Gulfport Energy Corporation (GPOR) Q2 2016 Earnings Report, Transcript and Summary

Greetings and welcome to Gulfport Energy Corporation’s Q2 2016 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Ms. Jessica Wills. Thank you. You may begin.

Thank you, and good morning. Welcome to Gulfport Energy Corporation’s second quarter of 2016 earnings conference call. I am Jessica Wills, Manager of Investor Relations and Research. With me today are Mike Moore, Chief Executive Officer and President; Ross Kirtley, Chief Operating Officer; Aaron Gaydosik, Chief Financial Officer; Keri Crowell, Chief Accounting Officer; Paul Heerwagen, Vice President of Corporate Development; and Ty Peck, Managing Director of Midstream Operations. I would like to remind everybody that during this conference call, the participants may make certain forward-looking statements 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 a second quarter 2016 net loss of $339.8 million or $2.71 per diluted share. These results contain several non-cash items, including an aggregate non-cash derivative loss of $198.7 million, a loss of $170.6 million due to an impairment of oil and gas properties, a loss of $0.8 million in connection with Gulfport’s interest in certain equity investments and an adjustable tax benefit of $0.2 million. Comparable to analyst estimates, the adjusted net income for the second quarter of 2016, which excludes all the previous mentioned noncash items was $30.4 million or $0.24 per diluted share. During the six-month period ended June 30, 2016, Gulfport’s D&C capital expenditures totaled $230.7 million, midstream capital expenditures totaled $3 million and leasehold capital expenditures totaled $32.5 million. In addition, Gulfport invested approximately $13.7 million in Grizzly Oil Sands during the six-month period ended June 30, 2016. An updated presentation was posted yesterday evening to the website in conjunction with yesterday’s earnings announcement. Please review at your leisure. At this time, I would like to turn the call over to Mike Moore.

Thank you, Jessica. Good morning, everyone, and thank you for listening in. As announced in the press release yesterday evening, during the second quarter, Gulfport reported approximately $30.4 million of adjusted net income on $170.5 million of adjusted oil and natural gas revenues and generate approximately $102.2 million of adjusted EBITDA. On our earnings call in May, we discussed a few key leading indicators Gulfport monitors as we consider the appropriate level of activities for 2017 and beyond. Since that time, all of these indicators have moved in our favor and the supply/demand fundamental surrounding the natural gas markets have continued to improve. On the demand side, we have witnessed robust growth in exports and record powerburn year-to-date, partially offsetting storage injection during the summer and providing a more balanced market as we head into the winter. In terms of supply, daily production peaked during the first quarter and we expect it will continue its decline through the fourth quarter of 2016. With the rig count at historic lows, the industry leaned on its stock inventory to mitigate the impacts of decreased drilling activity. And we firmly believe this inventory will largely be depleted as we head into 2017. So, we are seeing a structural change in demand, accompanied by record low activity levels and waning spare capacity, historically consisting of excess stock inventories and curtailed producer volumes, all of which are pointing towards inflection point in early 2017. When we combine the improvement in natural gas strip pricing with our high return assets in the Utica, we believe our financial position and anticipated 2017 cash flow profile warrants higher activity levels than what we have today. At the beginning of 2016, as we were navigating through a lower commodity price environment in the near term, we announced the 2016 capital program of three rigs beginning in January 2016 that contemplated reducing activity levels throughout the year. However, alongside that guidance, we also stated we would remain nimble should there be a change in the commodity to ensure that we had the flexibility to respond promptly when prices merited. In March of this year, we completed an equity offering raising approximately $412 million of net proceeds to allow us the flexibility to remain defensive in a lower-for-longer pricing environment while also positioning Gulfport to react aggressively should a rebound in natural gas markets materialize. And this expectation is now a reality. With an improving fundamental outlook and a recent strengthening of the commodity, this additional liquidity now provides Gulfport with the ability to react quickly by adding back activity within the basin, leveraging the strength of our balance sheet to ensure that we capture the value associated with an upwards swing of the commodity cycle, perhaps more quickly than others. As we contemplate appropriate levels of activity, we realized earlier this year that we must begin accelerating right now to provide a meaningful impact to production during 2017. We have been proactive in taking all the necessary steps operationally and financially required to accelerate our activities quickly and successfully. First, we have remained well ahead of long lead planning items such as permitting and location construction to ensure we had a sufficient level of inventory at all times. Second, we focused on improving efficiencies throughout the field and realized significant reductions in our cost structure. Third, we locked in contracts on the services side to ensure our continued benefits from today’s low-cost environment. And lastly, we built a financial war chest enabling us to strike quickly and aggressively when conditions dictate acceleration. With this in mind, we have already begun adjusting our activity in the near term to take advantage of an improving natural gas market, building momentum as we exit this year and bolstering our 2017 outlook. While our previous guidance contemplated a reduction in drilling activity throughout 2016, we now plan to retain the three gross operated rigs we have running today. And also, recently signed up a fourth drilling rig with the plan for it to spud its first well during September in our dry gas area of the play. In addition, we have opted to add incremental completions during the fourth quarter of 2016, which will allow us to increase the number of wells we have ready for production going into 2017, providing us leverage at a point in time when we see significant potential for strengthening the curve. With this additional activity, we now expect to drill an incremental 17 to 18 net wells and turned-to-sales an additional 10 to 11 net wells on our operated acreage in the Utica during 2016. We have updated our 2016 budget to include this incremental activity and our heightened focus on cost reductions, and efficiency gains continue to yield positive results, providing a partial offset to the additional capital spend. During 2016, we now anticipate spending approximately $325 million to $375 million on operated D&C CapEx. Although this additional activity will have little impact on full-year 2016 expectations, we believe the timing of the buildup and momentum during the second half of the year will provide a meaningful impact on 2017 and beyond. On the drilling side, ahead of any potential service cost inflation, the Gulfport team proactively renegotiated the contract terms on our current three-rig fleet to ensure that we are locking in the long-term benefit from today’s low-cost environment. Our rig fleet is comprised of all high-spec, built-for-purpose equipment, complete with experienced crews, enabling us to consistently drive efficiencies and push the technical limits of our operations. While locking in these contracts now, we have secured a base level of activity for the next year, not only hedging against service cost inflation but also ensuring consistent service quality to aid in further efficiency gains. On the completion front, when we entered Utica, we invested in certain key areas of our operations to ensure ready access to quality equipment and crews, mitigating the potential for price gouging and supply shortfalls. Pressure pumping horsepower and profit availability are both segments of the supply chain seen to be potential bottlenecks associated with ramping activity, not to mention large line items on our AFE. By vertically integrating these businesses, we have not only secured insulation from service cost inflation across the significant portion of completion operations, we have also ensured a clear path to ramping our completion activities during 2017 brining back activities quickly as market conditions warrant. As we look towards next year, while we have not yet finalized the specifics surrounding our anticipated full-year 2017 program, we are prepared to provide some color on potential levels of activity based on our view of the world today. When you combine constructive natural gas fundamentals with our high quality asset base and strong financial position, we would expect to further increase our development pace during 2017 above and beyond the four-rig program we have running today. In fact, at a $3 plus strip, we believe we can easily ramp to a six-rig program. Based on our current estimates, we anticipate this level of activity would result in a year-over-year growth in 2017 of approximately 20% to 25% while spending $675 million to $725 million on D&C CapEx. As we move to the remainder of 2016, we will continue to monitor the pricing environment and refine our views as we consider the appropriate level of activity for 2017 and beyond. We currently believe the lack of supply going into next year could certainly generate a scenario above where the strip sits today and should natural gas prices continue to move higher and we are able to hedge out the curve, we would look to expand our rig count beyond the six-rig scenario I just mentioned. Assuming an eight-rig program, we estimate this level of activity would result in year-over-year growth in 2017 of approximately 25% to 30% while spending $850 million to $900 million in D&C CapEx during 2017. Keep in mind that these scenarios assume that the additional rigs begin running on January 1, so this ramp in activities don’t have a full-year impact to production during 2017 which is reflected in the growth expectations I just mentioned. If we were to roll forward another six to nine months to account for cycle times and reflect a full year of drilling and completion activities from these incremental rigs, we believe the six-rig scenario would generate nearly 35% year-over-year growth in 2018 over 2017 and an eight-rig program would generate close to 50% growth in 2018 over 2017. It is important to note, Gulfport’s core philosophy of capital discipline and conservative credit metrics remains intact, and we currently expect to fund our 2017 activity through operational cash flow and available sources of liquidity while also maintaining reasonable leverage metrics. As of June 30, Gulfport had approximately $400 million of cash on the balance sheet and an undrawn revolver resulting in nearly $900 million of total liquidity. Moving on to the specifics surrounding our second quarter results, total net production for the second quarter averaged approximately 664 million cubic feet of gas equivalent per day. As expected, not running a completion crew during the first quarter pushed our few second quarter tie-in-lines to be weighted to the last week of June, effectively resulting in no incremental operator production being turned to sales during the quarter. In addition, we are experiencing higher than anticipated gathering line pressures in our highly prolific dry gas development area of the play, which is having a near-term impact on production levels. During the early stages of our development, Gulfport and our third-party midstream providers worked diligently to develop a long-term multi-phased compression plan, which we have now begun implementing. Today and over the next several months, we plan to install and phase-in pad level compression on a select group of wells. In addition, we currently expect to have field-level compression online by year-end 2016 and once operational, we anticipate that debottlenecking these surface restrictions will result in an uplift to current production and increase our production levels as we enter 2017. For the third quarter of 2016, we currently forecast production to average approximately 685 to 705 million cubic feet per day. As I just mentioned, we are seeing a near-term impact to production from higher line pressures and 3% to 6% growth during the third quarter is lower than what we originally expected prior to these restrictions. That said, we reiterate our full-year 2016 production guidance and we now estimate we will be well in excess of our previously-provided exit rate growth of 15% fourth quarter 2016 over fourth quarter 2015. Our midstream group has been hard at work at optimizing our current firm commitments to ensure that we receive the highest value for our products, and I am pleased to say that their efforts were well represented in our second quarter realizations. Before the effect of hedges and including transportation cost, Gulfport realized natural gas price settled approximately $0.51 per Mcf below the average NYMEX natural gas last day settlement prices for the quarter. Year-to-date, our realized natural gas price has settled approximately $0.61 per Mcf below the average NYMEX. And we reiterate our full year basis differential guidance of $0.61 to $0.66 per Mcf off of NYMEX monthly settled prices. In addition, before the effect of hedges, our second quarter oil and NGL realized prices came in better than expected. And we have updated our expectations for 2016 and currently expect to realize approximately $5.50 to $6.50 off WTI for oil and $0.25 to $0.29 per gallon for NGLs during 2016. Lastly, our hedge portfolio continues to provide a meaningful impact for our revenue. And we realized a gain of approximately $61.3 million during the quarter. Turning to cost, we continue to focus on improving margins and lowering our operating cost to create long-term savings and increased returns. During the second quarter, our per unit operating cost which includes LOE, production tax, midstream gathering and processing and G&A totaled $1.14 per Mcfe which is down 22% over the second quarter of 2015. Second quarter LOE totaled approximately $0.24 per Mcfe, down 38% over the second quarter of 2015. Second quarter midstream processing and marketing expense totaled approximately $0.65 per Mcfe which is down 15% over the second quarter of 2015. Second quarter G&A expense totaled approximately $0.20 per Mcfe, down 11% over the second quarter of 2015. Due to the decline in volume during the second quarter, as anticipated, this caused some irregularity when comparing second quarter 2016 to first quarter 2016. However, we have reiterated our 2016 guidance expectations and believe all of our per unit operating expenses will continue to decrease further throughout the year as we realized economies of scale as our volumes grow. In closing, while the natural gas rig count begin to take a drastic decline during early 2015, we witnessed a material delay in this reduced activity correlating to lower supply. The lag between spud to first sales and producers dipping heavily into their DUC inventories lengthened the time it took to see a reduction in supply. We strongly believe the same lags that have hindered the decline in production for reduced activity will also play a meaningful role in delaying an increase in the supply as we think about future additional activity being added in natural gas basins. The financial philosophy Gulfport has adhered to for the past decade has not only allowed us to weather these cycles, but navigate them in a position of strength. Our strategic commitment to the balance sheet and conservative leverage metrics have provided us with the ability to pursue an aggressive growth plan and be a leader in capturing market share in the improving natural gas market. This concludes our prepared remarks. Thank you again for joining us for our call today and we look forward to answering your questions. Please open up the phone lines for questions from the participants.

Thank you. At this time, we will be conducting a question-and-answer session. [Operator Instructions] Our first question comes from the line of Neal Dingmann with SunTrust. Please state your question.

[Indiscernible]. Just building on that last part, you were talking about the delays. My first question is this. Could you just walk through a bit about how you see 2017 CapEx and not only how that will impact your 2017 growth but how that might impact 2018?

Okay. Thanks, Neal. Yeah. You’ve got to keep in mind that we’re building into a six-rig program, so we’ve had three rigs running. We’re adding a fourth rig on September 1. Keep in mind that we’re talking about nine months spud-to-first sales, so there’s quite a lag time from when you actually see production. So, during 2017, we’re actually building momentum to a six-rig program. We’re talking about a base program of six rigs which would mean we would add another two rigs on January 1. But, again, nine months spud-to-first sales. So, we have to spend some extra CapEx in 2017 to build momentum going into 2018. So, our growth – we’re delivering quite a bit of growth in 2017, but really you see that momentum coming through and reflected in the growth profile for 2018. We’re talking about 35% to 50% growth in 2018, and that’s really a result of some of that extra CapEx that we’re spending in 2017. It just takes a while to build momentum to a full six-rig program. Does that answer your question, Neal?

Yeah. That makes sense. And then, just lastly, and maybe a little bit shorter term, can you talk about 2016 production exit rate given the number of second half wells turned-to-sales, I’m just looking at that slide 13 in particular and again if you could talk about around your exit rate.

Yeah, again, as I mentioned on the scripted comments, it does look like we’re going to be well in excess of the 50% fourth quarter over fourth quarter exit rate 2016 over 2015. So, that comes at a perfect time as we are building momentum going into 2017 into what we think could be a very strong pricing scenario. So, we’re excited about the levels of activity that we’ve had in 2016 building momentum for us at just the right time in 2017.

Got it. Thanks so much.

Thank you.

Our next question comes from the line of Ron Mills with Johnson Rice & Company. Please state your question.

Morning. Mike, just on the leverage between the six rigs and eight rigs, what are some of the potential drivers in ya’lls mind that would cause you to go from your base six-rig program to eight rigs?

Well, keep in mind ultimately, Ron, it’s about commodity prices honestly, first and foremost. Now, for us, because of our philosophy or the way we run our company, we have to balance CapEx versus cash flow versus liquidity and then, of course, ultimately leveraged metrics. So, it comes down to commodity prices. Now, we do have the ability to add debt since we are less than two times levered and we’ve talked about being comfortable in the two to three times range. So, we have quite a few sources of liquidity to ramp to an eight-rig program. But again, it’s just finding that balance as we see some commodity price stability. As we go into the back half this year, we want to wait a little while obviously until we get into the fall before we make some final decisions on next year.

And, Ron, it’s Aaron. Let me add one thing. Just kind of keep in mind that we did raise the approximately $400 million of equity proceeds back in March. So, we feel like our balance sheet’s in great shape, and we prefunded between that and operating cash flows. We prefunded that CapEx spend that we will have next year, whatever we eventually hone in on.

Aaron, that’s a good segue to my – because it seems like on the expected activity levels that you should – even just using strip, you should be able to fund your activity out of cash flows and current cash on hand without really relying on any incremental revolver debt or anything. Is that a fair representation?

Yeah, I think that’s fair. I mean, it all depends on the commodity price deck. But I think Mike mentioned the two to three times leverage. So – and maybe add one more thing. When we were looking at our 2017 kind of booking so to speak, we weren’t just looking at 2017, but we’re looking at 2018 together. And so, we felt like because where the balance sheet is today that the current balance sheet, the cash on hand, the revolver access that we have, we can comfortably fund a six- to eight-rig program just depending on wherever the strip settles at the end of this year.

Great. And then, just to get to that rig count, it sounds like you’ve renegotiated your existing contracts on the three rigs. But in terms of discussions with service providers for access to the kind of equipment you want and the kind of crews you want, is there going to be any limitations on that ramp and are you able to also lock in some of the current rates for a 12- to 18-month period for the increased activity?

Yeah, that’s a good question. And so, we have been talking to our service providers for some time and our guys have done a great job in negotiating and locking in those contracts. And so, what we’ve been able to do is get terms of generally 12 to 14 months at some attractive rates. So, I’m not going to share those with you, but we’re very, very happy with the rates we’ve been able to lock in from the service providers and the length of time we’re able to lock those in. So, we’ve got four base rigs locked in. We’re working on additional rigs. There are rigs available. There are crews available. I think Gulfport’s in a unique position because it has been active throughout this process. It’s got a good balance sheet and pays its bills. So, I think that makes our conversations with service providers maybe perhaps a little easier than others. We also have line of sight to a lot of drilling inventory, so they know that we can keep them busy for a long time. So, those conversations are going well. We are also running a RFP process on some of our smaller ancillary services and of course, we’re looking for terms of 12 months if we can get them. But so far, the conversations have gone well.

Great. Thank you.

Thank you.

Our next question comes from the line of Pearce Hammond with Simmons Piper Jaffray. Please state your question.

Good morning, and thanks for taking my questions, and that was helpful prepared remarks, Mike, as it related to next year, and then to 2018. My first question’s on the line pressure issues. And pardon my ignorance, but I just want to better understand what’s really the cause here? I would think that with reduced activity in the Utica relative to the gas price environment that we’re in, it seems a bit surprising that we have this issue, and then, as we move forward, the line of sight for improvement on this, specially if activity is starting to increase, if you can outline some of your reasons for the confidence and how this gets resolved? So, just want to understand the cause, and then, the resolution a little better.

Thanks, Pearce. So, you’ve got to remember the development of the dry gas area is a fairly new development and we are really the first do develop it in a big way. The situation you have, Pearce, is you have lots of new production coming on, at a very tight geographical area and these are very high pressure wells. This is a very prolific region and so, you’ve got pipeline to have maximum operating pressures that they operate under and we’re seeing pressures of 1,100 to 1,300 psi which is pretty incredible pressure. So, in oil and gas, Pearce, as you know, compression is something that you bring on when it’s needed, but not before typically. And so, we are at a point that it’s needed. And so, we’ve had plans for compression all along. Right now, we’re working on field lift or pad level compression. That should come on shortly. We’re also working on full field compression, which we’ll begin phasing in by year-end. So, it shouldn’t be an issue for 2017. Just keep in mind this is ultimately an above the surface mechanical challenge. Again, it’s something that you deal with in every play. We have the plan. We’re phasing it in. And so, we are working through this very quickly which just shows, I think, our operational maturity. And I think the fact that we’re still going to be within our guidance range for the year just indicates that we’re working through it very quickly and we’re on top of it. Ty, would you add anything to that?

No. I think you’ve covered it. No.

Okay.

Yeah.

Does that answer your question, Pearce?

Yes, it does. Thank you. It’s very helpful. And then, my second question is just more of a follow-up to the prior questioner. So, it sounds like that based on the six-rig program for next year and assuming roughly $3 that your leverage metrics would not change, in fact could improve as you step out into 2018. Is that a fair assessment?

Yeah. I think – and, Pearce, it’s Aaron. I think what I’d say is where we stand today, we’re at 1.4 times leverage on an LTM basis. And we’ve talked about two to three times. So, we are comfortable with having that leverage tick up. But basically, the plan that we’ve outlined puts us on the lower end of those workings over the long term, so we’re very comfortable with the six- to eight-rig program just depending on where the commodity price is.

Excellent. Thanks so much.

Thanks, Pearce.

Our next question comes from the line of Jason Wangler with Wunderlich Securities. Please state your question.

Good morning. Just maybe doing some linear math at the July production, and understanding the compression issues start to alleviate pretty quickly. Can you just talk about the ramp in this quarter getting production probably in excess of 700 million, as you look at it in terms of I guess just the activity level that you guys have planned bringing on wells? I know it’s not something you’d typically talk about, but just trying to get a handle on how that ramp looks with the kind of the headwind of the compression issue.

Yeah, that’s a good question. So, on slide 13, if you refer to slide 13, this quarter we put the turn-in-line schedule in for the third and fourth quarter. So, I think that will help you, but remember we’ve brought on 5 wells right at the end of June. We’ve got 20 wells coming on in the third quarter and there are 10 coming on in the fourth quarter. So, we certainly feel very comfortable about third quarter and fourth quarter. And as I mentioned, both in the scripted comments and in my earlier Q&A, we actually looked to exceed by quite a bit, the 50% exit rate that we previously had anticipated for fourth quarter over fourth quarter.

And Jason, it’s Aaron. Let me add, what you’ve got to keep in mind and you can see it on slide 13 of our deck. We basically have two-thirds of our turn-in-lines for the year coming on in the second half of this year and really the step coming on in the third quarter is not really showing up in the July number. So, we do feel comfortable about hitting that guidance range that we talked about both the third quarter numbers, as well as the full year.

Yeah, and that’s what I was going to be maybe just follow onto is I would assume that the majority of that 20 is still coming on August, September then. So, it’s really even more than six months loaded, that’s kind of the back end of the five months of the year. Is that fair to say?

That’s fair.

Great. Thank you, guys. I’ll turn it back.

Thank you.

Our next question comes from David Deckelbaum with KeyBanc Capital Markets. Please state your question.

Morning, Mike and Aaron and thanks for taking my questions.

Hey, David.

I’m curious just on the outlook, you provided some bookends, I think, for 2018 and what that build up does from 2017 going into 2018. Would your expectation be that with a six-rig program that CapEx in 2018 would look similar to 2017 if we held the service cost flat or is there some extra cost that are embedded in 2017 that would conceptually go away as you build them to the out years?

Hi, David. It’s Aaron. I think, 2018, the CapEx numbers that we laid out for 2017, at this point in time, I think it’s fair to just assume that those would carry over at the same rig cadence.

Okay. That’s fair. And then, you talked about – a lot of questions have been asked about putting on compression and you said, you’re very confident in your 3Q and 4Q numbers. Is there any quantification, I guess, we – experience I guess when the lateral was put on line in 4Q. We saw the uplift in production and that that was quantifiable. And can you quantify how much production uplift we should expect at the end of the year just from compression installation?

Well, David, I would say, it’s hard to quantify exactly. It’s not really an exact science. Again, we think we’ll still certainly land within our guidance. I can tell you that we’ve already done some things mechanically in the field to change the pressures by 100 psi and we’re already seeing a material uplift based on just that 100 psi change. So, we feel very, very comfortable in our ability to get an appropriate uplift once we get the pad level compression and the field level compression phased-in. So, this is, again, pretty common and not something that we all haven’t dealt with before.

Okay. And was any of that compression benefit reflective in the July numbers?

No.

Okay. All right, guys. That’s it for me.

Thank you.

Our next question comes from Marshall Carver with Heikkinen Energy Advisors. Please state your question. Marshall, please state your question at this time.

Okay. Sorry for that. I was muted. Your well costs have been heading down over the last couple of years, and you’re talking about trying to lock in good terms from here with service companies. Should we think about well costs basically leveling out from here for the next year or two or seeing some inflationary pressure? How should we think about the well costs as we move into 2017?

Yeah. That’s something we should all be focused on, for sure. I think our view is, Marshall, that service costs were at a bottom. I think the question is will there be enough ramp of activity to encourage the service providers to use the opportunity to increase their prices. I’m not sure if that’s – if I believe that’s the case yet. But they’re certainly going to increase their prices when they have an opportunity. That’s why we continue to work on efficiencies throughout this process. Net-net for Gulfport, we wouldn’t anticipate really any significant increases from our service providers and that’s offset by some of our efficiencies, but Aaron has a couple of comments to add as well.

Yeah, so, Marshall, as we worked on the kind of the numbers that we talked about for 2017 and 2018, maybe a couple of things to add on to what Mike said. One is that we’ve been doing a lot of contracting with service providers to try to avoid the chance of having that service cost inflation kick in. And I think, the second thing I’d say is that we’ve also been internally constantly evaluating that interplay between increased density and larger volume fracs, both through our own experimentation and our participation at outside operated wells. And so, when we were putting together those CapEx numbers for next year, it’s probably worth mentioning that a portion of our program, we did contemplate involving some larger fracs. And that was based into those CapEx numbers that Mike talked about earlier.

Okay. Thank you.

Your next question comes from John Nelson with Goldman Sachs. Please state your question.

Good morning and thank you for the thoughtful medium-term outlook. Apologies if this was already covered. It’s been a busy morning, but what natural gas price do you need in the 2018 strip to go ahead and accelerate to eight rigs?

We didn’t actually talk about a specific natural gas price, John, but kind of the way we view it is every incremental quarter uplift to natural gas prices gives us some meaningful cash flow. So, I think, for us the interplay between the commodity price, cash flow versus CapEx, liquidity leverage, those are the things that we’re looking at.

Okay.

And, John, let me also add that obviously commodity price is going to be one of the biggest factors, but it’s not the only variable that we’ve got to keep in mind as we think about where we shake out on that rig count. And as we’ve talked about a few times already, that leverage metric we’ll be keeping them within two to three times long term is another piece of the puzzle.

So, and John, just to add one more comment, maybe try to be more specific for you. We feel like, with our cash cost and our efficiencies, our niche is in the $3 or $3.50 range, and we are certainly growers at that level. Now, we’re seeing forecast higher than that, but I think we’re fairly conservative in the way we think about our ability to grow in the $3 to $3.50 range.

Okay. If I can maybe just dive into that. So, on our numbers at least, it looked like at the six rig case at about $3, you’d be cash flow neutral. Is it fair to then say that – or if I’m hearing you correctly, is the goal to really not necessarily target cash flow neutrality in 2018 depending on what commodity price you’d lock in, instead more just balance of kind of where those credit metrics end up being at between two to three times? Is that how we should think about kind of triangulating the rig count?

Yeah. I think kind of the variables that we use to think about the rig count, and part of it goes back to that $412 million in net proceeds that we raised back in March. So, the balance sheet’s in great shape, and we had that 1.4 times leverage where we sit today. Part of it is the quality of the asset base. If you’re talking $3 to $3.50-type numbers as Mike mentioned, that’s definitely within our wheelhouse as they’re having very strong returns. And so then we can prefund that outspend with the balance sheet we have today. I think as we think where do we sit at the end of 2017, where do we sit at the end of 2018, that’s where we’re trying to make sure that we’re comfortably within the two to three times leverage metric range.

Okay. That’s helpful.

Yeah. John, I think the important to note here just to make sure that we’re clear, I think we’re pretty unique in the fact that we can grow. We talk about 35% to 50% growth in 2018 and we have the ability to do all that with no external funding sources. We could take on some additional debt because we have room to do that, but I think that puts us in a very unique position.

Hey, John. Aaron. Again, one more thing I’d just add. You had a question about kind of outspend. I think one thing you’ve got to keep in mind is with an improving asset base and improving commodity price deck, we can still outspend but keep leverage metrics flat or actually decreasing. And so, it’s not necessarily trying to hit just cash flow neutrality at a certain point in time.

That’s incredibly helpful. My second question is obviously I can understand the value proposition from kind of pulling forward NPV. But Mike, just curious on your thoughts on what the inventory depth would look like at eight rigs and how you would think about potentially replenishing that or some of the eight rigs would be in kind of non-dry gas areas such that we wouldn’t be compressing that as meaningfully?

Well, the way we view our inventory is that we still have a very adequate inventory 10 years plus of opportunities out there. Certainly, there’s always an opportunity to add inventory if we need to add inventory. But remember, when we talk about our net locations, we always [ph] risk (43:30) those just to be conservative. So, organic leasing opportunities are plentiful out there. And you’ve got to remember this entire play is really rolling in the next two to three years with explorations. It’ll be interesting to see what happens there, are people able to hold them organically? Do they have the money to pay the renewals. It’s kind of a new dynamic that we’ll have to watch unfold for the next couple years.

Okay. And then, just one housekeeping one for me, if I could. It looked like wet gas locations were added to the 2016 completion calendar. You did have a big drop off in NGLs in 2Q. Should we be expecting a decent bounce back? Or said another way, was any of the 2Q decline due to shut-ins for offset completion in the NGL line and we should expect a bounce back or is that not necessarily the case?

Hey, John. This is Ty. So, as far as the NGL drop off, a lot of that was the ethane recovery. We’re able to recover less this last quarter and so, that’s just a part of the barrel that’s just coming down.

Okay. That’s all for me. Thanks.

Your next question comes from Stark Remeny with RBC. Please state your question.

Hey, guys. Good morning. I’m filling in for Kyle today. I just have a couple of questions, if you don’t mind. Could you kind of provide some clarity on how we should think about any changes to your lease extension payments in 2017, assuming you guys ramped to either the six- or eight-rig program?

Well, previously, we had talked publicly about having a similar budget in 2017 as we did in 2016. I think $50 million to $60 million is what we talked about. Obviously, with an increase in activity, that would mean that our leasehold budget, our renewals would go down. It’s hard to quantify exactly at this point, and I don’t want to get too much into the weeds on 2017. But I guess my point is you could expect reductions in renewals for both 2017 and 2018.

Okay, thanks. And then, I guess, just kind of curious on if you look on slide 13, it looks like you guys have a few planned stepped-out wells to the North. I guess, can you kind of guide on what the timing of those wells are and what the status of any infrastructure gathering there is out there?

As far as the timing, I think most of it you’ll see it next year, mid-next year. And as far as infrastructure goes, that’s one of those areas that we continue to get in front of. And we’re out there doing the – taking the necessary steps to get out there by that timeframe.

Okay. Thanks.

Thank you.

Our next question comes from Holly Stewart with Scotia Howard Weil. Please state your question.

Good morning, gentlemen, Jessica. Just one quick one. Aaron, I think you opened the door a little bit on the comment for larger flat fracs being contemplated in the CapEx budget for 2017? And we’ve heard, I guess, a number of companies over the course of earnings season talk about the increase in sand loading and tighter spacing and longer lateral. So, could you just maybe give us a flavor for what you’re contemplating for next year?

Morning, Holly. So, we’re still finalizing things but we’ve definitely done some early work on what the plan is for next year. And so, for a portion of the wells, we do think a larger frac design make sense.

Holly, this is something that we’ve been looking at for some time as have, I think, our peers. And we have been evaluating the interplay between increased density drilling at 750 foot spacing versus the benefit of larger volume fracs. We’ve done some experimentations ourselves. We certainly watch what outside operated activity has been. So, a portion of our activities next year will incorporate larger volume fracs, I’m not saying every single location, but just to put it in perspective perhaps up to 2,800 to 3,000 pounds per foot. And we’re talking 9,500 to 10,000 foot laterals here. So, that gives you some idea of what we’re going to do next year. But, again, it won’t be necessarily on every single one. We’ll be selective on which of our locations we’ll do those on.

And, Holly, as part of the rationale there is that if you think about kind of the industry being in an overall slowdown over the last couple of years with commodity prices. As we think about the next several years of budgeting, I think acreage holding for us, and I’m sure others as well, is kind of a little more important going forward than it has been historically. That’s part of the rationale behind going to these larger fracs in some cases.

Sure. Sure. And can you remind us, if you’re at 2,000 pounds right now?

About 1,800, Holly.

1,800? Okay. All right. Great. Thank you.

Our next question is from David Beard with Coker & Palmer Institutional. Please state your question.

Hi. Good morning, everybody.

Hi, David.

You’ve done a great job outlining the upside, and I’d just like to get a little color here on the downside, and I know partially it has to do with spot prices and partially with how much you’re hedged. If gas prices pull back on the spot basis, what would cause you to either stop or even drop a rig? Or on the other hand, what would you like to be hedged in order to grow through a period of $2 or $2.25 gas? Thanks.

Well, first of all, when you look at our hedge book for 2017, according to consensus, it’s close to 50% of our expected production, maybe under a six-rig program, a little less than that, and that’s the $3.08. With that base wedge of hedges in place, David, I think it’s unlikely that we would look at anything less than a six-rig scenario. We obviously think that, later this year, there’s going to be an opportunity to layer in some additional hedges. Obviously, as a company, historically, we’ve shown that we take as much risk off the table by having good solid hedge books anywhere from 40% to 70% hedged. In fact, this year we’re 82% to 85% hedged just because of our bearish view on the commodity. But that being said, fundamentally, we don’t see anything that’s going to cause gas prices to go down between now and the end of the year. And so, I think our view is let’s wait and layer in some more hedges when there are beginning to be some spikes in gas as we approach winter and get those first goals mapped. So, again, I think unlikely we’d be less than six rigs with the hedge book we have started already and the ability to layer additional hedges on top of that.

Yeah. Good. That’s helpful. You do have quite a bit of runway before having to make a downside decision. Appreciate the color.

Thank you.

Ladies and gentlemen, that does conclude our Q&A session for this call. At this time, I will now turn the conference back over to Mr. Moore for any closing remarks.

Thank you, Audrey. 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.

This concludes today’s conference. Thank you for your participation. You may now disconnect your lines at this time.