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Gulfport Energy Corp
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Greetings and welcome to the Q2 2018 Gulfport Energy Corporation 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.
I would now like to turn the conference over to your host, Jessica Wills, Director of Investor Relations. Thank you. You may begin.
Thank you and good morning. Welcome to Gulfport Energy Corporation's Second Quarter of 2018 Earnings Conference Call. I am Jessica Wills, Director of Investor Relations. Speakers on today's call include Mike Moore, Chief Executive Officer and President; Donnie Moore, Chief Operating Officer; and Keri Crowell, Chief Financial Officer. In addition, with me today available for the question-and-answer portion of the call, are 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 vary 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 second quarter 2018 net income of $111.3 million and $0.64 per diluted share. These results contain several non-cash items including: an aggregate non-cash derivative loss of $76.8 million; a gain of $231,000 attributable to net insurance proceeds in connection with the legacy environmental litigation settlement; a gain of $122 million in connection with the sale of Gulfport's 25% interest in Strike Force Midstream; and the sale of 1.2 million shares of common stock held in Mammoth Energy Services; and a gain of $8.9 million in connection with Gulfport's interest and certain other equity investments.
Comparable to analyst estimates, our adjusted net income for the second quarter of 2018, which excludes all the previous mentioned items, was $57 million or $0.33 per diluted share. An updated 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 joining our call this morning. As announced in our earnings report yesterday evening for the second quarter of 2018, Gulfport reported approximately $57 million of adjusted net income on $329.6 million of adjusted oil and natural gas revenues and generated approximately $213.6 million of adjusted EBITDA.
Gulfport had another solid quarter as we carried the momentum from our strong start to the year with an active quarter operationally and highlighted by production exceeding the high end of our guidance. Total net production averaged approximately 1.33 billion cubic feet of gas equivalent per day, increasing 3% over the first quarter of 2018 and 28% over the second quarter of 2017. Our second quarter results were driven by strong production growth in the Utica Shale, turning in line 14 dry gas wells throughout the quarter and continued solid performance out of the SCOOP. Our midstream and marketing group continues to enhance the value received for all of our products and we experienced another quarter of strong price realizations.
In the Utica as anticipated, the numerous capacity projects put into service to-date has led to a structural improvement in local differentials, advantaging Gulfport as our incremental growth volumes priced into a basis-tightening local market. In addition in the SCOOP, we have built a diversified firm portfolio with regards to both pipelines and markets outside of the basin which has boosted our realizations to-date and bridged us to our long-term solution, Cheniere's Midship project of which we are an anchor tenant and recently increased our capacity on the pipe. With regard to expenses, our total per unit operating expense during the quarter equaled $0.96 per Mcfe and when coupled with our strong price realizations resulted in adjusted EBITDA increasing 28% over the second quarter of 2017.
Lastly, we were active on the monetization front, completing the announced sale of Gulfport's 25% equity interest in Strike Force Midstream and monetizing approximately 1.2 million shares of Mammoth Energy Services. Our activities year-to-date have positioned us well as we continue to execute on our commitment to capital discipline and reach a pivotal point in our 2018 program, achieving free cash flow generation beginning here in the third quarter of 2018. Driven by our performance year-to-date and forecasted activity for the remainder of the year, we have narrowed our 2018 production guidance and we now anticipate our total net production during 2018 will be in the range of 1.32 billion to 1.34 billion cubic feet of gas equivalent per day, an increase of 21% to 23% year-over-year.
We remain committed to funding our 2018 capital budget from cash flow and have reaffirmed our 2018 total capital guidance. As planned, our capital program was heavily weighted to the first half of the year and during the six month ended June 30, Gulfport's D&C capital totaled $483.5 million and non-D&C capital totaled $76.2 million. Capital spend will decrease significantly in the back half of 2018 and as a result position Gulfport to deliver free cash flow beginning in the third quarter.
On the monetization front, as previously announced, during the second quarter, we completed the sale of Gulfport's 25% equity interest in Strike Force Midstream to EQT Midstream Partners in an all-cash transaction for a total of $175 million. In addition, on June 26, Gulfport participated in a secondary offering of Mammoth Energy Services, receiving approximately $50 million in net proceeds and following the sale, reducing Gulfport's position in Mammoth Energy to total approximately 9.8 million shares with Gulfport's remaining ownership valued at approximately $350 million today.
Consistent with our comments from the first quarter, we are devoted to recognizing the most value for our shareholders as we evaluate the best uses of our available liquidity. Year-to-date, we have repurchased $110 million of Gulfport shares in the open market, totaling approximately 10.5 million shares at an average price of $10.47. And as of June 30, we had reduced the amount outstanding on our revolving credit facility to $75 million and held $119 million in cash on the balance sheet.
Gulfport has reached a significant milestone in our 2018 program as we expect to generate free cash flow in the back half of the year. As we weigh the opportunity set for uses of free cash flow, we will continue to consider all options including additional share repurchases and debt reduction, practicing discipline as we allocate capital to the highest return proposition to maximize shareholder value.
I will now turn the call over to Donnie to expand more on our operations.
Thanks, Mike, and good morning, everyone. Gulfport has had another great quarter across all of our assets, executing on both the operational and capital budget for the second quarter. A few months ago, I outlined three defined areas of focus for our business in safety and environmental performance, base production and new well turn-in-line delivery, and cost efficiency. And we're making good progress in all of those areas. I'll quickly touch on a couple of those following our second quarter results before diving into the details.
In our base production, we continue to see strong well performance, experiencing another quarter of excellent facility runtime and continue to see our base production outperform our budgeted expectations. Our new well delivery remains on track, turning in line 14 gross wells in the Utica and one gross well in the SCOOP during the quarter, all on target with our anticipated online dates.
On the cost efficiency side, we're within budget and on track to deliver our capital plan and remain focused on delivering the full year capital budget, reiterated again today. In addition, we're making great progress at the drill bit in the SCOOP, which I'll go into further detail shortly, leaving us confident in our ability to lower our drill base as compared to our 2017 program, reducing overall well cost in the play.
Specific to service costs, we have contracts with pricing in place and services secured for the remainder of our 2018 activity. And as we approach 2019, we are hard at work, finalizing our development plans and taking steps to lock in prices and services required to execute the 2019 program. For instance, we recently announced the extension of our frac contract with Mammoth Energy, now covering both the Utica and SCOOP asset areas.
And we're very pleased to continue the relationship and further build upon the efficiencies we have created together over the past several years. In addition, we have begun extending rig contracts, locking in tangible goods at today's prices, and securing all ancillary services to support our 2019 program. This year is playing out consistent with what we expected. And we are very confident in our team's ability to deliver on the goals we set when we entered the year.
Now on to the details. In the Utica we spud seven gross wells, utilizing two operated rigs during the quarter. As we mentioned before, our 2018 program focuses on maximizing lateral lengths and realizing economies of scale on our per foot metrics. And during the second quarter, we experienced the longest average lateral length across the wells drilled, resulting in the lowest lateral cost per foot on the drilling front we have seen to-date in the play. The wells in the second quarter had an average drill lateral length of 12,500 feet, an increase of 53% over the 2017 program. And when normalizing to an 8,000-foot lateral as assumed in our type curves, we averaged a spud-to-rig release of 18.9 days, down slightly from the first quarter of 2018 and 2% over our full year 2017 results.
Turning to completions. In the Utica Shale, we had another very active quarter. As planned the Utica completion program was front end weighted. And by the end of the second quarter, we had completed nearly 80% of our total planned stage count for 2018. During the second quarter, we averaged 5.7 stages per day and completed 583 stages in total, which includes 11 wells completed and 4 wells in progress at the end of the quarter. Throughout the quarter, we turned-to-sales 14 gross dry gas wells in the Utica with an average lateral length of nearly 8,500 feet. This level of activity led to a strong quarter on the production front, averaging 1.07 billion cubic feet equivalent per day during the second quarter, an increase of 3% over the first quarter of 2018 and 24% year-over-year as well as marking a record level of net production for the asset.
The Utica continues to be a very consistent and reliable asset in our portfolio and we continue to look at every phase of the operation to identify where we can become more efficient to add more value, and as I've said before shifting to taking minutes, no longer days out of each activity. Switching over to the SCOOP, we continue to see improvement at the drill bit with four growth wells spud, including three Woodford and one Sycamore Well, utilizing three operated rigs during the quarter. The wells released had an average lateral length of 8,100 feet, an increase of 8% over the 2017 program. And when normalized to a 7,500-foot lateral as assumed in our type curves, the wells averaged a spud-to-rig release of 60.9 days during the second quarter, 13% better than the first quarter of 2018 and a 16% improvement from our 2017 program average.
When analyzing the wells released in the first half of the 2018 program, approximately 40% of the 2018 well set have had a spud-to-rig release or 48 days or less and 60% have been drilled in 56 days or less. When comparing this to the 2017 program, Gulfport had zero wells with a spud-to-rig release of less than 50 days. Our improvement in the drilling phase is further highlighted by our ability to improve our average feet drilled per day by over 25% from our 2017 program as well as establishing a Gulfport record by releasing a well with the spud-to-rig release of just 44 days during the second quarter.
We continue to focus on identifying, implementing and realizing efficiencies in the play. As we get more wells under our belt, we continue to update and refine our understanding of the reservoir, and as you can see create more consistent well delivery. We will continue to build upon this momentum and remain intently focused on identifying areas of improvement, including optimizing the well design, increasing lateral lengths, horizontal targeting, casing program design, optimizing bottom hole assemblies, and bit selections just to name a few. Not only did it decrease drill days, but ultimately maximized value for every dollar we invest.
On the completion front, during the second quarter, we turned-to-sales one gross dry gas Woodford well with a stimulated lateral length of 9,400 feet. While running one completion crew during the quarter, we averaged four stages per day and completed 265 stages in total, which includes five wells completed and two wells in progress at the end of the quarter. Production during the quarter averaged 247.3 million cubic feet equivalent per day, a slight increase to the first quarter of 2018 and 53% year-over-year.
Following the second quarter, we turned-to-sales two wet gas Woodford wells, and alongside earnings, we announced initial production rates on our Cleburne and EJ Craddock 1 and 2 wells. On average, we continue to see great results of the play and remain very encouraged as we gain additional long-term production history on a longer set – larger set of wells. With regard to exploration activity, during the second quarter, we spud one Sycamore well, targeting the upper portion of the Sycamore formation and recently released the well.
We plan to complete this well during the third quarter of 2018 and provide results in the latter part of the year. When normalized to a 7,500-foot lateral the well had a spud-to-rig release of approximately 62.5 days. Results to-date have proved there is a significant resource in place and we continue to get increasingly comfortable with folding the Sycamore into our development plan in a more meaningful way, transitioning from exploration to repeatable low risk development in the zone.
With that, I will turn the call over to Keri for her comments.
Thank you, Donnie, and good morning to all. Gulfport second quarter production came in ahead of expectations, and as Mike mentioned, was driven by the continued strong performance of the existing asset base and turn-in-lines in our Utica Shale play. Production averaged 1.33 billion cubic feet of gas equivalent per day and consisted of approximately 89% natural gas, 7% natural gas liquids, and 4% oil. Based on results year-to-date and our forecasted activities for the remainder of the year, we now forecast our full year 2018 average daily production to be in the range of 1.32 billion to 1.34 billion cubic feet per day, an increase of 21% to 23% over 2017.
In addition, we currently forecast third quarter of 2018 average daily production to be approximately 1.36 billion cubic feet of gas equivalent per day. On the realizations front, during the first six months of 2018, our realized natural gas price before the effective hedges and including transportation costs settled $0.50 per Mcf below the average NYMEX price. Based upon actual results and utilizing current strip pricing at the various regional pricing points at which the company sells its natural gas, we reiterate our full year guidance and continue to forecast to average in the range of $0.58 to $0.72 per Mcf below NYMEX settlement prices in 2018.
As we have previously stated, driven by the seasonality of natural gas and the markets we reach, we believe our differential will average at the wider end of the range during the third quarter and narrow into the fourth quarter of 2018. During the first six months of the year, before the effective hedges, our realized oil price came in at $2.12 off WTI and our realized NGL price came in approximately 46% of WTI. And we reiterate our expectation to realize $3 to $3.50 off WTI for oil and 45% to 50% for NGLs during 2018.
Our realized prices continue to be supported by our hedge position and we realized a settlement gain of $0.05 per Mcfe during the second quarter of 2018. Our philosophy of maintaining a strong hedge book is an integral part of our business, and our portfolio continues to underpin our development program, providing a high degree of certainty surrounding the cash flow profile for the remainder of our 2018 program and beyond. Our current hedge portfolio covers 80% of our expected 2018 natural gas production with 950 million cubic feet per day priced at $3.05, and during the second quarter, we meaningfully added to our 2019 natural gas position, securing 1.15 billion cubic feet per day at $2.81 per MMBtu. Maintaining an active hedging program is key to supporting the long-term development of our assets, and we will continue to opportunistically layer on additional hedges and basis swaps to provide line of sight to our realizations and cash flows.
For the second quarter, our strong realized prices and hedge position resulted in adjusted oil and gas revenues of $329.6 million, which is composed of approximately 76% natural gas revenues and 24% liquids, including 13% oil and 11% natural gas liquids. In terms of cash operating expenses, our per unit operating expense which includes LOE, production tax, Midstream Gathering and Processing, and G&A totaled $0.96 per Mcfe during the second quarter, down 7% when compared to the second quarter of 2017. When coupled with our realized pricing uplift, we expanded our adjusted EBITDA and generated approximately $213.6 million of EBITDA during the quarter, an increase of approximately 28% over the second quarter of 2017.
As previously mentioned, we reaffirm our full year 2018 total capital budget and forecast to invest $750 million to $815 million across our assets funded entirely within cash flow at today's strip pricing. For modeling purposes, we currently forecast the remaining capital invested to be slightly more weighted to the third quarter of 2018.
Moving on to the balance sheet. We remain committed to maintaining reasonable leverage metrics. And as of June 30, 2018, Gulfport's net debt-to-EBITDA ratio decreased to 2.3 times or below 2 times when adjusted for Gulfport's ownership in Mammoth Energy. Based on our projected cash flows from the remainder of the year, at current strip prices, we forecast our leverage ratio at year end 2018 will remain at the low end of our targeted range.
I will now turn the call back over to Mike for closing remarks.
Thank you, Keri. In closing, we continue to show consistency in our ability to execute by exceeding our production estimates, increasing the narrow end of our 2018 production guidance, while strictly adhering to our 2000 capital budget. During the quarter, we hedged a large portion of our anticipated 2019 natural gas production, mitigating the volatility in the commodity price and giving us a high degree of certainty in our anticipated cash flows. Consistent with our messaging, while we have not provided specific outer year expectations, for 2019, we continue to forecast low double-digit growth within cash flow at current strip prices.
We are committed to remaining disciplined as we allocate capital, demonstrating our commitment to the Gulfport shareholders with every dollar invested as we have reached a significant milestone in our 2018 program and expect to generate free cash flow in the back half of the year.
This concludes our prepared remarks. Thank you again for join 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, sir. Our first question comes from Neal Dingmann with SunTrust. Please state your question.
Morning, all. Mike, my first questions are in the SCOOP. In the SCOOP, and you guys talked about obviously just the overall company about the free cash flow. My question is really, would you consider – what would it take to consider stepping up the pace, step up the pace of your southeast SCOOP activity? And why I'm asking this, I noticed last night there was an offset operator that reported a four-well pad very near yours that had a high IP, around 2,700 and nearly 50% oil. So though I know you're not focused on growth, just wondering, given these sort of huge results that are out there around you, what would it take to increase that activity?
Okay. Thanks, Neal. First of all, let me say, we're actually in that well. So I know which one you're talking about. I just want us to keep in mind that just with the activities that we've had in section to-date (00:25:09) in that SCOOP asset, we've already – our revenues are already 25% liquids weighted, thanks to the SCOOP activity. But yes, in 2019, I think you should – you could see, you will see a shift to the east in our activities which should have a little higher liquids component.
Very good and then just moving over to Utica. Obviously, investors are still pretty critical of gas, but I'm just wondering if you could talk, if you isolate, I'm just wondering if you isolated that Utica asset, your entire Utica assets, how would you think about that just as a free cash flow story? I'm just wondering, I mean again is that if you just separated that or let's assume for a second you spun that out, how would you think about that asset being gas and all right now?
Well, I think, first of all, I still think that the Utica and SCOOP together are very complementary assets and we've actually talked about this before, but the Utica is a little more mature asset. We – let's take 2019 for instance, we will show production growth in Utica. We will generate free cash flow in Utica. And the plan is and has been, since we purchased the SCOOP, over time, we'll take that excess cash flow from the Utica and put that over into the SCOOP where we have a higher margin molecule coming out the ground.
Very good. Thanks, Mike, for the details.
Thanks, Neal.
Thank you. Our next question comes from Ron Mills with Johnson Rice & Company. Please state your question.
Good morning.
Good morning.
Hey, Donnie for you, on the drilling side, you talked about some significant improvements getting down to even 45 to 50 days. Can you talk about some of the things you've done on the drilling side to achieve that? And give any other color on things you're evaluating in terms of both the drilling and completion design that you mentioned?
Yeah, sure Ron, thank you for that. Yeah, very pleased with the progress, last year 72 days and as you've just said and I said it in my comments, 60% of our wells, less than 56 days this year, a tremendous step change to our progress there. I think a couple of things I'll point out, the well history that we've gotten now, how we brought that back into our subsurface understanding, it's really a true team effort between our geoscientist, our drilling team, the entire operations team. And then just the different combinations of, as I mentioned before, bottom hole assemblies and bits and mud programs and well designs. You're starting to find that right combination and get to where we're seeing that consistency in delivery and that's what we're really looking for.
So going forward, as we shift more to development, you start really seeing casing designs more in a development mode versus appraisal mode. So that's a big step change ahead for us. More wells per pad, so we'll increase that as we go forward. And then of course, we're always looking at the completion designs. It's hard to make too many changes right now. I mean the wells we're delivering are as good as any in the play, but we'll always continue to tweak and optimize to deliver more value.
Great. And on the follow-up, staying in the SCOOP, I know you drilled your first Sycamore well. What are you looking for in that well and what would it take for the Sycamore to start to show up in your inventory because it's the zone that you all didn't allocate any value to in the acquisition?
Yeah, Ron, this is Donnie. I'll start off and maybe Mike can chime in. As you mentioned, we just TD-ed this upper Sycamore, so that is a little different task force for testing the upper portion of the Sycamore formation. As I mentioned, we'll get that completed this quarter, get some data. Latter part of the year, we can share. If you think back, we've got one operated lower Sycamore right now and several non-operated wells that we've participated in and we're definitely excited about the performance we're seeing. And as you look across our acreage, you know that the resource pretty closely matches our Woodford footprint, so – and also I'll bring up, let's remember the Sycamore was a vertical target for many years in the Mid-Con. So that's a proven resource in the SCOOP. And so once we get some data from that upper Sycamore Well, a few more non-operated wells, and we'll be able to add it to our model and see what that co-development looks like with the Woodford. So really excited about where we're at and where that can go and stay tuned for some more locations and...
And just to add to that, we are very excited about the opportunity set that we have in the Sycamore and Springer for that matter. In our view, the aerial extent is de-risked but density is necessary to get our final thoughts on the inventory. But I think you could probably look for us having higher levels of activity in the Sycamore in our 2019 program.
Right. Thank you.
Our next question comes from David Deckelbaum with KeyBanc Capital Markets. Please state your question.
Good morning, everyone. Thanks for taking my questions.
Hey, David.
Good morning, David.
Actually, just a follow-up on Ron's last question. You mentioned looking at Sycamore as a co-development opportunity and then adding some of that to the 2019 plan. Would that be a co-development target in 2019 or I guess timeline wise how far away are we from kind of understanding density and sort of likewise the timing on when we can think about how much resource is there?
Yeah, yeah, David, this is Donnie, and I'll start off on that one. If you think about our previous Sycamore, it actually was completed with the Woodford well, so we're able to kind of look and see any early indications of what co-development could look like. And again, we're very, very happy with those results. So, again, go back to co-development, we really see a lot of value in that, not only for the Woodford but for the Sycamore itself. So we'll continue to look at that. We'll use all the data that we're getting from some of these non-operated wells also, so excited about where it's at.
David, one thing I'd add, this is Paul, is that the strength of the position we have here in the SCOOP is we do have a lot of small working interest exposure to non-op activities in the area and we've got a number of peers that are actively exploring the same questions we're exploring here regarding that zone.
Thanks, Paul. And my next question was just on the Midship pipeline, you guys took some extra capacity, I think another $100 million a day. Can you sort of give us your thoughts on why you sort of took that initiative and what sort of economic benefits you see on Midship relative to having not signed up for those volumes?
Hey, David, this is Ty. When we initially took the position on Midship, it was right after we purchased the asset and mainly because we're aware of the need for additional takeaway from the area. For a variety of reasons, we felt like that the Midship project was the best to anchor. Now that we've had the SCOOP asset for a while, as you've heard, we think the well performance, quality of rock, those kind of things have allowed us to update kind of the view and we felt like that it was a prudent time at this time to right-size that commitment to that project.
Good. Is there like an approximate sort of dollar per Mcfe benefit that you see being on Midship versus the alternative?
Well, as you – I mean the basin is getting pretty tight. So I think that there's not a lot of alternatives out there that's really under construction. You have a couple of other projects that are either in service right now or have been put in service. But other than that, the Midship is the next project that's out there. So it is the alternative or it is the, I think, the next project that people are looking towards and we're in anchor position on it.
Thanks, Ty. Thank you, guys.
Thank you.
Thank you, Dave.
Our next question comes from Jason Wangler with Imperial Capital. Please state your question.
Hey, good morning, everyone.
Good morning.
I was curious in the Oklahoma, the wells are coming in at much lower days. I mean can you talk about the cost impact of that as you see that playing out and what it maybe could do for the cost of these wells?
Yeah, Jason, this is Donnie, and I'll start there. Yeah, the days and typically those days and costs go right in line with each other. And on average, these wells are coming in line with what we published as our D&C cost for our type curve wells. And I can also say as Paul mentioned just a few moments ago, we're in a lot of non-operated wells right around this position. And when I look at operators that have been doing this four, five years, we're right in line with what they're doing. So – and we've done that in basically six, eight months. So we're very pleased with the days we're shaving off, the consistency that we're seeing. And as I said just a moment ago as well, we're shifting more to development. We'll continue to see those days and costs continue to trend down, so great progress. I'm excited about where we're going.
And Jason, this is Mike. I would just add that I'm pleased with the rate of change on the efficiency side here in the SCOOP if you compare it to Utica. Feels like and statistically it is ahead of progress, probably, we were able to make in the Utica. So we're certainly talking to all other operators. We all share data. We all share ideas, but we've been able to take a lot of steps to drive these efficiency. Donnie mentioned those in his scripted comments and I just want to say I'm very pleased with the progress that we've made. I think we can make some more progress as well, but so far so good.
Okay. And maybe just a follow-up to that. On the completion side, I think when you guys bought the asset, you kind of had a pretty good feel for what you wanted to do and the previous operator had some good success. Have you seen much change there now that you have the asset for some time or is there anything that you guys have kind of tweaked or has it mostly just been simply kind of continuing on that path because the well results have kind of been pretty consistent again since you've acquired it?
Yeah, no, that's right. So, Jason, this is Donnie. Looking – there's always a number knobs that we're turning in completions from cluster designs to water volumes to the one everyone looks at, proppant loading just to name a few. And we'll continue to tweak some of those knobs as you mentioned. The wells continue to be strong. Typically, up here, it's more of a crosslink or jail type systems that you run. We are looking at some slick water systems here, which are used throughout many plays in the country. So I think that's a potential step change for us, but we'll continue to deliver the well results and we'll always continue to try to tweak that and optimize our designs to get the most out of our wells.
I appreciate it. I'll turn back.
Thanks, Jason.
Thanks, Jason.
And our next question comes from John Nelson with Goldman Sachs. Please state your question.
Good morning.
Morning.
And thank you for taking my questions.
Thank you.
Some of the service providers have cited pricing weakness in Appalachia in their updates the last couple weeks. I know you guys highlighted that you've extended the Mammoth relationship. Can you just talk to the pricing structure embedded in that contract? And if pricing still kind of marks to some spot index, or just any general kind of service cost pricing comments that you guys are kind of seeing at the moment?
Yeah, this is Donnie. And I'll start off on the contract you referenced there with Mammoth. We are again very pleased to extend that through 2021 and the efficiencies we've gained together over the past few years are really top of the industry delivery in the northeast. And really the mechanics didn't change as we mentioned in the remarks before. It just gives us flexibility now to be able to use that in either of our assets, Oklahoma or Ohio. If you think about pricing for us, most of our services, pricing has been locked in for the year. A lot of our activity is done for the year. We're ramping a lot of that down where we're front end loaded. So it really hasn't impacted us and we haven't really seen much fluctuation in prices.
I guess as we think about 2019 though, in the discussions you're having, does it seem like the market softening, that that could be a tailwind as we head into 2019, or is it still too early that you haven't necessarily been in those discussions yet?
Yeah, I mean we've been in discussions. I think it's too early to say which way it's going. We haven't really seen it leaning either way. We're pretty consistent right now. As I mentioned in my remarks, we're starting to lock things in for 2019 and feel good about where we're at.
Okay. That's helpful. And then just I think you guys have been clear all along that the CapEx program is front half weighted at that two-thirds and kind of came in a little over 70%. Just as we looked at some of the kind of working interest levels, I guess, where I'm going with this is, the remaining completions or drilling, do the lateral lengths get shorter or the working interest levels go down or relative to the plan have some of those come in higher than what you would have thought that would matter at all to the full year CapEx budget? Put another way, could we look out in a quarter and say, well, our working interest levels went up and that's actually driving a CapEx increase. We're going to drill longer laterals? Sorry. Thanks.
Yeah. No, that's a good question, and we actually saw some of that last year, so it's probably relevant as well. This is Mike. That's not the case this year. We went into the year knowing pretty close what our working interest was going to be for the programs of the entire year in both SCOOP and Utica. We have very high interest in both areas this year. We know our lateral lengths, so they're not changing. We're exactly where we thought we would be for the year as far as CapEx is concerned. And I might just point out that we're finished with our Utica completions and we're down to two rigs in SCOOP. So, just directionally from an activity level, it certainly should indicate and support lower CapEx activity in the back half of the year. We are very committed to our CapEx budget as we've said before. And we feel very good about our position and how the CapEx is going to come in. It's going to be incrementally lower in the third quarter and then the fourth quarter as well. So less activity leads to less CapEx. So we should come out exactly where we thought we would.
That's really helpful. And then just one more housekeeping item from me. The SCOOP well turn-in-lines over the rest of the year, are they pretty ratable between 3Q and 4Q? Is there any backend loading? Just trying to think about how the turn-in-lines will impact the production trajectory.
Yeah, what I'd say, John, is that they're going to be pretty backend weighted to the third quarter and then any 4Q turn-in-lines will be late 4Q.
Great. I'll let somebody else hop on. Thanks, guys.
Thank you.
Thank you.
Thank you.
Our next question comes from Subash Chandra with Guggenheim. Please state your question.
Yeah, thanks. Good morning. A question on big picture Appalachia, you guys – as you've guided, your completions, your pace in the second half of the year are much slower than a year ago, but others have done the same and I'm trying to – I guess I'll ask you to sort of maybe talk about the basin beyond Gulfport if you can, if what this means for 2019 and beyond, two rigs versus six a year ago, others are dropping crews and rigs. Is 2019 level, 2020 level and beyond, is that going to be governed by prices in the basin? Or do you think there's just a secular shift for growth in Appalachia overall?
Well, and this is Mike, I think Donnie and I will tag team on this. But we've got a lot of dynamics up there. And first of all, let me say, we continue to like the economics in the Utica dry gas window. But part of it, number one, is from efficiencies. You heard Donnie talk about what we've been able to accomplish up there, bringing down our drilling days, so you can simply do more with less. Up there, it's a more mature asset. We're certainly further ahead. And then secondly, drilling rigs isn't the only part of the story. We have DUCs up there too, and so I can't speak for other companies as much. But for us, we can have levels of activity kind of separated from drilling activities because we have these DUCs to complete. So that's something that's I think more unique to us and that extends into 2019 as well. As far as what other operators are doing or thinking up there, I'm not sure. Still seems like there are some very active operators up there drilling ahead. So we certainly continue to like the economics and we think it's very complementary to our SCOOP asset, what we're able to do there.
Okay. Is the DUC count in the range of 40 or 50 wells or?
Subash, this is Paul. Think about that being in the 50 to 60 well zip code by year end of 2018.
Okay. Okay. Yeah, that's substantial. And then your leading edge of SCOOP, if you've answered this, I apologize. Dollar per foot, what sort of range did they come in?
Yeah, I mean I don't have the presentation in front of me, but if you look at this roughly for these wet gas SCOOP well is about $1,400 or so per foot. And as I said just previously, these wells are in line with that, that we're delivering. And I really feel like as we get into development mode, we'll continue to drive those costs and days down. So excited about where we're at and where we're going.
Okay. And a final one for me, I think you've sort of referenced, you're kind of focused on the drilling aspects of SCOOP right now, and then you'll focus on the development aspects, so that's kind of an interesting distinction. And you mentioned a few other things that go into the development side of things that you want to work on. Is one of them also sort of staying in zone or is that already something you're doing as we speak (00:45:41)?
Yeah, this is Donnie, Subash. I mean that's something that we've been doing, I think when we took over the asset a year or so ago, we were 50% or so in target, in zone. Our geosteering has been phenomenal. I mean these guys are doing 97%, 98% in zone. So that's kind of behind us now and that's not something we have to really focus on. They're threading the needle right now.
But it certainly, this is Mike, it certainly is it's an important distinction and we've actually, I think we've talked about it in the last two or three calls. When you talk about staying in zone, 50% of the time versus 98% of the time, that's huge from a lot of different aspects, not only can you drill faster, but you're also exposing yourself to the meat of the rock, so to speak, even as you cross these faulted fractured structures here in Oklahoma. So it's very important and we made a lot of success early, a lot of progress early on that area, and we continue consistently quarter-after-quarter to be in that 98%, 99% in zone target range.
Thanks, Subash.
Thank you. Our next question comes from John Aschenbeck with Seaport Global Securities. Please state your question.
Good morning and thanks for taking my questions. I had a follow-up on the drilling efficiencies and the SCOOP. I was curious if you continue to shave off time on the drilling cycles, would you be more inclined to continue at that pace and just drill a few more wells this year than your original plan or would you cap activity levels at your original 2018 plans?
Yeah, John, this is Donnie and I'm sure Michael will chime in on this. But no, we're committed to our program this year. We'll deliver the plan within our budget and those are great problems to have, but they're problems easily solved this year that we will stay within our budget.
We're – I'll just add, this is Mike. We're adding – we're growing 23% this year from a growth perspective and we're committed to our CapEx budget. So we're locked and loaded and we're not going to deviate from that on either side of the equation. So you wouldn't expect to see any changes for 2018.
Okay. Got it. Appreciate the color there. I had my next follow-up I guess is just on delineation of different sounds in the SCOOP. You had the Sycamore tests coming up in Q3. I was curious if you have any additional operated Springer tests scheduled in the near-term or if the game plan is to just continue to participate in non-op wells and let your offset peers do the science work for you.
Yeah, John, this is Donnie. We don't have another Springer slated for this year. We'll do our Sycamore. And as you mentioned, we're in a lot of non-operated positions up here. With Springer tests, we'll continue to let, let that kind of do the delineation and appraisal for us. And we're kind of focused right now on bringing the Sycamore forward and let our non-op position bring the Springer forward. So I think it's a good way of capital constrained. We're going to stick with the budget. That's a good way of getting it all done. So...
Okay. Great. That's it for me. Thanks.
Thanks, John.
Thank you.
Our next question comes from David Beard with Coker & Palmer. Please state your question.
Hi, good morning. Thanks for the time.
Hi, David.
Good morning, Dave.
A macro and a micro question just on the costs. Just wish you could give a little color on 1Q to 2Q, LOE and gathering and processing, they ticked up, well production ticked up, so any color you could give on some of the moving parts on cost?
Sure, David, this is Keri. So, if you remember, winter stretched a little bit longer, ticked into second quarter, so we did have some seasonal non-recurring maintenance charges that drove LOE up for the second quarter, but we do believe our full year, we're still within guidance. We still believe that's the correct range and just those expenses can be a little choppy quarter-to-quarter.
All right. That's helpful. And then just a very big picture question relative to acquisitions. We've seen obviously some properties for sale and some prices that looked pretty attractive. Mike, where do additional acquisitions fall on your radar screen or they're not really there at this point?
Listen, we're a public company. We always have to consider value creating opportunities, whether that's buying or selling. But look, we just finished that SCOOP acquisition. We're in the process of developing, moving into developing mode there, delineating some additional zones for us. We got a lot of inventory between Utica and SCOOP. So I would say, we're focused on our activities in Utica and SCOOP at this point, and not currently looking at anything.
Good. Thank you. Appreciate it.
Thank you.
Our next question comes from Biju Perincheril with SFG. Please state your question.
Hi, good morning. There's been some discussion of using local sand in the basin, I guess from West Virginia, Ohio areas. Is that something you've considered, you plan to test, and any preliminary thoughts on potential cost savings?
Yeah, Biju, this is Donnie. And I mean, if you're looking at just the Ohio, our Utica asset, I mean we've got an agreement in place already for sand. It meets our demands. It continues to be there for us, not really looking in the Ohio now. Down in the Mid-Continent, there's also some regional local sands here that we're looking at which has some potential, but we haven't really executed on anything at this point.
Got it. So for Utica, you're sticking with the current sources you have?
That's correct.
Got it. Okay. Thanks.
Thank you.
Thank you. Ladies and gentlemen, we have run out of time for questions. I'll now turn the conference back over to Mike Moore for closing remarks. Thank you.
Thank you. We appreciate your time and interest today. Should you have any questions please do not hesitate to reach out to our Investor Relations team. This concludes your call.
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