and optimum injection rates and volumes to reduce stage costs.

Third, we are testing slickwater systems in order to eliminate gel fluids to reduce cost. Fourth, the completions team is bearing the fracture stimulation design, including reduced stage length, limited entry cluster design and maximized proppant placement.

Fifth, similar to our operations in the Utica, we will implement Gulfport's post-frac drill-out practices, which includes the landing of production tubing immediately following drill-out. And lastly, we will utilize all available technology and equipment at-hand to enhance cycle times, and reduce non-productive time over historical results.

We believe all of these items will ultimately increase efficiencies in the field and reduce cost. I will now turn the call over to Keri to discuss the specifics surrounding the first quarter financial results..

Thanks, Mike. Our success on the operational front led to strong financial results during the first quarter, highlighted by robust production and higher realized pricing, ultimately improving our bottom line and cash margins.

Total net production for the first quarter came in ahead of expectations and averaged approximately 849.6 million cubic feet of gas equivalent per day, a 23% increase over the first quarter of 2016, and an 8% increase sequentially.

Strong well performance, solid operational run time and execution in the field, as previously mentioned by Mike, all led to the outperformance during the quarter.

We exited the quarter strong, and Gulfport anticipates the second quarter to be an active quarter for turn-in-lines in the Utica Shale, making the growth trajectory for the company more weighted toward the middle of the year.

During the second quarter, we anticipate reaching a significant milestone for the company, and currently forecast, for the first time, net production during the quarter to average in excess of 1 billion cubic feet of gas equivalent per day.

Reaching 1 Bcfe per day of net production is a remarkable achievement, and is a reflection of both the quality of our assets, and the execution of our team.

On the realizations front, our first quarter 2017 realized natural gas price, before the effective hedges and including transportation costs, totaled approximately $0.63 per Mcf below the average NYMEX price. As expected, this is slightly wide off the full-year guidance range.

However, as we integrate the SCOOP assets into our corporate profile, we anticipate to realize an uplift in pricing, given its close proximity to multiple physical pricing hubs, and reiterate our full-year guidance of $0.56 to $0.62 per Mcf off NYMEX monthly settled price for natural gas.

Before the effect of hedges, our realized oil price came in at $4.34 off WTI, and our first quarter realized NGL price came in approximately 51% off WTI, both above our previously provided public guidance.

For oil, given the recent strength we have seen in the Utica, and the uplift expected in the SCOOP, we now expect to realize approximately $3.75 to $4.75 off WTI. With regard to NGLs, on our call in February, we noted we were starting to see what we believed was the beginning of a supply/demand rebalance in the Northeast with regard to NGLs.

And as illustrated in the strong realizations during the first quarter, we have witnessed this rebalance bring NGL prices back to historical norms. Taking this into account, we are updating our guidance, and now expect to realize approximately 45% of WTI for natural gas liquids for 2017.

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 60% of our expected 2017 natural gas production, including nearly all of our anticipated volumes from the SCOOP acquisition swapped at $3.18 per Mcf.

We have also been active in securing a base load for the outer years, and continue to opportunistically layer on additional hedges, and base a swap to provide line of sight to our realizations and cash flows. Turning to cost, the Gulfport team continues to control cost in the field.

And during the first quarter, our per unit operating expense, which includes LOE, production tax, midstream gathering and processing and G&A, totaled $1.10 per Mcfe, in line with the fourth quarter of 2016. First quarter lease operating expense totaled approximately $0.25 per Mcfe, down 9% sequentially and 5% year-over-year.

First quarter midstream gathering and processing expense totaled approximately $0.63 per Mcfe, which is slightly up sequentially following the commissioning of compression in the Utica Shale, and the integration of the liquids-rich SCOOP assets.

First quarter G&A expense totaled approximately $0.16 per Mcfe, an increase of 14% sequentially, given the acquisition, and a decrease of 2% year-over-year.

As we stated on the fourth quarter call, we expect all per-unit operating expenses will decrease further, as we progress through the year due to economies of scale ultimately improving overall margins. Moving on to the balance sheet, Gulfport completed its spring borrowing base redetermination following the closing of the SCOOP acquisition.

Including the addition of reserves from the SCOOP, Gulfport's lenders approved an increase in the company's borrowing base from $700 million to $1 billion. In connection with this process, Gulfport is pleased to announce that JPMorgan, Commonwealth Bank, ABN Amro, Fifth Third, and CIBC have joined as part of the company's expanded lender group.

As of March 31, Gulfport had approximately $102.5 million of cash on hand, and $40 million drawn on our revolver. Pro forma for the recent borrowing base increase, our liquidity totals approximately $825 million, providing significant flexibility as we continue to carry out our 2017 activities.

We continue to adhere to our commitment of funding our 2017 activity through operational cash flow, and available sources of liquidity, while also maintaining reasonable leverage metrics and, at current strip prices, forecast to remain within our leverage target of 2 times to 3 times debt to trailing 12-month EBITDA at year-end 2017.

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

In closing, to summarize our first quarter, operationally, we continue to show consistency in our ability to execute in the Utica Shale, increasing efficiencies in the field and experiencing another solid quarter on both the drilling and completion fronts.

We closed our SCOOP acquisition and hit the ground running, as we integrated the asset into our portfolio, and we were able to share two exciting well results with you today.

We have plans to test multiple benches on our SCOOP acreage this summer, advancing our understanding of the Springer across the position, and potentially de-risking a significant amount of incremental inventory with our Sycamore test.

Financially, we continue to focus on reducing cost and improving margins, and boosted by our strong realizations during the quarter, witnessed a 12% increase in cash margin over the fourth quarter of 2016.

We have locked in approximately 85% of services in the Utica, and essentially all the major services in the SCOOP and, when combined with efficiency gains, should provide Gulfport increased certainly to our future well cost and operational hedge against anticipated pressure on service cost.

Our balance sheets remain strong, and we'll continue to fund our 2017 activity within available sources of liquidity. Looking ahead, the future is very bright for Gulfport. We have the right assets and the right team, which is backstopped by a solid financial position.

As we execute on our long-term development plan in the Utica and the SCOOP, Gulfport is positioned to deliver peer-leading growth from our premium assets for years to come. Doing so, while maintaining the strong financial conditions of the company and creating long-term value for our shareholders. This concludes our prepared remarks.

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

Thank you. Our first question is coming from the line of Neal Dingmann with SunTrust. Please proceed with your question..

Good morning, Mike, Keri, and team. Mike, first question. You talked a little bit about – you mentioned, I think, in your prepared remarks, you and Keri both talked a lot about, what I'd say, the financial and operational flexibility you have.

And so, when I look at the 10 rigs out there, how could that change towards the end of the year? I guess you mentioned that Sycamore and Springer doing maybe potentially well on each of those in the summer.

So, if those come on, like some of the peers we've seen, would you drill more of those? Would you maybe reallocate that 10 rigs? If you could just talk about the flexibility towards the end of the year and going into 2018..

Well, first of all, let me say that we are committed to the CapEx budget that we lined out earlier this year. These tests that we're going to drill at Sycamore and Springer are one well test. So, they don't add a lot of incremental CapEx for us.

But listen, if we get in the back half of the year and we're ahead on drilling and ahead on completions, we have the optionality to drop a rig or two or we can build a completion inventory and hold it to 2018. Now, what I would say on the Springer and the Sycamore is, we're going to drill those wells this summer.

We're going to get the results probably in the fourth quarter. And that's plenty of time to incorporate that. Our thought process is around that future activities into our 2018 planning process. But keep in mind, we're also – there's a lot of information coming out from other operators around us as well on the Springer and Sycamore.

Continental's put out some really good wells and information. And so, I think as far as, particularly, as it relates to the Springer and Sycamore, it helps form our thoughts around levels of activity there in 2018. So, probably not much change to 2017..

And Mike, kind of tied in to that question, how would it change – I notice on that slide 7, you all updated both for the wet gas and the conde for the single well economics for Utica and SCOOP.

So, I guess my question kind of centering around the same thing, if NGL prices continue to climb as we've seen in both plays, would that – I assume, then that would tie in to potential change of plans as well?.

It's a good question. So, the one thing we like about our portfolio is the optionality that we have, the exposure to different commodities. Certainly, one of the things we liked about SCOOP, specifically, was the liquids NGL exposure, but priced in a better way than Appalachia.

So, certainly, as NGL prices continue to improve, we will recalibrate our thoughts around activities in the different windows. Obviously, you can see the SCOOP wet gas returns are comparable to the Utica dry gas returns, but if NGLs continue to improve, we can certainly make different decisions about where to allocate our rigs.

And again, the optionality of our portfolio is one thing that I think is pretty unique to us..

Got it. And then, maybe last question for Ty. Looking at slides 21 and 22, where you outlined your FT sales outlets as well as your FT portfolio, Ty, you show, I think especially in 22, how the diffs are going down. Does that incorporate – I mean, you've got a lot of production growth coming here in the next year or two or three.

If you could just talk about kind of your expectations for how you've tied in those diffs as production ramps in both the plays?.

Yeah. Good morning, Neal. We looked at 2017 and we always thought it was going to be a pivotal year. And it is playing out as we expected. And while we didn't – we knew it was going to be pivotal, but we didn't know the exact timing of that pivot. And so, what we did beforehand is set up a conservative approach as we entered into 2017.

And as we mentioned last time, we expect to sell all but 5% under our firm arrangements. But by design, and really highlighted in slide 22, is that we will continue to grow past 2017 beyond our FT portfolio, which is there on that slide 22, the lower right box.

And in fact, to show the impact of that, we went ahead and put in that bottom line as the Dom South pricing as we look at the strip going forward. And so, you can see that it benefits us to sell into basin prices as we go into 2018 and 2019 as these projects – these FT projects come online..

Very good. Great wells, folks. Thanks..

Thanks, Neal..

Thank you. The next question is coming from the line of Ron Mills with Johnson Rice. Please proceed with your question..

Good morning..

Good morning, Ron..

Hey. Thanks for the second quarter production guidance, but one of the things you talk about is a much more active turned in line numbers during the second and third quarter. I know you only turned in line about 7% of your expected total in the Utica in the first quarter, and very few of SCOOP, obviously.

But how do you think the quarterly progression is or moves in turned in lines between – over the remainder of the year by quarter?.

Well, again, I think the heavy quarters for us, for turn-ins are going to be the second and third quarter, Ron. And in the second quarter, because of that, you will see us probably in excess of 1 Bcf of gas for the quarter. We will still have growth in the fourth quarter. It just won't be as robust as the second and third quarters.

So, again, second and third quarter are shaping up to be a heavy turn in line schedule for us..

Great. And you highlighted both Ward, Continental and other guys' Sycamore activity.

Have there been very many offsetting Springer well results around you as well as you look to test that formation here this summer?.

Continental certainly has some nice Springer test. And we put a new slide in the deck this time that shows some of the offsets, Ron, but yes, there are some offsets for us..

Okay.

And then, lastly, just on the SCOOP type curve, I know it's very early, but your type curve as designed versus the completion design you are using in your first wells and presumably going forward, what's the point of comparison in terms of your type curve, i.e., number of – stage length and proppant levels versus the way you're completing them with 2,400 pounds and 180-foot spacing?.

Well, Mark, do you want to take that?.

Well, we started out on (33:18) trying to be as aggressive as we could. You know what I mean? (33:22-33:28) we're trying to get as aggressive as we could. If you look at slide 31, it's the evolution of the frac design that took place and (33:34) design is about as aggressive as the (33:38).

So, we tried to get more aggressive than that (33:41) pounds per lateral foot in the original designs here..

So, Ron, when we put those original type curves together, obviously, for the acquisition economic analysis, we were trying to be conservative. And so, we were using historical practices for the proppant assumptions. So, most of those were sub-1,000 pounds. So, they weren't – those type curves weren't inclusive of the upside fracs.

And so, certainly, that's part of the reason you're seeing a big difference. But we certainly thought there was an opportunity here to increase the amount of sand that we were pumping. And we were able obviously to do that on the Vinsons and place more than twice the amount of sand in the Vinson well.

So, the historical, the type curves that are represented in our presentation are the historical practices..

And that's the reason for the question because if you were using – if the historical average is based on the weighted average number of wells at levels of proppant, I mean, you're well over 2x the proppant levels, and so I'm trying to get a sense as to upside. But I appreciate....

I think last comment, Ron, just certainly based on what we've seen, so far, although it's just two wells with the upsized frac jobs, certainly, the thought process would be, at some time, that we would revise those type curves up..

Great. All right, guys. Thank you so much..

Thank you..

Thank you. Our next question is coming from the line of Tim Rezvan with Mizuho. Please proceed with your question..

Hi. Good morning, folks..

Hi, Tim..

I know it's early days in the Sycamore. Slide 11 has some pretty encouraging results.

As you kind of go through the permitting, have you identified where you're going to be drilling the first Sycamore test? And as a related question, do you have any insight on the variabilities in the oil cuts from offset operators?.

Well, it's interesting. I thought – we thought somebody might ask where that test is going to be. So, we've been looking for a spot for those tests that would de-risk as much as our acreages possible, kind of between our wells and pure offset. So, we're going to be drilling in the southeast Grady County. It's where those tests are going to be.

And then, your second question was about the variability. So, I'd say that phase windows here should mirror the phase windows of the Woodford. Sycamore generally follows the same phase windows..

Okay. I appreciate that color. And then, as we think about where your rigs are now in the SCOOP, I know slide 25 has some color.

I guess how do you think about the biggest priority with the 20 spuds you have planned for 2017? Kind of I guess what's the biggest priority with where you're drilling?.

Well, I think the priority for us, remember, we inherited – we just closed on this February 17. So, we inherited, if you will, the planned locations for this year, obviously, as you heard us talk about, these are mostly Woodford wet gas locations. So, that will be where the bulk of our activity is focused this year.

But that gives Mark and his team an opportunity to work on improving the completion technique, to test some different things. Right now, the Woodford wet gas is certainly our highest return, but we're of course trying to balance that with de-risking our entire position.

We're happy that we're able to accelerate our testing of the Sycamore and Springer. When we originally talked about it, we didn't think we were going to be able to get locations ready until late this year. But we certainly accelerated that, encouraged by the activity and success of some of the other operators.

But this year will be a year of both de-risking, I think, but also improving the completion techniques out here, and the drilling techniques as well. Obviously, Rob can drive some efficiencies, too..

Okay. And then, I guess, one last follow-up. You talked about 62 days spud to rig release.

Do you think that's something that going to be worked on meaningfully this year?.

This is Mark Malone. Yes, there's no doubt. I mean, if you recall, out of that 62 days of the (39:03) historically at that point. So, the problem within the Utica Shale, we were in excess of 45 days at the time we (39:12). There is no reason to believe that (39:14) good times here as well..

Okay. I'll leave it there. Thank you..

Thanks, Tim..

Thank you. Our next question is coming from the line of Jason Wangler with Wunderlich. Please proceed with your question..

Hey. Good morning, guys..

Hi, Jason..

Hey, Mike. Just curious, so just sticking with the SCOOP for one. We talked a lot about the well results you're seeing up there. Are you seeing any that you're participating in? I know most of your acreage is operated.

But are you seeing any proposals or even getting into any non-operated wells up there as you kind of start to formulate your plans into the Sycamore and Springer?.

Yeah. Jason, we're in a lot of those wells. So, we're getting data as a non-operated interest in a lot of those wells up there. So, yes. The answer is yes..

Okay. Great. And just, you talked about it on your prepared comments up in the Utica about that kind of unique frac.

How long ago was that done? And is there any other color of how it went off? And even if it is something that you look at doing again here as we kind of look forward?.

Jason, I'm not – a unique frac in Utica?.

Yeah. Yes. Sorry..

Oh.

The evolution of frac equipment?.

Yeah..

Yeah. Okay. Okay. Sorry, I misunderstood your question..

No. You're good..

Yeah. So, we're excited about being able to – being the first – first of all, to bring that equipment to the Northeast. And I'll let Mark step in too, because he's the one who's been running the job..

Well, the evolution fracture really is about pad locations and sites. The locations up in some parts of Southeast Ohio are (41:01) fracture is really (41:02). The other piece is the fact that they run on natural gas. And as a natural gas producer, that's something we feel strongly about doing. And also, it's a clear burning fuel as opposed to diesel.

So, it's something we're really excited about. And just finished up their second pad for us, in fact (41:18)..

Just to give you a little more color on that, Jason, the thing that we really like about obviously is that it's environmentally friendly by using a third of the footprint, but these locations up there can be really challenging. It's a very mountainous terrain. So, those locations can be costly, because of that challenge.

So, it's going to allow us – it could allow us to save quite a bit of money on our location, build and design..

Great. I'll turn it back. Thank you..

Thank you..

Thank you. The next question is coming from the line of David Deckelbaum with KeyBanc Capital Markets. Please proceed with your question..

Morning, guys..

Hi, David..

And nice job with the first SCOOP completions.

I had a question for you guys, maybe, Mark, just the drilling costs for the SCOOP wells, what your thoughts were kind of initially relative to expectation? And then, based on the type curves that you guys have put out there, what do you think as a, sort of, reasonable 12-month cost reduction target as you kind of compare your well designs to some of the peer well designs out there?.

This is Mark. You got to keep in mind that the two wells that we turned in line, the Vinson wells, were actually drilled by the (42:38-42:43) we were able to place about 2,400 pounds of proppant (42:46) up to 20% reduced cost. So, even though the drilling cost went higher, we're really proud of what we did on the completion side..

So, David, we have a lot of initiatives that we're working on up there, different pit programs. We're also working on being very, very precise on how we land our wells, which should make for more efficient drilling. It's hard to quantify exactly how many days we can cut down on both the drilling and the completion side.

But we do have quite a few initiatives. Some of those are enumerated in my scripted comments as well. Mark has been very efficient on the completion side. And as he mentioned, he placed twice the amount of proppant at 20% less cost than the historical jobs up there.

So, I think we can make some significant inroads this year, and that's – we're going to work hard on that. So, can we cut down the 62 days of drilling? Historical averages were 60 to 70 days. So, we're already on the low end of it.

But yes, I think there is certainly room for improvement, if you think about how quickly we advanced in Utica in just three years' time. But hard to quantify exactly where it might end up at this point..

I appreciate that, Mike. And just, I guess, similarly, the Springer cost assumptions, I guess, before you have a test, do you guys I think forecast a cost per foot in like the 1,400 per foot range. I guess as you compare that to the Woodford, in most cases, it seems to be more expensive except for the deeper dry gas.

Is there a reason why you think the Springer wells would be more expensive on a lateral foot basis, or is that just conservatism until you drill your own?.

I think it is conservatism, and it's associated with drilling times. But we'll wait and see, David, but we are trying to be conservative there..

Okay. Great. And then just the last one for me is just on the Midship Pipeline, the nomination of volumes start up end of 2019, I guess.

Do you foresee, I guess, in the interim, one, I guess how do you see that providing an advantage to you beyond, like, 2018 going into 2019? Do you see those volumes as being required for your gross program? And can you give us sort of a flavor on what the cost is like on that transportation?.

Yeah. This is Ty. I'll start off to say we inherited good FT portfolio from our predecessor. But we have definitely day one started building on to what we felt like was needed. And the biggest add there was that foundation shipper status on Midship.

While we like the Midship project, as it was a new pipe, new competition in the area, it comes on with demand into the LNG. And it's backed by quality shippers, so it is going to be executable. As far as the area, we think that it's a good start. I will back up.

The Midship project will come on early 2019, but then you're also seeing, just recently, Enable has announced two projects that are bringing on upwards of 600,000 (46:24) beginning early 2018 and through 2019. And so, what we saw coming on is that there is a lot of rigs coming into the area.

And what we didn't want to get into and what we're not getting into, or getting ahead of it, is any kind of constraints or anything like that. So, the projects are getting done, which is good. The projects are getting done by all the players in the basin. And so, we feel comfortable that we got in a good portfolio.

And yet, at the same time, just in Utica, we're rightsizing it for Gulfport and the production Gulfport is adding to that basin..

Thanks, guys..

Thanks, David..

Thank you..

Thank you. The next question is coming from the line of Marshall Carver with Heikkinen Energy Advisors. Please proceed with your question..

Yes. You're off to a really quick pace in terms of wells spud in the Utica in 1Q. Would you plan on dropping a rig in the second half of this year to stay within the expected – original expected plan, or would you maybe drill and complete more wells? And what would be the – I guess, two questions.

What would be the key determining factors in that decision, and when do you need to make that decision?.

Marshall, as I mentioned earlier, we're going to live within our CapEx budget for 2017. We are off to a fast start. We do have some flexibility with our rig contracts. So, we could think about an adjustment there, if we get ahead; or we could choose to hold up on some completions.

But I think you have to keep in mind we do believe that there's room for efficiency gains this year, so we think we can get more with less. So, there's a lot of moving pieces here, Marshall, but just rest assured that we're going to live within our CapEx budget. And we have lots of levers to pull and lots of flexibility.

But again, we also have some future efficiency gains that will play in that as well..

All right. Thank you..

Thank you..

Thank you. The next question is coming from the line of John Nelson with Goldman Sachs. Please proceed with your question..

Good morning. Congrats on the update, and thank you for the incremental data you guys released in the slide deck over the quarter..

Sure..

Thank you..

I wanted to circle back to David's question, hoping to discuss the MidCon gas marketing strategy a bit more.

Post the Midship pipeline agreement, are you done securing FT out of the region? Or how should we think about under what terms or what netbacks you'd be looking for to maybe sign additional FT contracts?.

Yeah. I would say that, again, we feel like we're off to a good start, and it's the same kind of plan that we approached Utica on is, if we see things shifting where we need to add FT, we are always willing to do that. FT is not always a solution, though.

There's other things as far as firm arrangements with shippers already on the pipes as well as getting into the capacity release on a shorter-term basis.

But there is a lot of different levers to pull that we've been willing to do and we have done in Utica, but always with the intention that we do our part, but that we keep it right-sized to the growth portfolio to which we need to move the production.

First of all, our day-in, day-out is to move the production, and then add incremental value where we can. And as far as netbacks are concerned, I think whatever we showed on our type curve slide deck is kind of where we're targeting and we feel comfortable with.

The one thing I will say is that with Midship, one of those – the foundation shippers, as they've alluded to in the past, that you do have some flexibility to move up as that project continues. So, we have some flexibility of things to pull if we see that the basin dynamic is changing.

And the other thing I like, too, is it's – we talk about gas, but it's also an NGL and oil play. And if you look at where that location of the SCOOP is, we have good access to Cushing. We have good access to the south. We have good access to Belvieu, Conway. The market hubs are right there, and that is a big benefit when we look at SCOOP..

Okay. Just to be clear on that, because I'm not sure, so what level of FT or what is the OpEx structure that's built on the SCOOP returns in the slides then? You said that we should kind of (51:26)..

Yeah. I think we're showing that $0.45 back from NYMEX for the SCOOP assets, somewhere around there..

Okay. That's helpful. All right. I'll let somebody else hop on. Congrats on the quarter..

Thank you..

Thank you. Our last question is coming from the line of Jeffrey Campbell with Tuohy Brothers. Please proceed with your question..

Good morning, and congratulations on the strong quarter..

Good morning..

Mike, I was just wondering, could you just kind of round numbers tell us how many more of the upsized SCOOP completions you intend to tie in line during the rest of 2017, and maybe what's the quarterly cadence of those completions?.

I would say most of the completions this year for SCOOP will be the upsized completions. I'm not sure of the exact tie-in-line schedule. I think the cadence is more weighted towards the second half though from a tie-in-line schedule for the SCOOP..

Okay.

So, then maybe it's fair to think that, I mean, since these wells are outperforming, if they continue to do it, it may have a positive productive effect on 2017, but maybe even a more enhanced effect on 2018, is that maybe a general way to think about it?.

Yeah. I think that's a great question actually, because I think what this does is set us up really nicely and propels us into 2018, and we can think about 2018 in a certainly much different way. But yes, I think the impact – we will have some impacts certainly in 2017, but certainly a big impact in 2018.

Okay. And I've been just wondering, bearing in mind that the first – these first two SCOOP completions, they were your completions, but the wells were drilled by the previous operator.

Do you see any potential to improve future results once Gulfport begins drilling these wells, perhaps, better zone landing or timing zone?.

Well, listen, as I mentioned, we think there is a lot of things we can do here. Apparently, Vitruvian was a good operator, and there are lots of other good operators out there as well. Our guys have a lot of experience in this area, they've drilled a lot of these wells, and we certainly have over 300 wells drilled up in Utica.

So, we have a lot of things that we're planning to try that we think will improve efficiencies on both the drilling and completion side. I mentioned different kind of a pit program. I mentioned landing in zone, rotary-steerable is something that we're going to use that hasn't been used consistently here. We think that's going to help a lot.

We have a, I would say, a shopping cart full of things, Jeff, that we're going to try. And Mark, I think, has a few things he wants to mention as well..

Yeah. I think both from a production perspective and also drilling perspective, we can benefit from more targeted landing zones. So, we're going to continue to push the envelope both from the drilling and completion side. And I think you will see more of the enhanced completions going forward..

Great. Thanks.

Let me ask just one final question, and this is kind of a broad one, but what I'm really thinking about here is just maybe what holding by production needs are versus your longer development view? Just wondering going into the Springer and Sycamore tests, if they're successful, near term, are you more likely to develop either interval as a stand-alone target or might then some way accelerate progression towards multi-well pad development, maybe multi-interval pad development?.

I think right now we're focusing on single well targets. Now, keep in mind our acreage position is 80% held by production here in the SCOOP, which is one of the things that we really liked about it. So, we don't have a gun to our head. At some point, we could think about multi-target situations, Jeff.

But right now, we're focused on de-risking and identifying the Sycamore and Springer..

Okay. Great. Thanks. I appreciate it..

Thank you..

Thank you. We have reached the end of our question-and-answer session. I would now like to turn the floor back over to Mr. Moore for any additional concluding comments..

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..

Ladies and gentlemen, this does conclude today's teleconference. Again, we thank you for your participation, and you may disconnect your lines at this time..