Gulfport Energy Corporation (GPOR) Q3 2019 Earnings Report, Transcript and Summary

Greetings and welcome to the Gulfport Energy Corp. Third Quarter 2019 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] It is now my pleasure to introduce your host, Jessica Antle. Thank you. You may begin.

Thank you and good morning. Welcome to Gulfport Energy Corporation’s third quarter 2019 earnings conference call. I’m Jessica Antle, Director of Investor Relations. Speakers on today’s call include David Wood, Chief Executive Officer and President; and Quentin Hicks, Chief Financial Officer, Executive Vice President and Chief Financial Officer. In addition, with me today available for the question-and-answer portion of the call is Donnie Moore, Chief Operating Officer. 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 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 non-GAAP measures. Reconciliations to the comparable GAAP measures will be posted on our website. Yesterday afternoon, Gulfport reported third quarter 2019 net loss of $48.8 million or $0.31 per diluted share. These results contain several noncash and non-reoccurring as presented in our press release filed yesterday evening which provide a detailed reconciliations of the adjusted items. Comparable to analyst estimates, our adjusted net income for the third quarter of 2019, which excludes all of the previous mentioned adjusted items, was $39 million or $0.24 per diluted share. 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 David Wood, CEO of Gulfport Energy.

Thank you, Jessica. And thank you all for joining us on this morning’s call. Gulfport’s third quarter is underscored by our continued strong performance from each of our operating areas and achieving the next phase of our 2019 plan provided at the start of the year, free cash flow generation. We exceeded our production targets while adhering to our capital budget, improved our balance sheet through the previously announced repurchase of senior notes and generated significant cash flow from our 2019 activities. For the third quarter, we reported $39 million of adjusted net income and generated $219.4 million of adjusted EBITDA. In addition, operating cash flow before the changes in working capital and inclusive of capitalized expenses, totaled $173.6 million, and we generated free cash flow of approximately $103.4 million during the third quarter of 2019. Total net production averaged 1.57 billion cubic feet of gas equivalent per day, increasing 12% quarter-over-quarter and driven by the strong momentum carryover from the second quarter, turn-in-lines in the Utica Shale and continued performance of our base production in the SCOOP. We remain on track to deliver on our 2019 production guidance. And based on the remainder of the year’s activities, we currently forecast full-year 2019 net production to average at the midpoint of the previously provided guidance range. During the nine months ended September 30th, Gulfport incurred $423.7 million and operated D&C capital and $72.6 million in non-operated D&C capital. In addition, land expenditures incurred totaled approximately $33.1 million during the first nine months of the year. Our operated capital spend remains on target with expectations. And with respect to non-operated activity, we continue to work towards recovering a portion of the capital incurred to-date, through the sale of certain non-operated interests. We have a high degree of confidence we will be successful in accomplishing this and we remain fully committed to spending within the range of our 2019 total capital budget net of no-operated divestitures and reaffirm our 2019 capital guidance. On the strategic front, we continue to simplify the portfolio through non-core asset sales, and recently entered into an agreement to sell certain overriding royalty interests associated with assets the Company held in the Bakken. This transaction net to Gulfport’s interest fills approximately $8 million in cash and is expected to close during the fourth quarter of 2019. In addition, the previously announced process to divest of certain water infrastructure assets Gulfport holds across our SCOOP position is in the final stages, and we expect to provide further details in the coming weeks. I am very pleased with the transactions we have executed to-date, divesting of non-core assets not contemplated within our current development plan, and allowing us to strategically reinvest this capital elsewhere in our business. As previously announced during July, we repurchased approximately $105 million principal amount of senior notes for total cash spend of $80 million. At the levels at which our bonds have been trading, we continue to see an attractive opportunity to retire senior debt at a meaningful discount and expect to continue reducing a portion of our outstanding debt. In addition, we continue to see merit in our previously announced equity repurchase program, which remains active and is authorized to be executed through January 2021. As we continue to evaluate potential uses of cash flow, we will remain disciplined in our allocation of capital, both committed to maintaining a strong balance sheet and enhancing shareholder value. Turning to our specific core areas. In the Utica, during the first nine months of 2019, we spud 13 gross wells, utilizing roughly 1.2 operated rigs. The wells had an average drilled lateral length of 12,200 feet, an increase of 18% over 2018, and when normalizing to an 8,000-foot lateral, we averaged a spud to rig release of 18.6 days, down 5% over full year 2018 results. As we noted earlier in the year, during 2019, we focused on maximizing lateral lengths to allow us to deliver more with less. And I’m pleased to report that drilling team in the Utica Shale had a record quarter at the drill bit. We exceeded many of our previous drilling records, and during the third quarter, we drilled our longest well to-date in the play with the lateral length of over 16,000 feet and measured depth totaling nearly 27,000 feet. We currently have one rig running in the Utica Shale and plan to deliver an additional three gross wells during the fourth quarter of 2019. Turning to completions in the Utica Shale, we concluded our 2019 frac program during the third quarter and completed 47 wells in total during 2019, averaging 6.9 stages per day and completing a stage count of 2,068 stages this year. The wells completed during 2019 had an average stimulated lateral length of 9,800 feet and all 47 of the wells were turned to sales during the first nine months of the year. This level of activity led to very strong production from the assets averaging 1.2 billion cubic feet equivalent per day during the third quarter, an increase of 18% over the second quarter of 2019 and 9% year-over-year. The Utica continues to be a very consistent, reliable asset in our portfolio, and we are extremely pleased with the performance of the resource year-to-date, and the team managing it. Switching over to the SCOOP. During the first nine months of 2019, we spud eight gross wells including seven Woodford wet gas wells and one lower Sycamore well, utilizing roughly 1.6 operated rigs. The wells released had an average lateral length of 8,400 feet. And when normalized to a 7,500-foot lateral, the wells averaged a spud to rig release of 59 days during the first nine months of the year, a decrease of 7% when compared to our 2018 program average. When isolating the well set to just the Woodford formation, the average spud-to-rig release totaled 54.5 days during the first nine months of 2019, a 14% improvement to our full-year 2018 program average. An integral part of capturing cost reductions and efficiency gains is being repeatable. And our drilling team in the SCOOP continues to be committed to delivering consistent, repeatable results out of this play. We currently have one rig running in the SCOOP, drilling ahead on the wells spud late third quarter and we plan to deliver one additional gross well during the fourth quarter of 2019. On the completion front, during the first nine months of 2019, we turned to sales nine gross swells with an average stimulated lateral length of 7,100 feet. We had no completion activity in the SCOOP during the third quarter but plan to complete and turn to sales five gross wells during the fourth quarter of 2019. Production during the third quarter averaged 281.5 million cubic feet equivalent per day, down 5% from the second quarter of 2019, which does not include any new wells turn to sales and highlights the shallow decline nature of this asset. In summary, both our quality core assets have us on track to deliver on all our operational guidance metrics, while forecasting capital spend net of certain non-operated divestitures within the original budget provided in January. I am delighted now to introduce Gulfport’s Chief Financial Officer Quentin Hicks, who joined the Gulfport executive team in late August. Quentin has an extensive background in corporate finance, capital markets, and oil and gas accounting, and we believe his leadership is a strong addition to our team. With that, I will turn the call over to Quentin for the financial highlights and for his comments.

Thank you, Dave, and good morning, everyone. First off, I’d like to thank Dave and the Board of Directors for giving me the opportunity to be a part of the leadership team here at Gulfport. I look forward to working alongside the entire Gulfport team to achieve our goal of maximizing value for our stakeholders. During the third quarter, production averaged 1.53 billion cubic feet of gas equivalent per day, composed of 93% natural gas, 5% natural gas liquids and 2% oil. Net production for the quarter increased 12% over the second quarter of 2019 and came in ahead of our previously provided expectations, driven by solid execution in the field, and quality well performance across our asset base. Looking through the fourth quarter, we plan to turn to sales five gross wells in the SCOOP during the month of December. And taking this into account, we reaffirm our previously provided full-year guidance range of 1.36 billion to 1.4 billion cubic feet per day of production, and we expect to come in right at the midpoint of that range. On the realizations front, during the first nine months of 2019, our realized natural gas price before the effect of hedges and including transportation costs settled at approximately $0.59 per Mcf below NYMEX prices. We reiterate our expectations for basis differentials to range between $0.49 and $0.66 per Mcf for the full year 2019. During the first nine months of the year before the effect of hedges, our realized oil price came in at $2.93 below WTI. As a reminder, following the sale of our South Louisiana assets, we now expect our oil differential to average a $4 to $5 discounted WTI for the remainder of the year. However, on an annual basis, we reiterate our expectation of a $3 to $3.50 discount to WTI. Turning to NGLs, before the effect of hedges, our realized NGL price came in at approximately 35% of WTI. And based on these results and recent NGL strip pricing, we have updated our pre-hedge NGL guidance to be 35% of WTI for the full year 2019. Our realized prices continue to be supported by our strong hedge book. And during the third quarter of 2019, we realized the hedge settlement gain of $0.59 per Mcfe or $82 million. For the remainder of 2019, our natural gas production continues to be well covered by our hedge book with the fourth quarter of 2019 fully hedged at $2.81 per MMBtu. In addition, we have a large hedge position, covering our NGL exposure and expected oil production for the remainder of the year. We recently took advantage of the opportunity to layer in additional gas hedges for 2020. We now have gas swaps in place for 2020 totaling 548 million cubic feet per day at an average swap price of $2.88 per MMBtu. These additions to our 2020 hedge book provide an increased degree of certainty surrounding our cash flow profile as we plan for next year, supporting the anticipated development of our assets and positioning us well to continue to fund our program, largely with cash flow. We plan to continue to opportunistically layer in additional hedges in 2020 to provide line of sight to our realizations and cash flows with the focus on hedging at levels that provide us with an opportunity to generate free cash flow in 2020. For the first nine months of 2019, our realized prices and hedge position resulted in adjusted oil and gas revenues of $967.3 million, which is composed of approximately 81% natural gas and 19% real liquids revenues. In terms of cash operating expenses. Our per unit operating expense, which includes LOE, production tax, midstream gathering and processing and G&A, totaled $0.92 per Mcfe during the nine months ended September 30th. These expenses were in line with our full-year guidance and are down 9% when compared to full-year 2018 levels. This reduction in OpEx was driven by higher production and related economies of scale from our dry gas development Utica Shale as well as continued focus on improving our cost structure. As we look forward to 2020 and a challenging commodity price outlook, we are actively looking for ways to lower costs and improve efficiencies in every aspect of our business, which includes taking a hard look at G&A and staffing levels. During the third quarter, we made the transition to becoming free cash flow positive with free cash flow from operations, inclusive of capitalized expenses and before changes in working capital of $103.4 million. We expect another quarter of meaningfully positive free cash flow in the fourth quarter. Moving on to the balance sheet. Gulfport has kicked off its fall borrowing base redetermination. We’re in a position of strength as it relates to our borrowing base process as we currently forecast very little revolver draw year-end 2019 and our previous $1 billion elected commitment level sits well below the total availability on our facility of $1.4 billion. We expect to keep our commitment level at $1 billion this fall redetermination. As we look forward 2020, we are focused on keeping our balance sheet in good shape. Accordingly, we are creating our 2020 budget with the focus on not materially drawing our revolver to fund drilling, and ensuring leverage remains at manageable levels. As we think about capital allocation going forward, I agree with Dave’s statement that the market has presented us with the unique opportunity to reduce our debt at attractive prices. Over the past several months, we have seen a shift in investor sentiment with liquidity and leverage becoming a primary focus for companies such as ours. Our strong current and projected liquidity provides us with the unique opportunity to retire notes at a meaningful discount while maintaining adequate liquidity going forward. Retiring senior notes at a discount provides three benefits to us as follows: First, it reduces our annual cash interest off, thereby improving our cash flow profile; second, it allows us to chip it away at our outstanding debt balance and improve our leverage ratios in an accelerated way; and third, it allows us to capture discount, which is pure value accretion to our equity holders. As we look at capital allocation decisions going forward, including debt and share repurchases, we will continue to evaluate all options available to us with careful consideration of the implications of these decisions on our balance sheet levels. I will now turn the call back over to Dave for closing remarks.

Thank you, Quentin. As we focus towards 2020 and beyond, we are in the process of refining the budget. But before we turn it over to Q&A, I want to provide some color to our thoughts surrounding the capital and operational plan. First, our message remains consistent, and we carry forward our commitment to allocating capital in a disciplined manner, focusing on returns, operating within our cash flow, and maintaining reasonable leverage metrics. We continue to put an emphasis on bottom line returns, not top-line production growth, and expect our 2020 plan to generate neutral to positive cash flow with production and output not a target. As we look to identify areas of improvements, we have concluded that to create sustainable operational efficiencies, it is necessary for capital spend to be more evenly weighted throughout the year. In 2020, we will begin the transition to a more level spend between quarters. And while the shift will result in a reduction in capital efficiencies in the near term, we forecast increased efficiencies in 2021 and beyond, and believe this is a much more balanced and efficient way to run our business. Shifting to the balance sheet, and as Quentin mentioned, we are implementing a measured approach, maintaining reasonable leverage while ensuring adequate liquidity. Based on current strict pricing and including our recent build out of hedge book, we expect very little, if any, revolver draw to fund our drilling and completion activities in 2020. Lastly, published alongside our formal guidance, early next year, we plan to discuss a longer term view of our anticipated activities and provide a two-year outlook, based on certain commodity price scenarios. In closing, considering the current supply and demand dynamics, we continue to have a view that over the next several years, North American natural gas will live within a range of $2.60 to $2.90 per MMBtu. Considering this and all the previous mentioned goals for our 2020 plan, at $2.60, we forecast our 2020 capital program to be roughly cash flow neutral. Should commodity prices improve beyond this, we would remain committed to our program and evaluate all options for incremental cash flow, practicing discipline as we allocate capital to the highest return proposition. Should commodity prices be below that threshold, we would adjust our activity and above all ensure that the 2020 program was funded largely within cash flow. I believe not focusing on top line production growth, but rather building our capital plan towards a neutral to positive cash flow will allow us to maximize value in a challenging commodity market, preserving our high-quality core inventory for a more constructive natural gas and environment in the future. 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. The floor is now open for questions. [Operator instructions] Our first question is coming from Neal Dingmann of SunTrust Robinson Humphrey. Please go ahead.

Dave, my first question is probably for you or Donna. You mentioned the sort of operating efficiencies you’re looking to do and maybe because the state of your plan. My question is, be -- in order to drive that, how do you think about as far as running multiple rigs, both when you think about that in the Utica and over in the Mid-Con. Obviously, we hear a lot about needing several rigs to consider more efficiencies. So, I’m just wondering how you view that. Again, respect of knowing you don’t have a full 2020 plan out, but just how you and Donnie think about that in order to get these efficiencies?

Yes. Thanks, Neal. I appreciate you calling in. The way that we currently have our programs where we drill all of our wells pretty much in the first half of the year and then shut down activity is a pretty inefficient way to run that program. And what we’re trying to do in ‘20 and beyond is have a rig continually running throughout the year and use that to be able to drive efficiency. So, overall, we should see a total number of less rigs drilling the same number of wells. So, I think that will be a lot more efficient. So, I’ll let Donnie provide some extra color on that.

Yes. I mean, I think just to add on to what Dave said, we’ve run multiple rigs in both plays, but we do that in that one and two-quarter tranches. Getting this consistency where you got the same crews, it just -- and I’ll just throw out the SCOOP. If you look at the SCOOP, we’ve gone from 70-plus days to 60 days. With this we did a well [indiscernible] 35 days in the SCOOP. So, that’s what the consistent program can get you, can get you those kind of efficiencies.

Got it. And then, just the follow-up, again, knowing that you don’t have the details of the full plan for next year. But just, how do you think about -- you obviously, given your bonds I think in the 60s and given where the stock is, the currency and versus obviously a growth, I’m just wondering when you look at -- you had a firm amount of free cash flow this quarter. How do you sort of balance, Dave, when you start seeing these things? Anything you can talk around, that will be appreciated.

Yes. So, I think, Quentin said it nicely in his remarks, as we see in terms of where our debt levels are trading, we see attractive opportunity to purchase that. So, we’ve got a team focused on that in the near term. So, I would say that’s kind of high priority for us. Just picking up on your question around drilling activity, if we look at this year and how we transition from ‘19 to ‘20 with a relatively low activity of drilling, we just have one well -- one rig in each basin running now. In the program going forward where we are more ratable, we will see the transition between years, so, ‘20 to ‘21 being a lot flatter than the transition between ‘19 and ‘20 is. So, that’s another benefit of predictability within the program that we’re trying to move towards. So, should flatten it out, should let Donnie’s guys be a lot more efficient. And I think, overall, we’ll be able to drive cost reductions through our program.

Very good. Thank you all for the detail.

Thank you Neal.

Thank you. Our next question is coming from Jason Wangler of Imperial Capital. Please go ahead.

Maybe kind of similar to Neal’s question, but maybe on the debt repurchases versus kind of the outstanding balance on the facility. Just how you guys think about that? I know, Quentin kind of mentioned liquidity obviously is important, but also where the discount is there. How do you kind of balance that as you look at the couple of transactions happening in the fourth quarter as well as the operating cash flows that you guys should be generating going forward?

Yes. Jason, as we look forward to the fourth quarter and our anticipated asset sales, we think will be roughly undrawn on the revolver at year-end. And as Dave mentioned, we’re targeting a program in 2020 that would be neutral to positive cash flow. So, we feel like we’re in a pretty good position of strength as it relates to liquidity, because we’ve got $1 billion commitment on a revolver with nothing drawn at year-end and then very little drawn from 2020. So, that provides optionality and flexibility to utilize some of that revolver to do things that create value, such as buying back bonds and/or stock. So, that’s kind of how we view it. We wouldn’t heavily rely on the revolver, meaning get into it in a material way to do that because liquidity is very important. As we look out over the next few years, you never know what commodity prices will be. But, we would be opportunistically using that liquidity to take advantage of opportunities to create value for our stakeholders. So, that’s kind of how we view it. And, I can’t give you a level at which we would draw it. We’re thinking through that right now.

No. And I probably didn’t ask it as well as I could have. I guess, what I’m asking is, I guess, as you sit now -- and I think you already kind of answered it, the idea would be to pay back the revolver for the most part with cash flows and then start to look back at whether it’s bond or share repurchases after that. Is that fair?

I would say, we’re always -- we’re looking forward over the next couple of years at our plan, and we’re considering capital allocation with a view over the next couple of years and how it impacts leverage, liquidity, cash flow, cash flow per share, and we kind of look at it on a holistic basis. So, the timing of when we might buy back certain securities is considered in light of that kind of a view of the world.

Thank you. Our next question is coming from Josh Silverstein of Wolfe Research. Please go ahead.

I was hoping you could provide a little bit more context around the updated hedge profile. Clearly, you added a lot more protection for next year. But, I was curious how you added swaps above where they were before, considering the decline in the forward curve. And then, just as it relates to the ‘22s and ‘23s, was that part of this with the options?

We’ve talked about our view of long-term gas prices throughout this year being in this 2.60 to 2.90 window, really considering supply-demand factors more than anything else. And, when we were looking at where 2020 was, we look out into the ‘23, ‘24, ‘22 window and saw that we could sell those long-dated calls outside of that window and bring in some dollars back into 2020 and help us in the position that we need to for next year. So, I think, given the volume that we were able to accomplish and the price level, I feel much, much better about where we are for 2020. Also, as we spoke throughout the year, this shoulder season into the winter is the time when we get a real look into next year, and we’ll be actively layering on top of what we’ve already announced, another set of hedges. And, I think that will allow us to get a much better sense of what next year’s program looks like. So, I’ll ask Quentin to provide any color on that.

The only additional thing I’d say is, if you sell a long-dated call at $2.90 you’re effectively capping your upside on a portion of your production in those outer years, that’s -- above $2.90, it’s a good problem to have, and we will still have some unhedged production above those levels. But at $2.90, we can make really good money and generate a lot of cash flow. So, we’re okay taking on that cap to our realized pricing in order to bid up the near-term prices with 2020 swaps.

Got it. Okay. We could certainly follow-up offline on this. But, does that -- I guess, $2.88 number now, does that include the premiums now that you will be receiving from those calls? [Ph]

Yes. We’ve rolled -- so, we effectively sold calls for value. It’s a call option that we receive the proceeds for. But rather than taking the cash and putting it on our books, what we did is we rolled that value into swaps in [indiscernible] that allowed us to swap it. We were doing them at $2.95. So, our blended average now is $2.88.

Thank you. Our next question is coming from Jane Trotsenko of Stifel. Please go ahead.

Good morning, and thanks for taking my questions. I have a question on well cost. I’m just curious if you can provide some commentary on how you see well cost trading on at a foot basis in the SCOOP and Utica in 2020?

Hey. Good morning, Jane. This is Donnie. Yes. When you think about cost -- and I’ll just talk at a higher level on cost, when you look at cost for us, we focus on quality, we focus on efficiencies. That’s what’s driving the value, and cost is a part of that for sure. When you look at the SCOOP, we continue to drop those days down where we’ve gone from 65 plus or minus days last year. We’re down under 60 today. We drilling some of those wells in less than 40 days. So, that’s a definite impact on your cost, plus you have the service environment that’s really been hit pretty hard over the last year and I think probably see more of that next year. So, both bases, we are seeing cost come down, we’re seeing efficiencies go up, and I wouldn’t expect anything different in 2020.

Jane, I would add that going to this more ratable spend through the year, picking up what I said earlier, we would expect that the efficiencies of a year-long operation on a rig would add incremental value to us. So, that’s another way, I think, we see it.

My second question is on the unit cost structure. Should we be expecting like flat per unit cost structure for Gulfport for 2020, or do you see like modest improvement?

Yes. Jane, this is Quentin. We expect generally to be around the same range that we put out for guidance in ‘19 on a per unit cost basis next year. We’ll have more color on that year as we put out formal guidance probably in early January. But, generally, we’re not expecting any big uptick or downturn in the cost structure. We’re continuing to work on everything, including G&A, as we mentioned earlier. And we’ll have more details on that in early January.

Jane, I’d like to follow up on the G&A piece. As part of this new process that we’re adopting for our plan and budget which we didn’t have last year when I joined, we’ve changed people around, brought new people in, you just heard Quentin speak. We are taking a look at G&A in some detail. We do have a voluntary early separation program that’s going to allow us to help reduce our G&A. So, all the levers are being looked at and all the levers are being pulled. And once we get a full handle on what next year looks like, I think, you’ll be able to get a sense of where we’ve taken it.

And the last question, if I may. How should we be thinking about SCOOP basis differentials, once the Midship pipeline is online?

Say the question again, please, Jane. I didn’t quite catch that.

Yes, SCOOP basis differential. So, should we be thinking that natural gas price realizations for SCOOP production might see incremental improvement, once the Midship pipeline is on line?

Jane, this is Quentin. It’s going to be roughly the same as it is right now, somewhere in the $0.45 range is what we’re projecting.

I appreciate it. Thank you so much.

Thank you, Jane.

Thank you. Our next question is coming from Leo Mariani of KeyBanc Capital Markets. Please go ahead.

Hey, guys. I just wanted to ask the plan on the asset sales here. So, I guess, you’ve got the Utica non-op, as well as the SCOOP water assets pending. It sounds like you’re pretty close on those deals. Are these really the kind of final two kind of significant asset sales that you guys are planning to dispose off? Is there anything else that might be coming down the pipe, next year?

Yes. As you know, one of the benefits of having a new plan budget process is just like we did when we found the SCOOP water assets around the second quarter as an opportunity. We’re going to take a full scrub through everything. I don’t have anything right now, Leo, in front of me. But, I expect the discipline that we’ve got from looking at our business that there might be some small things that shake out. But, I think, you’ve touched on the main things that we’ve got.

Okay. And, I guess, just in terms of the Utica non-op, can you give us any metrics around that in terms of roughly how much production is associated with that or sort of how much acreage is to kind of give us a sense of what that could amount to for you folks?

Yes. It’s kind of a de minimis type of thing. We’ve done a great job this year in managing cost related to what we operate. And I’m very happy with that. I think, the issue with the small dollars that we had in non-op is there was a significant overrun. And I just don’t like that. And so, we’ve had the same issue in years past, and I’ve talked about it on these calls before. And so, we’re really just trying to balance that back out and say, hey, we’ve got our non-op budget where we wanted it to be. But, it’s not a meaningful amount of production or anything else.

Okay. That’s helpful. And I guess, just with respect to the budget, obviously, I appreciate the fact that you guys have yet to kind of finalize where 2020 shakes out. But, just from a high level, I mean, it sounds like the way you guys are sort of describing it that is a good chance that we could have slightly lower activity next year and kind of lower CapEx, is that kind of how the direction you guys are moving?

Yes. I don’t have any issue with that. We’re not chasing the production target here. As Quentin mentioned, we’re focused on returns. I think, the build of our hedge book here has got off to a great start. In these new hedges we’ve got to help a lot. We’ve got some more work to do there. I think, that will dictate what kind of absolute level and spend we’ve got. But, moving to this more ratable capital through ‘20 and ‘21 and beyond, I wouldn’t be surprised, if next year is down a little bit from where we are this year. So, I think you’re directionally right.

Thank you. Our next question is coming from Jeffrey Campbell of Tuohy Brothers. Please go ahead.

I’ll follow up the last question, just ask in a slightly different way, which is, as you move into 2020, and bearing in mind the current commodity environment, do you believe the fewer longer laterals that you’ve drilled in the Utica can maintain steady production there next year?

Yes, we’re very pleased with the well performance there. And so, I think that’s fair, Jeff.

Okay, great. And then, kind of following on with that, with the significant inventory in the Utica winding down, I was wondering if you see any more capital going to the SCOOP next year, as a percentage of spend?

Yes. Because this is kind of a new process in our organization, or how I’d like to have the plan and budget done, I would really prefer not to front run what we’re doing here. Earlier this year, we talked about capital moving between the two different basins. We still have that as an option. We’re not FT-bound [ph] in either place. So, we can do that based on economic attractiveness. And so, yes, I think, we have that flexibility. As you know, the Utica wells are cheaper and quicker. So, the dollar comes back to you faster versus the SCOOP, which has the liquids component. So, that will all be factored in as we work through the plan for this coming year. And we’ll have a pretty good idea and you’ll get to know where that splits when we actually come out with our final budget.

Okay. That was helpful. Thank you. Last one for me. Some E&Ps have been successful at selling ORRIs as assets that generate cash payment at attractive cash flow multiples. And in fact, you guys just sold some legacy ORRIs in the Bakken. I was just wondering, if this is a potential go forward arrow in the Gulfport quiver, particularly in relation to other potential asset sales as you work on getting that done over time?

Yes. Jeffrey, I think, that’s very insightful view and it’s certainly something that we think about. And through this process, we will be able to see what impact that has, but don’t have any specific plans today. But, it certainly is a, as you said, an arrow in the quiver. And so, yes, I’d recognize that.

Thank you. Our next question is coming from Kashy Harrison of Simmons Energy. Please go ahead.

Just one quick one for me. Good morning and thank you for taking my question. I was just wondering where you guys see maintenance CapEx now for the business? Thank you.

Yes. So, if you tell me what gas price you want, I can probably address that. But, it’s something, 5 and a little bit less is probably fair is me sort of mudslinging a number, which I hate to do, but something like that.

All right. That was it for me. Thank you.

Thanks, Kashy.

Thank you. Our last question today is coming from Noel Parks of Coker & Palmer. Please go ahead.

In hearing your thinking about your development pace and trying to smooth that out, just wondering, do you have a view on where seasonality in gas prices have headed. I was wondering if in your thinking there is an assumption embedded of either seasonality getting more pronounced in the shoulder months, or I guess, you could make an argument that longer term export demand that might get smoothed out. So, just looking for your thoughts on that.

Yes. You know that -- I think, that’s in insightful question is to how the markets absent export have behaved with summer and winter draws being quite different, and where we’re going with the impact of exports to Mexico and particularly LNG, which don’t have that same seasonal variation. So, what I would expect to see going forward is the high level frequency to change and that we might see some price moves that are tied more to those export draws than the domestic demand. So, I think that’s a very good way to think about where we’re going. I think, probably until 2025, when we see a step up in volumes, leaving the U.S., won’t be as much, but I think we’re going to start to see more and more of that. And I think that’s going to dictate a lot of the changes within our North American market. So, I think, that’s a very good thought of yours to look at that.

Hey, Noel. I’ll follow up on a micro. That was a macro kind of thought. From our Company’s perspective, if you look at our production profile, at least here in ‘19, we maximized our production for the year in September. And if you think about gas prices, that’s probably not an optimal time to have your maximum production, because that’s the shoulder month and it’s typically low. So, the evening out of the capital spend will allow our production profile to be a little more evenly weighted through the year, so we get the benefit. Our production comes down in the fourth quarter and the first quarter when you typically have -- January, February, we have the highest gas pricing. So, one of the benefits of evening capital spend is you’re getting rid of that kind of lumpy production in months that don’t make sense where you have spikes in production. So, hopefully that will help us going forward.

Great, thanks. And my other question was, sort of the silver lining we’ve had in this tough stretching years for energy, have been on the service cost front, certainly a big contributor to efficiency. Do you -- can you foresee any scenario where you were dealing with meaningful service cost inflation? I know, you said that you were planning to introduce more like a two-year view when you next update guidance. So, just wondering, I guess, maybe looking at year two, do you have any assumptions for cost inflation in there?

No. I think, the way I’d look at it is, we built up a service industry capability, based on some pretty strong growth. And now, the efficiencies, plus the impact of where product prices have gone, we’re completely oversupplied. And so, I think, to be able to get back to any sort of balance is going to take a long time, so several years. There may be some equipment retirement and upgrading, et cetera. But, we’ve not seen anything that would suggest that there is a shortage or short supply of equipment we need. And so, I think that’s all to the producers’ benefit.

Thank you. At this time, I would like to turn the floor back over to management for any closing comments.

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