Gulfport Energy Corporation (GPOR) Q3 2018 Earnings Report, Transcript and Summary

Greetings and welcome to the Gulfport Energy Corporation Third Quarter 2018 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'd now like to turn the conference over to your host, Jessica Wills. Thank you. You may begin.

Thank you and good morning. Welcome to Gulfport Energy Corporation's third quarter of 2018 earnings conference call. I am Jessica Wills, Director of Investor Relations. Speakers on today's call include Donnie Moore, Interim Chief Executive 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 differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we may make reference to other non-GAAP measures. If this occurs, the appropriate reconciliations to the GAAP measures will be posted on our Web site. Yesterday afternoon Gulfport reported third quarter of 2018 net income of $95.2 million, or $0.55 per diluted share. These results contain several non-cash items, including an aggregate non-cash derivative loss of $4.1 million, an expense of $917,000 in connection with the litigation settlement, a gain of $2.7 million in connection with the sale of additional common stock held in Mammoth Energy Services following the underwriters' partial exercise of its option granted in the June 2018 offering, and a gain of $12.9 million in connection with Gulfport's interest in certain other equity investments. Comparable to analyst estimates, our adjusted net income for the third quarter of 2018, which excludes all the previous mentioned items, was $84.6 million, or $0.49 per diluted share. An updated presentation was posted yesterday evening to our website in conjunction with the earnings announcement. Please review that at your leisure. At this time, I would like to turn the call over to Donnie Moore.

Thank you, Jessica. Welcome everyone and thank you all for joining this morning. We had a solid third quarter. I look forward to discussing it in more detail with you in a moment. First, I want to acknowledge the other announcement we made yesterday afternoon about Mike stepping down from his positions and resigning from the board. We've been very transparent and there isn't much to add what we disclosed in our press release and filings yesterday. The board has asked me to take charge and that's what I plan to do. I have more than three decades of experience in the E&P industry and have had most of the year now as COO to get to know the team, the operations, and the assets here at Gulfport. So your expectation of us should be that we'll drive forward and my aim is to raise the bar. I met with our team yesterday after the announcement we are all focused on moving forward. The board now will continue to act in the best interest of Gulfport keeping our shareholders foremost in mind. In this spirit we will be disciplined capital allocators, we remain focused on developing attractive opportunities to enhance value and deliver profitable growth. With that, I want to move ahead to discuss our third quarter performance. As announced in the earnings report yesterday, for the third quarter of 2018, Gulfport reported approximately $84.6 million of adjusted net income on $365.1 million of adjusted oil and natural gas revenues and generated approximately $238.8 million of adjusted EBITDA. The third quarter marked a strong operational quarter for Gulfport, delivering a 7% increase in total production per day over the second quarter of 2018 and experiencing strong price realizations across all of our products. Total net production averaged approximately 1.43 billion cubic feet of gas equivalent per day, increasing 19% year-over-year, and driven by the continued outperformance of our base production wedge and active turn-in-line schedule in both of our core asset areas and an increase in ethane recovery during the quarter. Our Midstream and Marketing teams continue to enhance the value received for all of our products and with the improvement in ethane prices during the third quarter, Gulfport elected to adjust our ethane recovery in both the Utica Shale and SCOOP to optimize the barrel composition and maximize the value received for the NGL stream. On the natural gas front, we continue to benefit from our diversified portfolio as well as capitalize on opportunities created through the ever-changing flow dynamics within the basins, and during the first nine months experienced very strong pricing for natural gas, leading us to narrow our anticipated 2018 gas differential alongside earnings yesterday evening. 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 12% over the second quarter of 2018% and 22% over the third quarter of 2017. Driven by strong resource performance year-to-date and forecasted activity for the remainder of the year, we have again increased our 2018 production guidance. And we now anticipate our total net production during 2018 will be in the range of 1.36 billion cubic feet to 1.37 billion cubic feet of gas equivalent per day, an increase of 25% to 26% year-over-year. During the nine months ended September 30, Gulfport's D&C capital totaled $638.1 million and non-D&C capital totaled $96.3 million. We remain committed to spending within the range of our previously provided capital budget, now forecasting total capital invested during 2018 to be within the book-end of the range, at approximately $815 million for the full year. Capital spend will decrease significantly during the fourth quarter of 2018 with activity decreasing quarter-over-quarter and remaining nimble in our operations to adhere to our commitment of capital discipline and the 2018 capital budget. Considering our large DUC inventory we hold in the Utica totaling approximately 55 gross wells today, we have adjusted our activity during the fourth quarter to further emphasize our commitment to the 2018 capital budget and we currently do not have a rig running in the play today. Lastly, completion activity in both the Utica and SCOOP concluded during the third quarter of 2018, and we do not expect to resume this activity until the beginning of 2019. Consistent with our previous comments, we are devoted to recognizing the most value for our shareholders, as we evaluate the best uses of our available liquidity. During 2018 Gulfport has reduced our net debt levels, and as of September 30, our leverage ratio decreased to 2.14 times at the low-end of our targeted range and down from 2.6 times at year-end, 2017. Year-to-date, we have repurchased $110 million of Gulfport shares in the open market and approximately $90 million remains under the current authorization. As of September 30, we had reduced the amount outstanding on our revolving credit facility to $60 million and held $125 million in cash on the balance sheet. Now the details. In the Utica, during the first nine months of 2018, we spud 23 gross wells, utilizing on average two operated rigs, the wells had an average drilled lateral length of 10,350 feet, an increase of 27% over 2017. And when normalizing to an 8000-foot lateral, we averaged a spud-to-rig release of 19.5 days, in line with our full-year 2017 results and highlighting the consistency of the drilling phase in our Utica operations. Turning to completions in the Utica Shale, we completed 37 wells during 2018, averaging 5.3 stages per day and completing a stage total count of 14,071 stages. During the first nine months of 2018, we turned-to-sales 28 gross dry gas wells in the Utica, with an average lateral length of 7,700 feet. This level of activity has led to very strong production from the asset, averaging 1.14 billion cubic equivalent per day during the third quarter, an increase of 7% quarter-over-quarter and 16% year-over-year, as well as marking another quarter with a record level of net production for the asset. During the fourth quarter, we plan to turned-to-sales seven gross operated wells in the Utica, bringing our 2018 total to 35 gross wells turned-to-sales throughout the year. The Utica continues to be very consistent and reliable asset in our portfolio. We are extremely pleased with the performance of the resource year-to-date. Switching over to the SCOOP, we continue to see improvement in our drilling phase, and during the first nine months of 2018, we spud 12 gross wells in the play, including 11 Woodford and one Sycamore well, utilizing on average three operated rigs in the play. The wells released had an average lateral length of 8,100 feet, an increase of 10% over 2017 and when normalized to a 7,500 foot lateral, averaged a spud-to-rig release of 64.9 days, a 10% improvement from our 2017 program average. When analyzing the wells released to date in the 2018 program, consistent with my comments from last quarter, roughly 40% of the 2018 Woodford well set have had a spud-to-rig release of 48 days or less, and 60% have been drilled in 56 days or less. As a reminder, in 2017, Gulfport had zero wells with a spud-to-rig release of less than 50 days. Our improvement continues to be further highlighted by establishing a new Gulfport record of releasing it well with a spud-to-rig release of just 43.7 days during the third quarter. As you can see our focus on identifying, implementing and realizing efficiencies in the play is yielding results. We look to continue to build upon this momentum into the fourth quarter and 2019, remaining focused on identifying areas of improvement, not only to decrease drill days but ultimately maximize value for every dollar we invest. On the completion front, during the first nine months of 2018, we turned-to-sales 15 gross wells, including 14 Woodford and one Sycamore well with a stimulated lateral length of 7,750 feet, while running one completion crew throughout the year, we averaged 3.82 stages per day and completed 426 stages in total. Production during the quarter averaged 274.6 million cubic feet equivalent per day, an increase of 11% quarter-over-quarter and 41% year-over-year. Alongside earnings yesterday evening, we provided both initial and longer-dated production results on several Woodford wells, as well as our Upper Sycamore well, which I'll touch on further in a moment. And as you can see, we continue to see great results from the Woodford well set and remain very encouraged as we gain additional longer-term production history on a larger set of wells. During 2018, we shifted our program to largely focus on full section development in the SCOOP, both in the drilling and completion phase of the operation, allowing us to realize cost efficiencies, maximize fracture complexity, and have efficient resource recovery. Full section development allows us to take our learnings from the initial well and apply those to the remainder of the well set in the section. Optimization of the well design, casing requirements, tool selection, are all were fine with every well we drill, driving performance increases and decreasing days well over well. Observing the completion results, wells completed within the full section regime are yielding very strong results, benefiting from increased wellbore connectivity achieved during simultaneous completions. Our learnings to date have led us to adjust our completion activity in the SCOOP, moving a few of the anticipated turn-in-lines expected late in the fourth quarter to early 2019, when we estimate drilling to be completed within the section and the completion of these wells can occur simultaneously. With regard to exploration activity, during the third quarter, we turned-to-sales our Miller 8 well targeting the Upper Sycamore formation. While the well is still in the very early days of production, it has a strong liquids cut, producing approximately 46% oil on a two-stream basis and 63% liquids on a three-stream basis confirming our expectation of the Upper Sycamore's potential for being a more liquids-rich resource. We look forward to gaining more production history on the well and as we plan for additional Sycamore development in 2019, we are focused on the optimal development scheme for resource recovery both in terms of density and timing of the development with respect to all producing horizons in the formation. As a reminder, during 2017, Gulfport co-developed our Serenity well targeting the Lower Sycamore solid formation in conjunction with our Winham well targeting the Woodford, with the goal of receiving early indication of what co-development could potentially look like across these two horizons. While it is still early in the long-term development of these wells, we have seen outstanding results. After roughly 300 days online, the Serenity and Winham wells continue to outperform the type curve on a daily basis. And when normalizing to the Woodford wet gas type curve, the Serenity has cumulatively produced approximately 80% above the type curve after 300 days online. And the Winham is well over 100% above the type curve since turning to sales, proving there is a significant amount of resource in place and the co-development of these zones provides strong results. As we plan for 2019, we're including the Sycamore into our development plan in a more meaningful way and currently plan to co-develop a unit as part of our 2019 program, targeting multiple producing horizons in the play, the Woodford, Lower Sycamore solid and Upper Sycamore shale at the same time. In summary, we've learned a lot over the last year-and-a-half, but we still have more to learn. We're very excited with the results to date out of the play, and it's no longer a question of if we have the resource, but now how do we get the most out of it, maximizing our recoveries and value across the play. With that, I will turn the call over to Keri for her comments.

Thank you, Donnie, and good morning all. Gulfport's third quarter production came in ahead of expectations, and as Donnie mentioned, was driven by the continued strong performance of the existing asset base, turn-in-lines in both our core asset areas and increased ethane recovery. Production averaged 1.43 billion cubic feet of gas equivalent per day and consisted of 89% natural gas, 8% natural gas liquids and 3% oil. Based on the 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 1.36 billion cubic feet per day to 1.37 billion cubic feet per day, an increase of approximately 25% over 2017. On the realizations front, during the first nine months of 2018, our realized natural gas price before the effect of hedges and including transportation costs settled $0.59 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 have narrowed our full-year guidance and we now forecast to average in the range of $0.58 per Mcf to $0.61 per Mcf below NYMEX settlement prices in 2018. During the first nine months of the year, before the effect of hedges, our realized oil price came in at $1.83 of WTI. Given the strength we've seen in oil pricing in all of our operating areas, we have updated our full-year guidance and now expect to realize approximately $1.75 to $2 of WTI during 2018. Our realized NGL price came in approximately 45% of WTI and we reiterate our expectation to realize 45% to 50% for NGLs during 2018. Our realized prices continue to be supported by our hedge position and during the first nine months of 2018, we realized a settlement gain of $0.03 per Mcfe. Maintaining a strategic hedging program is an important element, supporting the long-term development of our assets and we will opportunistically layer on additional hedges and basis swaps to provide line of sight to our realizations and cash flows. For the first nine months of 2018, our strong realized prices and hedge position resulted in adjusted oil and gas revenues of $1.05 billion, which is comprised of approximately 76% natural gas revenues and 24% liquids, including 13% natural gas liquids and 11% oil. In terms of cash operating expenses, our per unit operating expense, which includes LOE, production tax, midstream-gathering and processing, and G&A totaled $0.94 per Mcfe during the nine months ended September 30th, down 2% from the second quarter of 2018 and down 8% when compared to the full year of 2017. When coupled with our realized pricing uplift, we expanded our adjusted EBITDA and generated approximately $700.3 million of EBITDA during the first nine months of 2018. As previously mentioned, we remain committed to our full-year 2018 total capital budget and forecast to invest approximately $815 million across our assets. Moving on to the balance sheet, as of September 30, 2018, Gulfport's net debt-to-EBITDA ratio decreased to 2.14 times and 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 be at or below 2 times. I will now turn the call back over for closing remarks.

Thank you, Keri. In closing, we continue to see outstanding performance from the resource base, exceeding our production estimates and increasing our 2018 production guidance while remaining dedicated to funding our 2018 activities within cash flow and spending within the range of our previously provided guidance. As we exit 2018 and head into 2019, we are committed to sustainable cash flow discipline as we allocate capital. As we've highlighted in the past several quarters funded entirely within cash flow at current strip prices, we were able to generate low double-digit growth in 2019. This program is supported by the tremendous assets in our portfolio, which only require investment of approximately $500 million in maintenance capital mode, which yield significant free cash flow at current strip prices and providing meaningful growth capital to be reinvested across our low-cost resource base. As we consider our plans for 2019 and beyond, Gulfport's investment of future cash flow, whether into the assets, returning cash to shareholders, or debt repayment may vary over time, but will be underpinned by disciplined thoughtful allocation process centered around recognizing the most value with every dollar invested. This concludes our prepared remarks. Now as I'm sure you can appreciate you're the first of many stakeholders we're touching base with today. With the time we have left for questions, I'd like to focus on our results and our business. As a team, we're moving forward and that's what we're focused on. Operator, please open the phone lines for questions from the participants.

Thank you [Operator Instructions]. Our first question is from Neal Dingmann from SunTrust. Please go ahead.

Donnie, my first question, you've referenced it just at the end that Utica certainly is a great cash flow vehicle. I'm wondering when you look at for '19, do you plan to use this more as a cash flow vehicle to grow the SCOOP or you'll grow the Utica sort of independently also?

I mean, that is a great benefit of having such a resource, such an asset like the Utica continues to deliver day in and day out for us. As we go into '19 that's definitely an option for us as we've always talked about continuing to shift more and more of our capital over toward the SCOOP. I think '19 with the DUC inventory, I mentioned as well, the 55 DUCs, it's a little different dynamic as we began to bring that inventory back down to more of a working inventory for us, but yes great option for us, and definitely on the table.

And then when you look at the SCOOP, could you talk a little bit about more just from a higher level, how -- I know, since you've been there when you are looking at the SCOOP, the cost, and sort of the results you're seeing. I know you did that one test here just recently on more of the Sycamore, but just more the SCOOP, I guess, would for some of the more common results. Could you talk about cost and results and what you anticipate maybe changing for '19?

I mean as far as performance results from the well set, from the resources sale, from a -- we continue to see just outstanding results there, very excited about that. As we've talked every quarter about our efficiencies that we're gaining on the drilling and completion side, we've continued to see that well after well. I mentioned a little bit on my prepared remarks about the things we see in more of a development mode going from the first well to that eighth well or whatever in a section and the learnings we get and the improvements we see across that well set. So, as also mentioned, going into '19, we're looking at more co-development and in that co-development, you start getting efficiencies, again that we're seeing in drilling, but now in our completions as well as the things that we don't talk about a lot with our facilities and infrastructure. So yes, efficiencies cost will continue to go down, as we get into co-development next year and excited to see that play out.

Our next question is from Jason Wangler from Imperial Capital. Please go ahead.

Maybe taking Neal's question a little further, just was curious with the results that you've had in the Sycamore so far looks pretty good. What's that balance that you're thinking as you look at '19, maybe in a percentage of how many wells you kind of target, the Woodford versus the Sycamore, or how should we think about kind of the activity specifically in there given the results you've seen so far?

Yeah, great question, Jason. And yes, we are very excited about what we are seeing, whether it's the Lower Sycamore, the solid or what we just released on our Miller well and that's Upper Sycamore, and the liquids content there. So as we're thinking about, and I will get into percentages, but as we're thinking about 2019, co-development Upper Sycamore, Lower Sycamore, Woodford, we will have a test next year more of a cube type development in the section, testing all of those and again excited about each of those targets and what they're delivering for us.

Jason, as we think about next year that cube development Donnie mentioned, we feel like that's important, from an aerial extent perspective, we feel like the Sycamore is pretty well derisked both from our activity and others. Really we had already get some color on is that density components. And so with regard to 2019, while we're not giving specific percentages on activities within each zone, it will include some density work to understand that.

Maybe one more on that, if I could two. I mean the Woodford seems to be pretty well delineated across the entire acreage position. I mean how do you feel how far along as you were just saying Paul, do you feel the Sycamore, is it still some work to be done kind of the full extent of the acreage, or do you feel pretty good about it across the entire position?

Yeah, Jason this is Donnie. Yes, we feel good about this, Paul mentioned, now we're kind of focusing in on what's that density look like in more of a co-development of all those zones. So yeah, I mean as you said, the Woodford has had phenomenal results across the play, and we'll continue to work on that co-development and again looking at density.

Our next question is from Ron Mills from Johnson Rice. Please go ahead.

Just a follow-up on this co-development concept, Donnie, I think you mentioned the Serenity wells running 80% above your type curve, your Winham wells are 100%. I know in terms of the Woodford, your Woodford wells are also running above type curve. Just curious of your thoughts in terms of what drove that level of outperformance in the Serenity and Winham. Do you think it's related to the co-development of the two zones and just getting a better connectivity? Just curious of what your thoughts are that have driven that co-development and I'm assuming that's what is leading you to do more of that next year.

Ron, I mean those are great wells, as you said and repeated, the number there, I mean, they are fantastic results. And yes, I do think that co-development, that fracture connectivity that we're doing there is really paying off for us, we're seeing it some in our Woodford as well across the board. So that's why we are moving in that direction. I mean, to me that's how you maximize efficient recovery in a resource play and that's where we're headed to now. So what's really exciting for us is now being able to layer in that Upper Sycamore onto that, and that's why we want to get a test in the ground pretty early next year, so we can really see what those results look like.

And then as it relates to the Upper Sycamore, I think the concept we are trying to prove was more oily, obviously, a strong proof of concept, but when you think about the Upper versus the Lower Sycamore, the 40-plus percent oil versus 11% oil between the upper and lower. And in terms of the initial deliverability of this Miller well, can you provide a little color in terms of what you're seeing versus what you may have hoped for? Is this in line or are you even potentially more encouraged than what you had hoped for?

When we went into this well to really prove up was that liquid content, we weren't looking for upbeat 24-type well, we want to prove up that liquid content we got it. We're very, very excited that we've done that and again ready to absorb, folding that into our program as we move forward.

And then lastly, just in terms of activity, you talked about 55 DUCs up in the Utica. I don't know if you really have many in the SCOOP, but it seems from the CapEx standpoint to keep yourself within the high-end, you may be pushing some activity from the fourth quarter into the first quarter. But when you think about activity that you had in 2018, is that a pretty good proxy in terms of what 2019 will look like, or what are your initial thoughts in terms of '19, in terms of how that activity ramps back-up once you get back to work? Thank you.

I'll touch on a couple of different places where you mentioned activity in the capital. And yeah, when you have 55 DUCs in inventory to continue to drill and add to that inventory for us in this quarter just really didn't make sense. We pushed that out. If you think about activity for next year, and we haven't come out, of course, with what our plan is, but more than likely, in both assets, we'll be starting up completion activity in the first of the year probably very similar to what we saw in the past year, drilling will continue on in the SCOOP, probably closer to the level we started this year with. And then, in the Utica, you're probably looking at starting a rig early sometime next year, one to two rigs, but again, we haven't finalized plans for next year, but that's kind of part of the things that are on the table for us.

Our next question is from Tim Rezvan from Oppenheimer. Please go ahead.

On the topic of Utica, economics in the wet gas part of the play are improving with stronger NGL and oil prices. I know you have about 50 DUCs, how nimble can you be in 2019 with the wet gas program? And what would you be looking for to actually make that move?

Obviously, we don't have the '19 plan out yet, but I can tell you that the current base case assumptions we're working from right now include us shifting some activity in the Utica back to the condensate/wet gas window side of things. As Donnie mentioned the activity there is going to be a little lower than it has been historically on the drilling side, and so that activity occurs and then probably starts actually showing up in terms of production, probably in the second half of the year. But look at, you're on point with regard to the economics in that window, things have shifted in its favor.

The mid-year maybe impact, I mean, then if I could just shift gears a bit, I know you're not here to talk about the CEO search. But I was curious if you could kind of, from an organizational point of view, Donnie maybe, in your conversations with the board kind of maybe from the organizational point of view on management level hires, cost inflation was a big issue for you all this year and there has been kind of budget overruns for a couple of years in a row. Can you speak to the board's thoughts on kind of on staffing and on the organization and what can be done to deliver a more disciplined budgeting process going forward?

Tim, I'll probably start off, later on to Paul to add some comments, but we've talked about that all year, and that has been a focus not only with our teams, but with the board and we're seeing continued improvement on that side. I mean our capital efficiency is, continues to get better. I'll point out the discipline part of it. I mean we're coming in toward that high-end of our range, which is not where we want to be, but to take the activity down and continue to manage that, have that commitment to it. I think, I said something for the progress we've made and are making and we'll continue to get better at that and excited about next year to see the fruits of it. So, Paul, if you want to add something to Tim.

Yes, Tim. I may add that the board and management are continuing to collaborate on the annual planning process there. I think it's probably worth noting that you know with Donnie at the helm, bringing his three decades of management across some large cap E&P companies, we view his fresh perspective as a tremendous positive and believe his deep expertise brings an advantage to us as we head into that budgeting process. I would also add that Donnie has built out a strong team here and working all closely together as we head into the end of the year and very focused on putting together a good plan that can be delivered upon.

Our next question is from Holly Stewart from Scotia Howard Weil. Please go ahead.

Maybe first, just a higher level question for Donnie. You talked a little bit about '19 and sort of activity levels starting off similar to '18 in terms of completions, you've got that slide in the deck on. I think it's slide 8 on just the cadence for '18. Should we expect something similar? And I think it's been like that the last few years where CapEx is very sort of front-end loaded.

I mean I think as we had kind of laid out at least what we've talked about over the past few quarters that's probably a similar type thinking. But again, it's just we haven't finalized that, you don't know what that back in looks like. 2019 is a lot different than we've had in the previous years, especially, as Paul mentioned earlier on the drilling side. With that DUC count, you're really not starting out with the number of rigs we had to start off with. So whether it's drilling or completion, I don't want to guide you one way or the other because you've got some options there that could make that look different to say. I mean those are very efficient economic wells in the DUCs and we're going to be leaning into those.

Holly, this is Paul. I'd also add, as we head into more of that full section development in the SCOOP, I think it probably knocked some of the cyclicality out of that spending too and that change occurs over time, but probably not immediately in 2019.

Okay, it's good color. Maybe just a couple for Ty on the realization side, it looks like the slide deck also has your NGL barrel changing a little bit. I'm assuming that's related to ethane recovery. So I guess the question is, first, is that the case and then is there any other things we should be thinking about like those barrel changes over the next couple of quarters.

So this quarter we did have the opportunities to cap a little bit more I think in both basins, both in the Utica and SCOOP. We thought we're putting into our gas streams, we had that opportunity and we took advantage of it and that's what you're seeing reflected in Slide 25. Going forward, ethane prices have come down quite a bit and we're continuing to look on a daily basis, definitely on trying to optimize the streams, whether that's all three, whether it's gas, NGLs or oil. And so we'll continue to do that and it's not just about -- with regard to ethane, it's not just about the frac spread, it's the other things, the factors we have to look at and put into play. And we've seen a nice rally in our gas prices. So we continue to optimize that and think that as we look into the rest of the year, the Slide 25 shows us we may get it a little bit early.

Well, maybe I'll ask this to -- that what are your recovery levels right now on the ethane side in each of those areas?

It's probably, liked I said, if you look at last quarter's, it's a mixed well, actually the mixture is probably best suited is showed in 25, we're trying to estimate for the year-end. So I mean, it's in that 25% to 30% across those two areas, it's brought down a little bit of the propane recoveries. But again, you should think of it as the overall barrels that we are recovering are higher. So -- I hope that helps.

Yes. And then maybe one -- just one last one from me on the realization for Nate (ph), it looks like that year-to-date it came and so far been at $0.59, you brought down the guidance. Maybe just kind of what you're seeing given all the projects that have come on here as of late and kind of how you're thinking about '19?

Yes, I think it's been a really good year for us, just like we were -- we've been waiting for this to come on with regards to pipeline, with regards to all of our FT commitments and then being ready to take advantage of some of the volatility that's come along with the pipelines. I think the numbers really highlight our midstream connectivity, our downstream portfolio and then really highlights the team that we have that daily looking at these decisions and making them for the benefit of the revenue stream. So, I have been really excited and proud of the team, and what they've accomplished thus far. And I think, if you look into '19, some of that continues to play out, there's still pipelines coming on, there's still low storage numbers, and I think there's good opportunity for us to continue to deliver same kind of results as we look into '19 and put that into the budget. So we're really excited on that side.

Thank you, Holly. Well, I want to thank you all for joining us this morning. 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.

And again, this concludes today's teleconference. You may disconnect your lines at this time. Thank you again for your participation.