Image source: The Motley Fool.
Earthstone Energy Inc (ESTE)
Q2Â 2019 Earnings Call
Aug. 07, 2019, 12:00 p.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good morning and welcome to Earthstone Energy's Conference Call. [Operator Instructions] A brief question-and-answer session will follow the formal presentation [Operator Instructions].
Joining us today from Earthstone are Robert Anderson, President; Mark Lumpkin, Executive Vice President and Chief Financial Officer; andd Scott Thelander, Vice President of Finance.
Mr. Thelander, you may begin.
Scott Thelander -- Vice President of Finance
Thank you and welcome to our second quarter conference call.
Before we get started, I would like to remind you that today's call will contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 as amended and Section 21E of the Securities Exchange Act of 1934 as amended. Although management believes these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in the earnings announcement we released yesterday and in our Annual Report on Form 10-K for 2018. These documents can be found in the Investors section of our website www.earthstoneenergy.com. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially.
This conference call also includes references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement released today. Also, please note, information recorded on this call speaks only as of today, August 7th, 2019. Thus, any time sensitive information may no longer be accurate at the time of any replay.
A replay of today's call will be available via webcast by going to the Investors section of Earthstone's website and also by telephone replay. You can find information about how to access those on our earnings announcement released yesterday. Today's call will begin with remarks from Robert Anderson, providing an overview of our second quarter accomplishments and a review of our operations; followed by remarks from Mark Lumpkin, regarding financial matters and performance; and concluding with remarks from Robert, regarding our current and upcoming operational plans.
I will now turn the call over to Robert.
Robert J. Anderson -- President
Thank you, Scott and welcome to everybody joining us this morning. I know it's been a pretty busy morning. In the second quarter, we again set new records for both adjusted EBITDAX and average daily production, with adjusted EBITDAX of approximately $33.6 million, driven by our highest quarterly production to-date of approximately 12,700 boe per day as production grew 13% sequentially from the first quarter of 2019. While we didn't bring any new wells on production during the second quarter, the three operator wells completed in the Midland Basin in the first quarter contributed to the strong growth.
As you might recall, in March, we achieved an average rate of approximately 13,400 boe per day. Therefore just a moderate decline going through the second quarter. Our wells are continuing to perform in line with expectations, with our first half reported production profile beating our own internal forecasts. We're proud to be generating peer leading operating margins with first and second quarter 2019 realizing adjusted EBITDAX per boe of $32.09 and $29.11, respectively.
We have a slide in our investor presentation which illustrates this peer benchmarking analysis for Q1 based on all-in unhedged cash margin with Earthstone coming in at $25.34 per boe, 30% above the peer average, of course, our strong hedge position is boosting those margins even further. Mark will walk you through pricing and hedges in more detail, but I'll just comment on natural gas prices. In the Permian which were negative for much of the second quarter. We were fortunate that we have our 2019 natural gas and basis nearly fully hedged and a net price after basis of approximately $1.70 per MMBtu. We have similar hedged prices in place for a meaningful portion of our gas volume forecasted in 2020 as well.
We have also been working on optimizing our capital program for 2019 and have made some enhancements that result in some guidance changes, which Mark will review in detail. We expect our revised capital program to result in bringing on 14 gross Midland Basin operated wells and 10 gross Eagle Ford operated wells from late in the third quarter through the end of the fourth quarter. We'll also spud an additional five growth operator wells with this capex. Based on both well performance year-to-date and our revised capital program, we now expect an exit rate of 14,000 boe to 15,000 boe per day. Between our updated 2019 exit rate expectations and the approximately $50 million estimated 2019 capital expenditures that will have very minimal impact on our 2019 sales volumes, we will be very well positioned to begin 2020 with strong production.
In July, we closed a wellbore development agreement, or what you all might call a DrillCo arrangement with an industry partner that covers an 8 well program in 2019 on our central Reagan County assets, with an option for up to 11 additional wells next year. This agreement is structured as a wellbore only agreement and the DrillCo partner does not earn any acreage, but they will earn 35% of the working interest in these wells by paying a higher portion of the capital cost. The DrillCo will enhance our drilling economics and provide greater optionality in our future drilling plans as we meet our limited drilling obligations on an accelerated basis.
To support our capital program including the DrillCo, we've secured a second rig and are currently running two rigs on a temporary basis in the Midland Basin. We contracted a top performing high spec rig with enhanced pump capacity at a similar day rate as the rig we have been running over the last two years in the Midland Basin and which we plan to release later this quarter. With the upgraded equipment and crews, we expect the high spec rig to operate more efficiently, resulting in fewer drilling days per well. Thus we expect well cost reductions as a result of the new rig and associated services. I will give some details later on the positive results we're already seeing with this new rig which we deployed in June.
We have increased our activity in the Eagle Ford where drilling is under way on a 7 well program on our Pen Ranch project and we will then continue on to drill three wells on our Davis Project. We expect to start completion activity in the Eagle Ford in the third quarter and to complete all 10 Eagle Ford wells by year end. These 10 wells largely complete our -- our anticipated Eagle Ford development activity and we currently expect to focus 100% of our 2020 capital program in the Midland Basin.
I'll turn the call over to Mark to provide more details on our new guidance and financial results, and then I'll review a few operational items.
Mark Lumpkin -- Executive Vice President & Chief Financial Officer
Thank you, Robert. In view of the increased operating drilling and completion activities that Robert described and anticipation of lower non-operate activity, we're revising our 2019 capital budget to $205 million from previously $190 million, and this includes reallocating some of our spending from Midland Basin non-operated to operated drilling locations in both the Midland and Eagle Ford Basins. This revised budget assumes temporarily running two rigs in the Midland Basin until sometime around the end of the third quarter before dropping back to one rig, and it also assumes completing a 10-gross well program in the Eagle Ford.
We're raising our average daily production guidance for 2019 to a range of 11,250 barrels of oil equivalent per day to 12,250 barrels of oil equivalent per day from our previous guidance of 11,000 barrels of oil equivalent per day to 12,000 barrels of oil equivalent per day. This was largely due to well performance to-date and really is driven by added capital expenditures. We've not made any changes to our guidance on our 2019 production mix which we still expect to be around 65% oil, 19% NGLs and 16% natural gas.
As Robert mentioned with our revised capital plans for the balance of the year, our internal expectations for how we end the year and begin 2020 are now significantly higher. With 14 of our anticipated 17 gross Midland Basin operated wells and all 10 of our gross Eagle Ford wells expected to be online from sometime in the later part of the September through the end of the year, we do expect to achieve meaningfully higher production volumes at year-end 2019 and in the first quarter of 2020 than we previously expected. We've now put out new guidance on 2019 exit rate of 14,000 barrels of oil equivalent per day to 15,000 barrels of oil equivalent per day which is a significant increase versus our prior internal forecast.
In terms of the incremental $15 million of capital expenditures on a revised budget that won't really impact 2019 production volumes given the timing, we do expect an incremental approximately 1.4 net wells online and an incremental approximately 4.8 net wells spud which will largely be DUCs all by year end. This feeds into our increased expectations for production growth in 2020 as we now expect to significantly higher year-over-year percentage increase in volumes in 2020 on a one-rig Midland program versus the percentage increase we're likely to achieve in 2019.
Now let me turn over to our financial metrics for the second quarter. Our sales revenue was $44.5 million compared to $37.2 million in the second quarter of 2018, and $40.7 million in the first quarter of 2019. This top line growth was driven primarily by higher sales volumes which averaged 12,699 barrels of oil equivalent per day, representing 13% growth compared to the first quarter and by higher oil prices. Crude oil sales contributed $40.8 million or 19% -- 92% of total revenues, and our production mixture in the second quarter was 61% oil, 21% NGL with the remainder natural gas. We realized higher oil prices in the second quarter averaging $57.92 per barrel of oil, before realized gain on derivatives, due in part by continued improvement in the differentials in the Midland Basin compared to $50.30 before realized gains on derivatives in the first quarter.
On the natural gas side, a combination of weak index prices and wide negative differentials on our Midland Basin gas for much of the quarter resulted in average natural gas price before the impact of realized gains on derivatives of approximately $0.10 per Mcf, which compares to approximately $1.32 per Mcf in the first quarter. On a similar note, weakness in NGL pricing resulted in an average price of $14.90 per barrel in the second quarter versus $21.66 per barrel in the first quarter. All told, this resulted in realizations in the second quarter for oil, NGL and natural gas of about 97%, 25% and 4% of NYMEX respectively compared to the first quarter of averages of approximately 95%, 39% and 42% of NYMEX.
We have continued to benefit from a strong hedge book in 2019 with realized gains in the second quarter of $4.6 million, which brings our realized commodity hedge gains for the year to approximately $10 million.
Our hedge position remain strong with hedges for 2019 equating to approximately 82% and 83% of our production guidance for oil and natural gas, and we also continued to moderately add to our oil hedged position with incremental swaps in 2020, which are currently at an average price including differentials of over $60 per barrels and have initiated the moderate level hedges for 2021 at an average price including Midland Basin basis hedges of near $56 per barrel. Similarly we're well hedged through 2020 on the natural gas side on both the underlying commodity and on WAHA. For full details of our current hedge position, please reference our investor presentation.
We achieved the Company record quarterly adjusted EBITDAX level in the second quarter of $33.6 million, which was a sequential increase of 4% from the $32.4 million in the first quarter and up 64% from the same period last year. From an income standpoint, we recorded adjusted net income in the second quarter of $14.9 million or $0.23 per diluted share.
Now looking at our expenses. Our lease operating expense came in higher than our forecast but was partially offset by a lower than forecasted cash G&A expense. LOE per boe averaged $7.44 in the second quarter compared to $6.61 in the first quarter. Workover spent has been the primary driver of our elevated -- of our elevated LOE, some of that work was strategic to boost production at low incremental cost, but a large portion of the workover cost was related to frac heads on our producing wells. We have also experienced increased LOE for saltwater disposal as some frac heads have caused increased water production for a period of time.
As a result of what we have reported in the first half, we're now projecting for the balance of the year. We have revised our guidance for lease operating expenses to be in the range of $6.25 to $6.75 per boe or $1 increase over our previous guidance. We expect to be able to further improve our LOE unit cost in the second half, particularly in the fourth quarter and are aiming to achieve continued LOE unit cost improvements into 2020.
Our cash G&A expense per boe averaged $4.13 in the second quarter compared to $5.01 per boe in the first quarter. We continue to manage our G&A tightly and with total G&A below our internal forecast in the first half and with G&A per boe of $4.54 in the first half tracking below our full year guidance. We're also reducing our guidance on the cash G&A to a range of $4.50 to $5 per boe for the full year, which is a $0.50 decrease versus our prior guidance.
We reported net income for the second quarter of 2019 of $19.5 million compared to a loss of $38.4 million in the first quarter and net income of $1.5 million in the second quarter of last year. As described in previous calls, GAAP requires us to disclose the amount of net loss or income associated with the controlling interest which essentially reflects our Class A shares. Accordingly from a GAAP perspective, we reported net income attributable to Earthstone Energy, Inc., of $8.8 million or $0.30 per diluted share compared to a net loss of $17.2 million or $0.60 per diluted share in the first quarter of 2019, and compared to $650,000 of net income or $0.02 per diluted share in the second quarter of 2018. You can also refer to today's earning release and our 10-Q for further information.
Lastly, let's move over to the balance sheet and liquidity. At June 30th, 2019, we had outstanding borrowings in our credit facility of $110 million and a cash balance of approximately $5.8 million. We currently have $215 million of undrawn capacity on our borrowing base facility for total liquidity of approximately $221 million at quarter end. So our liquidity continues to remain strong.
I will now turn the call back over to Robert for more discussion on our operating activity.
Robert J. Anderson -- President
Thanks Mark. Our 2019 drilling program is continuing to perform well based on production performance from the first half of the year and our ongoing focus to safe and efficient operations. We currently have two rigs running in the Midland Basin, one of which will be released before the end of the third quarter as I've already mentioned, as well as our one rig in the Eagle Ford shale which will be released prior to the end of the year as we finish up our 10-well drilling program there.
Late in the second quarter, we completed the drilling of our five-well Mid-States project in Midland County. We have a 67% working interest in these wells, which have approximately 10,000 foot lateral sections targeting the Wolfcamp A and B intervals. We have started completions on these wells and expect to have them online around the end of September. The completions are progressing on schedule as we just wrapped up around 180 successful stages on the first three wells and are fracking the last two wells now.
Our frac efficiency continues to average about 8 to 10 stages per day with cost similar to earlier in the year. We expect to maintain this frac crew and related services completing wells from now through November. We moved the legacy rig drilling up in the Mid-States block to our Block 1 bolt-on area in central Reagan County, where we are just finishing up drilling on a two-well pad, targeting the Wolfcamp B upper, and then after that, we'll move it to a two-well pad targeting the Wolfcamp A in the same project area. All four of these wells are approximately 10,000 foot laterals and we will have a 65% working interest after giving effect to our DrillCo agreement. After drilling the second two-well pad, we expect to release this rig.
Utilizing the new high spec rig, we recently drilled a three-well pad in our TSRH unit in record time. We drilled approximately 60,400 feet a hole in 46 days. The wells average a lateral length of approximately 12,000 feet. We had several days with more than 3,500 feet of lateral drilled, which sets new records for our drilling team. These three wells are also included in our DrillCo and we have a 65% working interest. As mentioned on our last earnings call, these TSRH wells are spaced about 1,100 feet apart in the same landing zone or about 550-feet between wells. They are significant distance from existing producers on our TSRH block and will aid us in assessing the optimum spacing for this area.
From a non-op standpoint, we're participating in a 15-well project on the Martin and Midland County line, targeting five different zones in the Spraberry and Wolfcamp. We have about 20.5% working interest and expected net capex of approximately $29 million through completion. The current expected timing on completions on this project is largely in the first quarter of 2020 versus our prior plan that completions would occur before the end of the year which has resulted in a shift of capital from 2019 to 2020 for this component of our budget.
To spent a moment or two highlighting well performance, the strong results of our new wells and the continued performance of our base production all contributed to our record second quarter production. Our Upton County wells that were completed in the first quarter are producing below the 1 million barrel equivalent type curve but still with very attractive economics. I will remind you that these type curves are based on our own well data set and cover various acreage positions as well as different targets from Midland and Upton counties. As our well population increases in Upton County, we'll break out type curves by County specifically. For context, the Upton County wells in 2019 have a similar estimated -- oil recovery as Reagan County, but have a 71% oil component and start out at higher rates and therefore ultimately generate better economics.
Lastly, we continue to focus our -- we continue to focus on enhancing our operating margins, managing our leverage and the efficient execution of our capital program.
Operator, with that, we'll now turn it over for questions.
Questions and Answers:
Operator
Thank you. [Operator Instructions] Our first question comes from the line of Neal Dingmann with SunTrust Robinson Humphrey. Please proceed with your question.
Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst
Good morning, Robert and team. Nice quarter. So Robert my question is around the DrillCo, what sort of sparked that, I guess, let's just start there and are there other DrillCo opportunities?
Robert J. Anderson -- President
At this time we're not really exploring any other DrillCo opportunities and what sparked that is, this is kind of status MO for us, that we've always done these kind of things when we want to either accelerate, obligation drilling and get that HBP status behind us or also earn a little better economics in a particular area, because we're bringing them in a small promote. And then lastly, be able to extend our capital to the highest rate of return projects in our portfolio. So I think all of those things make good sense for us.
Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst
No, they didn't [Phonetic]. And could you tie one of these, if you saw, I guess, my thought is given for the rational market if acquisitions end up being fairly reasonable out there, could you tie one of these into an acquisition to make it even more -- accretive more quickly?
Robert J. Anderson -- President
Sure. We -- as you know, we're open to looking at a lot of different arrangements when we look at acquisitions and bringing in a partner to facilitate something, you know in an area is something we always consider.
Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst
Okay. And then lastly if I could just on, looking at sort of trajectory. It looks you got quite a bit of activity to end the year and then the next year and then without realizing you don't have 2020 out. Could you remark, just maybe talk about how you see trajectory and what you see in things, sort of kind of comparable to what they are now and just flowing into 2020 or what you see it seems like you're having a pretty good balance now?
Robert J. Anderson -- President
Yeah, let me take the first step with that one Neal. First of all, I think, people do recognize but I'll just highlight this anyways. We haven't brought a well line since March. So we -- in fact, we've been in a natural decline from March really through probably late September, and the way we've been thinking about things, we do expect to get these Mid-States wells online late in September, but it's going to have a very minor contribution to third quarter production. So essentially, we're on a decline until those wells come online. And again, we brought three wells online on a gross basis in the Midland Basin, all in the first quarter, and we'll bring 14 gross wells online in the Midland Basin from the very end of the third quarter through the end of the fourth quarter. In addition to that, 10 gross wells online in the fourth quarter in the Eagle Ford. So, obviously, we said before our capex program was very back-end weighted. From a production standpoint, we're at 13,400 barrels a day in March and that held up pretty good starting up the quarter and then there's been a natural decline and we ended up at 12,7000 barrels. We think that number is definitely going to be turning down a decent bet in the third quarter and we'd expect the third quarter to be our lowest volume in terms of production number for sure. Probably, a 10 handle or maybe even low 10's is kind of how we're thinking of it. And that of course depends a little bit on, do we get a week or two of Mid-States productions or is there not really any significant production from the Mid-States pad.
But as you think should about the fourth quarter and that should give you some kind of weighted back-end of how we're thinking about third quarter versus fourth quarter. If you think about the fourth quarter, we've really got wells coming online all throughout the quarter and some of the -- providing the exit rate guidance was to communicate that our expectations have changed and we've recognized that we've not put out exit rate guidance before, but we think it should help, give folks a bit of marker for how we expect to start the year out. I think based on our current midpoint of our production guidance, we would be up 18% in 2019 over 2018, and we think running one rig next year will be a pretty significantly higher percentage growth from '19 to '20 versus what the midpoint of 2019 implies versus 2018.
Does that help, I mean, we're still [Speech Overlap]
Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst
Go ahead, Mark.
Mark Lumpkin -- Executive Vice President & Chief Financial Officer
We're still going to have a pretty decent better completion activity into the first quarter, both as we've got probably some operated DUCs, but really some of the completion activity, if you can probably piece this together from looking our old and new guidance, has gotten pushed out on the non-op Midland Basin into really the first quarter of next year, that will be kind of non-op DUCs that get completed likely sometime in the first quarter and will continue to kind of help us crank out some pretty nice new volumes. And again, I think, big picture hopefully that gives some color on kind of how we're thinking of things versus how we're thinking, I think, probably last quarter.
Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst
No, it helps. Exit helps as well. Thank you.
Operator
Thank you. Our next question comes from the line of Brad Heffern with RBC Capital Markets. Please proceed with your question.
Brad Heffern -- RBC Capital Markets -- Analyst
Hey, good morning, everyone. You guys talked about -- in the second quarter the well performance was better than what you projected internally. I'm curious if the new guide fully incorporates that for both the legacy wells, the base production and if it incorporates it for new wells or if that's still remaining upside?
Robert J. Anderson -- President
No, we've got everything incorporated. We run a model everyday, I think, Scott's doing something, but we've updated for our mid-year internal reserve report, and it's got all that reforecasting built into it.
Mark Lumpkin -- Executive Vice President & Chief Financial Officer
Brad, I mean, the one thing I would add there is, like as we look at what's happened year-to-date, I mean, not just the second quarter but including the first quarter, our oil volumes on our PDP and including kind of the three wells you brought on the first quarter, they are definitely above our curves. And what we've seen happen is some moderate improvement or outperformance on the oil side and then the gas and NGL side has been just well in excess of that in terms of incremental volumes versus our projections. We kind of adjusted for that. We still think we're going to end up the year about 65% oil. In the third quarter, we definitely would expect that to tick down even below the 61% we have in the second quarter. But as we get a bunch of new volumes online with higher oil content in late third quarter and fourth quarter, we expect to get around that 65%.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay, got it. And then you guys talked about no Eagle Ford activity in 2020. Is that the plan sort of in perpetuity and can you remind where we stand on the HPP there and if you would just let the remaining acreage go?
Robert J. Anderson -- President
We wouldn't let it go and it's subject to a lot of things. There's some activity in and around our Northern block of acreage and we're watching that to see, what latest frac techniques and designs, how they impact results and then commodity prices. So right now as we look out to 2020, we're not planning to spend any Eagle Ford capital, but if oil prices improve and these new wells perform like we hope they would, then we could spend a little capital up there, but again, it would be very minimal amount of capital compared to our overall program for 2020.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay and then finally I'll just ask the requisite M&A question. You guys have obviously done the DrillCo here. But are there any deals out there that you're seeing or how does the deal flow look? I mean you guys are always trying to add.
Robert J. Anderson -- President
We all -- we are always trying to add, I'd say, it's probably more than frozen at the moment. It's just the whole macro environment and it has created a situation that there just isn't a lot of deal flow at the moment. So we're knocking on doors, creating as much discussions as we can about opportunities, we'll continue to do so.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay. Appreciate it.
Operator
Thank you. Our next question comes from line of Duncan McIntosh with Johnson Rice & Company. Please proceed with your question.
Duncan McIntosh -- Johnson Rice & Company -- Analyst
Hey, good morning, Robert.
Robert J. Anderson -- President
Hey, Duncan.
Duncan McIntosh -- Johnson Rice & Company -- Analyst
Looking at the -- you're running two rigs in the third quarter and then dropping your legacy rig. I was wondering if you could provide some color around the efficiencies. You kind of expect with the new higher spec rig.
Robert J. Anderson -- President
Well, we had a -- we were off to a really good start when we drilled this three-well pad, because it was using that high spec rig. And from amount of footage per day, kind of, thing on average, if you want to look at that way, it's been very successful implementing that rig. We're seeing some cost savings. I'm holding those numbers for a quarter and then hopefully we'll be able to give you some real live actual data on how much savings we're seeing by using this rig, but we do expect to have a savings over the prior rig and maybe even that will translate into ultimately how much capital we end up spending this year. So I hope that we can spend less than what the guidance is of $205 million.
Duncan McIntosh -- Johnson Rice & Company -- Analyst
All right, great. And my other questions are already answered. Thank you all.
Robert J. Anderson -- President
Appreciate it.
Operator
Thank you. Our next question comes from the line of John White with ROTH Capital Partners. Please proceed with your question.
John White -- ROTH Capital Partners -- Analyst
Good morning, guys, and very strong quarter. It looks like everything's running just the way you want it to.
Robert J. Anderson -- President
Thank you, John. Almost everything John.
John White -- ROTH Capital Partners -- Analyst
I know. There is always something else, right. On the non-operated Midland -- on your capex, your non-operated Midland there was a large decline there, is that due to companies withdrawing previously proposed wells or from you opting out of wells you previously thought you would anticipate in?
Robert J. Anderson -- President
Neither, it's just the activity pace that these guys have. It just got shoved out a little bit. So we're really just going to shift all of that activity into 2020. We're still participating in the same 20 wells that we had from the beginning of the year, it's just not getting completed as fast.
John White -- ROTH Capital Partners -- Analyst
All right. Well proposals that were deferred?
Robert J. Anderson -- President
They're not even deferred. They're just -- things are taking a little longer in the field. In one area, where they thought they were going to run multiple rigs on this 15-well program, they're running less rigs on it than they had planned.
Mark Lumpkin -- Executive Vice President & Chief Financial Officer
Yeah, John, we expect to get the same number of wells spud on a gross-to-net basis on the non-op, but the completions are effectively getting kind of push in to the earlier part of 2020.
John White -- ROTH Capital Partners -- Analyst
All right. Thanks for the detail.
Operator
Thank you. Our next question comes from line of Mike Kelly with Seaport Global Securities. Please proceed with your question.
Michael Kelly -- Seaport Global Securities -- Analyst
Hi, guys. Good morning. First off, I guess I'm glad to hear that you had given those exit rate numbers before, I was driving myself nuts last night trying to do -- trying to find those numbers. Glad I'm not crazy. But the question I really had I was curious if you could give us a little bit more details around this DrillCo, just what the security looks like and then I'm also curious on when this party has to say kind of yay or nay on their election to drill the wells with you in 2020? Thanks.
Robert J. Anderson -- President
Mike, some of this is a secret sauce that we probably aren't going to deliver. So I won't -- I'll probably drive you crazy, because I'm not going to give you a very straight answer. I'll just tell you that we're paying a little less than what our working interest is on the well. So there's a little bit of promote built in there, which is quite typical in these kind of deals. And as we get to 2020 and have results on our 2019 program, we will propose wells and they'll have an option to participate or not participate. It's pretty darn simple from that standpoint.
Michael Kelly -- Seaport Global Securities -- Analyst
Got it. So are you thinking about this, Robert, if -- is this kind of how you want to ultimately run two rigs as to how somebody come in and help kind of shoulder that capex burden or -- I'm just kind of curious if they say, no, would you think about going two rigs alone next year? How does that play our if they say yes or no?
Robert J. Anderson -- President
It's a good question, and we've thought a lot about it around here. And I think a couple of things are going to happen. One is, we're going to wait till we see what the environment looks like toward the end of the year and how these guys respond to the results we have on these wells. One thing is for sure is, I think we're going to have improved economics just on a gross basis because our drilling times are less. So our capital is going to be a little bit less than those wells and I think that will satisfy them to want to participate next year. But if oil prices tank then maybe both of us want to, kind of, delay or defer things or spread things out as much as possible. So again, the two rig program versus a one rig program isn't based on whether the DrillCo participates or not. I think there's some other things that will drive part of that decision as well.
Michael Kelly -- Seaport Global Securities -- Analyst
Got it. Understood. Thank guys.
Operator
[Operator Instructions]. Our next question comes from line of Jason Wangler with Imperial Capital. Please proceed with your question.
Jason Wangler -- Imperial Capital -- Analyst
Hey, good morning. Just maybe to dovetail on Mike's question. On the next year's wells, is that a well-by-well basis or is there a demarcation where they have to accept all 11 or 9?
Robert J. Anderson -- President
It's not a well-by-well basis and it's not all 11 at once. It's basically by a pad, Jason. So we don't want them to cherry-pick a horizon but they can sort of decide in or out on a pad basis.
Jason Wangler -- Imperial Capital -- Analyst
Okay, that's kind of what I was curious. And then it sounds like the wells for this year are pretty much already -- or the pads are already picked then, so you kind of know where you're going for the rest of this year with them?
Robert J. Anderson -- President
You see, yeah, we're done. I mean, we've talked about every well in some form or fashion that they're in this year for those eight-well. So yeah, and they're in all eight of those.
Jason Wangler -- Imperial Capital -- Analyst
Perfect. Thank you very much.
Robert J. Anderson -- President
Thanks.
Operator
Thank you. Ladies and gentlemen, this concludes our question-and-answer session. I'll turn the floor back to Mr. Anderson for any final comments.
Robert J. Anderson -- President
Thanks all. We appreciate your interest and have a great day.
Operator
[Operator Closing Remarks].
Duration: 38 minutes
Call participants:
Scott Thelander -- Vice President of Finance
Robert J. Anderson -- President
Mark Lumpkin -- Executive Vice President & Chief Financial Officer
Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst
Brad Heffern -- RBC Capital Markets -- Analyst
Duncan McIntosh -- Johnson Rice & Company -- Analyst
John White -- ROTH Capital Partners -- Analyst
Michael Kelly -- Seaport Global Securities -- Analyst
Jason Wangler -- Imperial Capital -- Analyst
Transcript powered by AlphaStreet
This article is a transcript of this conference call produced for The Motley Fool. While we strive for our Foolish Best, there may be errors, omissions, or inaccuracies in this transcript. As with all our articles, The Motley Fool does not assume any responsibility for your use of this content, and we strongly encourage you to do your own research, including listening to the call yourself and reading the company's SEC filings. Please see our Terms and Conditions for additional details, including our Obligatory Capitalized Disclaimers of Liability.
