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Earthstone Energy Inc (ESTE)
Q1Â 2019 Earnings Call
May. 06, 2019, 11:00 a.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) As a reminder, this conference is being recorded. Joining us today from Earthstone are Frank Lodzinski, Chief Executive Officer; Robert Anderson, President; Mark Lumpkin, Executive Vice President and Chief Financial Officer; and Scott Thelander, Vice President of Finance.
Thank you Mr. Thelander, you may begin.
Scott Thelander -- Vice President of Finance
Thank you, and welcome to our first 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 today and in our quarterly report on Form 10-Q for the first quarter of 2019 and 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. The 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, May 6, 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 today.
Today's call will begin with remarks from Frank, providing an overview of our first quarter accomplishment and our future plans, followed by remarks from Mark regarding financial matters and performance and concluding with remarks from Robert regarding our operations.
I'll now turn the call over to Frank.
Frank A. Lodzinski -- Chief Executive Officer
Okay. Well, thank you Scott and welcome to everybody for joining our call this morning. We've have had a great start to the year with solid financial and operating results. We continue to run one rig in the Midland Basin and that program is essentially on track and allowed us to achieve record average daily production of just over 11,200 BOE a day during the first quarter.
We also achieved record adjusted EBITDAX of over $32 million, we continue to focus on operating efficiently and effectively using our capital to grow profitably. Right now we are successfully accomplishing these objectives with a drill bit. Our high quality acreage position provide us substantial inventory of drilling projects that generate attractive rates of return and our operation team is doing an excellent job of extracting that value efficiently.
We have also been able to maintain a very strong balance sheet and we have a proven expertise to find, evaluate and negotiate successful growth transactions. That combination of strategic options gives us the flexibility to remain disciplined about our growth strategy. I will now turn the call over to Mark for brief overview of our financial situation.
Mark Lumpkin -- Executive Vice President and Chief Financial Officer
Thank you, Frank. Before we began, please keep in mind that we did provide 2019, guidance in January and we are not making any changes to our guidance. So, looking at our financial metric for the first quarter and starting with the top-line, sales revenues of $40.7 million was essentially flat compared to both the first quarter 2018 and the fourth quarter 2018.
We saw average daily sales volumes of a record 11,209 barrels of oil equivalent per day representing 7% growth compared to the fourth quarter. The higher volumes were largely offset by lower realized prices, which decreased by 6% versus the fourth quarter. Despite a lower commodity price realization in the first quarter, the later part of this quarter and the second quarter to date have been significantly improved on the oil price side. On top of this, the significant discount we are receiving on oil base on the Midland to cushion (ph) differentials has improved significantly with Earthstone's realized prices in the first quarter on a total Company basis, equivalent to 95% of NYMEX compared to 86% and 90% respectively in the third and fourth quarter of last year. Further, we ended the quarter with realizations in March that were 99% of NYMEX.
Our production mix during the first quarter was 67% oil and 19% NGLs with natural gas making up the balance. We continue to estimate that our 2019 mix will be about 65% oil, 19% NGLs and 16% natural gas. Adjusted EBITDAX was a record $32.4 million in the first quarter of 2019, up 35% from the $23.9 million we recorded in the fourth quarter 2018 and up 28% from the $25.3 million in the first quarter of 2018. Lease operating expense per barrel of oil equivalent averaged $6.61 in the first quarter of 2019 compared to $6.25 per BOE in the fourth quarter 2018 and compared to $5.35 per BOE in the first quarter of 2018, while LOE per BOE averaged $5.66 for the full year 2018 and while we still expect to average between $5.25 and $5.75 cents for 2019. Our LOE per BOE has been relatively high over the past two quarters due to a work over program that we initiated late in 2018. Robert will reference further, but we expect the recent work over program to result in greater production and longer run times.
In the first quarter our recurring LOE was $5.27 per BOE and work over expense accounted for $1.34 per BOE. Our G&A expense excluding stock-based compensation in the first quarter was approximately $5.1 million compared to approximately $7.8 million in the fourth quarter 2018 and $4.6 million in the first quarter of 2018. Our G&A per BOE, excluding stock based compensation, averaged $5.1 per BOE in the first quarter of 2019 compared to $8.12 per BOE in the fourth quarter of 2018 and $5.33 per BOE in the same period last year. This compares to our guidance of $5 to $5.50 per BOE. As discussed on our prior call, we're now accruing for cash bonuses on a quarterly basis and this should lead to smoother quarterly G&A expense versus what we reported last year. During the quarter we realized a $5.3 million net gain on our commodity price hedges. We also record an unrealized mark-to-market loss of (inaudible) million. Comparatively, in the fourth quarter 2018, we reported a $96.0 million unrealized gain on the mark-to-market of our hedges.
Largely as a result of this (inaudible) million of unrealized mark-to-market loss, we reported a net loss for the quarter of $38.4 million. As describing our previous earnings calls GAAP requires us to disclose the amount of net loss or income associated with a controlling interest, which will essentially reflects our class A shares. Accordingly, from a GAAP perspective, we reported a net loss attributable to Earthstone Energy, Inc. of $17.2 million or $0.60 per share compared to $36.1 million of net income or $1.26 per share in the fourth quarter of 2018. You can also refer to today's earnings release in our 10-Q for further information.
Now, let's move over to the balance sheet and liquidity. Last week the borrowing base under our revolving credit facility was reassured (ph) as scheduled and was increased by $50 million to $325 million. At March 31st, 2019, we had outstanding borrowings under our credit facility of $120.8 million and a cash balance of approximately $0.4 million. Adjusted for the recent increase in our borrowing base, we had $204.2 million of undrawn capacity for total liquidity of approximately $205 million at quarter end. So our liquidity continues to remain strong. From a hedging standpoint, we did benefit from our hedge in the first quarter with realized gains of $5.4 million and we continue to layer on hedges to reduce volatility of our cash flows and have added some additional hedges on 2020 oil volumes, in April as prices improved material from late last year and early this year.
Our hedge position remains strong with oil hedges in 2019 on approximately 84% of our guidance at $66 per barrel and a significant oil hedge positioned in 2020 at an average price of $65 per barrel. Further, we are similarly well hedged on the natural gas side and we have in place base different -- basis differential hedges for our oil and natural gas at approximately the same volumes as the hedges on our underlying oil and gas volumes. Our capital expenditures for the quarter totaled $42.7 million. As you know we've budgeted total 2019 expenditures of approximately $190 million and we do expect this to be more backend weighted.
So with that, I'll turn over to Robert for review operations.
Robert J. Anderson -- President
Thanks, Mark and good morning, everyone. As Frank highlighted we are pleased with our first quarter results. On average our well performance continues to be in line with or exceed our type curves providing further confidence in the quality of our acreage. Our 2019 drilling program is focused on the Midland Basin and specifically the Wolfcamp A and B zones, which have proven results across our acreage positions and we are not testing any new target zones this year.
As a reminder, we plan to spud 16 wells in 2019 and complete 13 of those. These wells are expected to demonstrate attractive well level economics and contribute to our growth in 2019. During the first quarter we completed three operated wells in the Midland Basin. In February, we completed our Malone 1-3 1A in the Wolfcamp A with an 11,206 foot lateral. We have an 89% working interest in this well located in central Reagan County and as is typical with Wolfcamp A wells in Reagan County, the Malone has taken some time to reach peak rates. However, after 75 days the well has a peak IP30 of 757 barrels of oil equivalent per day, 81% oil and is continuing to increase and is performing in line with our expectations.
In March, we completed two Ratliff wells in Upton County in which we have 100% working interest. They were drilled with an average lateral of 10,375 feet with one targeting the upper Wolfcamp B and the other targeting the lower Wolfcamp B intervals. These two wells are approximately 330 feet apart with the landing zones about 275 feet away from one another. The Wolfcamp B upper had a peak IP30 of 1,467 BOE per day, 94% oil, while the B lower well had a peak IP30 of 1,109 BOE per day, 91% oil. As a point of reference, the offsetting (inaudible) Wolfcamp B lower well we completed last September has a cumulative production of 176,000 barrels of oil equivalent in 180 days. So we are quite pleased with the results in this area. As we have previously mentioned during the quarter, we commenced drilling a five well program in Midland County on our Mid-States project in which we have a 67% working interest. These wells are targeting the Wolfcamp A and B intervals with 10,000 foot laterals.
Completion operations are expected to start in June and we should see production contributions from these five wells late in the third quarter. After completing drilling on our Mid-States wells, we plan to spend the remainder of our 2019 capital budget in central Reagan County, where we will start out on our three well TSRH pad, drilling two Wolfcamp B upper wells and a Wolfcamp B lower. These wells will be spaced about 1,100 feet apart in the same landing zone or about 550 feet between wells. These wells are a significant distance from existing producers on our TSRH Block and will aid in our assessment of spacing pattern parameters for this specific area.
We are also realizing value from our non-operated activity. During the first quarter we participated in two wells completed in Reagan County, in which we have a 50% working interest and one well completed in Howard County, where we have a 35% working interest. We are also participating in projects in various stages of drilling and completions across our position in Howard, Martin and Midland counties with interests ranging from 3% to 46%. Including in these wells will be a 15-well program drilling five different target zones made up of the Jo Mill, Lower Spraberry, Wolfcamp A and Wolfcamp B. Again an important data point for spacing parameters in this area.
As Mark mentioned in his discussion about LOE, we increased our workover program late last year and in the first quarter on both our Midland Basin and Eagle Ford assets in order to enhance our production and to intentionally reduce future downtime on a proactive basis. Items like adding equipment for our chemical treatment program and replacing tubing will increase our runtime. I would note that though LOE was high for the quarter at $6.61 per BOE, we did end the quarter with LOE per BOE in March a $5.31 driven by declining workover expenses and by significantly increased production volumes. I'll also note that we are seeing limited inflation on drilling completion or other services at the present time.
As has been mentioned mentioned, we had a company record production for the quarter of over 11,200 BOE per day and with the new wells completed in this quarter, we had production of approximately 13,400 BOE a day in March. Compared to the first fourth quarter of 2018 where we estimated we had 1,100 a day shut in due to offset frac activity, the first quarter did see reduced shut ins as a result of offset frac activity and we only had shut in volume of approximately 635 BOE per day. Our completion program this year should have limited effect on existing producers based on the configuration of our wells.
As a reminder, our 2019 capital budget is back-end weighted and so is our production growth. We completed the three wells in the first quarter, we expect to have the five Midland County wells coming on production later in the third quarter and finally expect five wells coming on late in the fourth quarter. This should leave us with four wells drilled waiting on completion at year end and this schedule should lead to relatively flat production over at least the next quarter and a half compared to this first quarter.
Finally, we have initiated drilling on our Eagle Ford project. We will drill seven wells on our Penn Ranch unit, where we have a 44% working interest and could increase our program by adding an additional three wells in this area. We expect to have these seven to 10 wells online before year end. Of course, we will continue to pursue acreage trades in the Midland Basin to expand our operated acreage and drilling inventory and we continue to have strong interest in pursuing acquisitions both large and small. But while, our strong capital structure supports potential acquisitions, we will continue to be strategic and disciplined in our pursuit of growth. We have the drilling inventory to continue our drill bit growth and are considering bringing on a second rig in the Midland Basin ,before the end of the year. Of course this is dependent on commodity prices and availability of high quality services. Although, the majority of our locations are in the Wolfcamp A and B, we see additional upside in Spraberry intervals yet to be tested on our Upton County acreage and we have Wolfcamp D target zones in both Upton and Reagan counties, which have been tested in close proximity to our acreage. So we continue to be excited about the upside on our acreage.
And with that operator, we will now take any questions that might be out there.
Questions and Answers:
Operator
Great thank you. At this time we will be conducting a question and answer session. (Operator Instructions) Our first question here is from Brad Heffern from RBC Capital Markets. Please go ahead.
Brad Heffern -- RBC Capital Markets -- Analyst
Hey, everyone. Robert, at the end there, you talked about potentially adding a rig in the Midland before the end of the year and you also talked about potentially adding some drilling in the Eagle Ford. I know you said it's sort of commodity price dependent, but what are the decision making factors in that? Is it -- you still want to be able to be cash flow neutral in 2020 or is there some other governor that you're thinking about there?
Robert J. Anderson -- President
In terms of the Eagle Ford, we're working out some final land issues and hopefully we can get this done before we have to make a commitment. The second rig in the Midland Basin, I think it's just based on economics at the wellhead and not necessarily trying to be free cash flow next year. I think given our two rig program next year, we'll have some economics we're seeing. I think we're going to be pretty pleased with ramping up to a second rig, it's just a matter of timing of when we start.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay. And then, I was worrying if you could give an update broadly on just how you're thinking about spacing. We've seen a lot of people in the Midland talking about up-spacing, it looked like, the -- I guess TSRH pad that you talked about as a little more widely spaced than what you'd been doing historically. So just any thoughts on on leading edge spacing?
Robert J. Anderson -- President
Yes. I mean that's a big issue at the moment. I think it's area by area specific. I think as you're in Midland and Upton counties, we're still quite comfortable with 660-foot spacing between the same target interval as you move into our TSRH area, we're going to test out a little wider spacing there and see what kind of results we get. And then I'll be able to come back and tell you somewhere between what we've tried and what we did in the past. I don't think it's nailed down yet, but again it's area specific and there maybe even target specific as well.
Frank A. Lodzinski -- Chief Executive Officer
Yes, Brad this is Frank, if you recall our earnings call from Premier Rand last quarter, we indicated that we are -- we're quite aware that the market is scrutinizing this whole parent-child relationship that we have a lot of locations. We're not very densely drilled in any area. So it gives us an opportunity, certain of that and as you know we're always focused on economics, right. The last thing we're going to do is -- I think for lack of a better word, shoot ourselves in the head on densely drilling on closer spacing and then come back and say it didn't work. So it's foremost on our mind.
Robert J. Anderson -- President
The other point I will make real quick is that at 660-foot spacing those are not proved locations. Our proved location spacing is much wider than that. And in fact, we actually have a probable and a possible between our puds in most cases, so you can kind of figure out the math there on 660-foot spacing, what that does. We've given ourselves a lot of opportunity to continue to evaluate area by area and what that does to our long term reserve profile.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay. Got it. And then just an administrative question. I think the original budget for the Eagle Ford, those seven wells were 22% working interest, but they're 44% on the press release, is that actually an increase in working interest or is that like the JV accounting or something that's changing that number?
Robert J. Anderson -- President
No. Its actual increase in the working interest based on certain parties decision whether to participate or not participate in wells.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay. Thank you.
Operator
Our next question is from Neal Dingmann from SunTrust. Please go ahead.
Neal Dingmann -- SunTrust Robinson Humphrey, Inc. -- Analyst
Good morning guys. Looking at Slide 10, Robert I guess my question, you will continue to see nice improvement I think, in here it talks about your particular stands out, going from five stages to nine stages per day. So you didn't mention I think in your remarks that (inaudible) of staying here flattish, but I'm wondering from a efficiency standpoint and you and Frank step back. Are you continuing to see more of these improvements and do you -- are you -- I guess number one, are you seeing these? And number two are they built into your sort of estimates at all?
Robert J. Anderson -- President
Yes. Neal, they are built into our estimates of what we've been able to accomplish so far this year and so the last time we were frac in wells was -- earlier in the year and that -- this slide captures that. I just say from a cost perspective we're looking at somewhere between $8 million or $8.5 million or so, on a 10,000-foot normalized well. So we're seeing those costs stabilize and definitely the leading factor of that is frac costs have come down quite substantially from last year.
Neal Dingmann -- SunTrust Robinson Humphrey, Inc. -- Analyst
Got it. Okay. And then just lastly on M&A. Frank for you or Robert ,I mean I know there's -- you're always looking out there, I'm just wondering is it because the cap structure you don't want to move leverage or -- I'm just kind of wondering what what sort of criteria are you all looking at right now -- and again in this market we haven't seen really anything for quite some time. Just wondering how does that the radar look? Is it got more popular?
Frank A. Lodzinski -- Chief Executive Officer
Well, I think Neal that the A and D markets all over the place, I think you still have folks out there that have expectations, that may be too high and that's not necessarily a function of commodity prices and so on -- that's a function of hope on their part. On our side, we've said on this call that we may go to a second rig. We continue to work on the smaller things the bolt ons, the trades, the things like we did last year with the larger company and blocking up things in central Reagan County. We're quite comfortable or at least I'm quite comfortable with the improving efficiencies we have in our drilling and completion programs with the type curves. So I think we can get out there and chase things. The governing factor is we're not going to let our balance sheet get out of control, right. We're not going to go to -- three acts or whatever have you EBITDAX to leverage ratio because in a commodity price drop, you've seen what that has done to a lot of our brethren out there.
So a governing factor might be how much debt and we want to keep our balance sheet reasonable. As Robert and I, and others have said, the two fundamental strengths that we've followed over more than three decades for me and Robert's been with us 15 or 16 years and the other guys is, controlled the things we can control, our operations and our balance sheet. So it's kind of a weaselly kind of answer, but we're in the market every day.
So here's the other thing that I would hope would benefit us. Okay. Because -- and Neal, you know, you've been around the block a long time, there's no answer to this. But the capital markets haven't been improving, right? There is not a strong capital market. That has led to monetizations (ph) by people in the past. I think that there's going to be an opportunity for us to pick up some acreage and maybe some production using our balance sheet, perhaps using our stock and perhaps putting some contingencies on it because -- thing we keep on saying to people is why holding onto it. There's not going to be a market that's going to happen overnight, where people are going to pay $40,000 an acre. So we're just trying everything we can.
Neal Dingmann -- SunTrust Robinson Humphrey, Inc. -- Analyst
It makes sense. And I look forward to see what you all come up with. Thanks guys.
Operator
Our next question is from John Aschenbeck from Seaport Global. Please go ahead.
John Aschenbeck -- Seaport Global Securities LLC -- Analyst
Good morning, everyone. Thanks for taking my questions and congrats on the quarter.
Robert J. Anderson -- President
Thank you.
John Aschenbeck -- Seaport Global Securities LLC -- Analyst
So for my first one, I was just hoping you could walk us through directionally just how you see your production profile and commodity mix playing out over the next several quarters? And then also the capital spend under your current outlook, just assuming you stick with the one rig in the Midland. Your prepared commentary was really helpful just in terms of speaking to activity levels, but if you could just help me out here looking at it from the 30,000-foot view at a total company level, any type of color you could provide on your production profile, commodity mix and capital spend would be really helpful? Thanks.
Mark Lumpkin -- Executive Vice President and Chief Financial Officer
Sure. Maybe I'll take a stab at that, it's Mark here and Robert can chime in if he wants you as well. In terms of production, obviously we had some wells come online late in the first quarter and as Robert mentioned our March production was over 13,000 BOE per day. There's nothing coming online between now and late third quarter. So that will decline from there. I think Robert's comment was we should be fairly flat production over next quarter and a half as you would expect, starting with 13,000 BOE per day in March and that's gonna be a little lower in April and then May and June et cetera. And we should start to get some some additional pickup in volumes in the third quarter.
So the way we're kind of thinking about it, it's probably fairly flattish in the second quarter versus the first quarter and the third quarter, we think it's about flattish, but that also depends on the exact timing of when we get wells on line, et cetera. So we're thinking of it that way and really I mean honestly we're probably -- I mean we are a little ahead of what our model kind of had and yet may mean we got a little more first quarter production than third quarter production versus our prior model, but we think it's fairly flat and we still feel very comfortable about being in the range and and obviously we're trying to be, well above the bottom of the range, but we feel better now than we did 60 days ago the last time we spoke because, we are tracking a little bit ahead in some of that's timing, and some of it is improvement and the amount of barrels we've had shut in for fracs and some of it is the type curves, we're performing well relative to that.
In terms of the mix we are seeing a little bit more shrink in some of the gas. So we're seeing a little bit less gas in the kind of the wet stream if you will. So we're not changing any guidance. And certainly when wells come on line, there are higher oil percentage than you would expect versus what we saw in the first quarter. The oil percent just to tick down a little bit. We're still with kind of guided to 65% oil, though we're a little above that here in the first quarter. It probably trends down just a little bit until we get more wells online later in the year.
John Aschenbeck -- Seaport Global Securities LLC -- Analyst
Okay. Mark that was really helpful. And then I'm sorry, I missed it, but just on the capital side it's fairly ratable or just how should I think about that?
Mark Lumpkin -- Executive Vice President and Chief Financial Officer
Well, I mean we spent 42 and changed in the first quarter and we had a decent bit of completion activity. We -- prior it's been a whole lot different than that in the second quarter and then it'll pick up in the third and fourth quarter.
John Aschenbeck -- Seaport Global Securities LLC -- Analyst
Okay, perfect. I appreciate that. And last one from me, Robert and Mark, you had some some really good color on work overs is really helpful, helps explain the increased LOE. I was just curious, how much did those work overs contribute to your Q1 production beat? And then, I apologize if I missed this, I think I did actually, but just how should we think about LOE and future quarters, is the full year guide, a good estimate or just how should we think about it?
Robert J. Anderson -- President
John, if I didn't had a whole lot of impact to our Q1 production volumes to tell you the truth, I mean a lot of that was done during the quarter and so sometimes wells take a little bit of time to clean up after you've worked on them. It hopefully will help stabilize production in the rest of the year on those specific assets. I don't know how to answer your second question.
Mark Lumpkin -- Executive Vice President and Chief Financial Officer
Yes. In terms of where we are in the range, I mean obviously we put out guidance on LOE of 525 per BOE to 575 per BOE for the year. We still think we can fall in that range, starting out at 661 in the first quarter, would you kind of lean toward the higher end of the range, yes. But just for context, we are 661 in the first quarter or kind of full year of last year, we were about $0.80 less than that per BOE on LOE. So that almost gets you to kind of top end of the range as Robert mentioned in March, given the benefit of the workover activity reducing pretty significantly versus probably December, January and February. And then having flush production with much lower than what we reported for the quarter. So it's probably still tracking, but if you probably penned this down we would tell you it's closer to the upper end of the range versus the bottom end of the range.
Frank A. Lodzinski -- Chief Executive Officer
Yes. I will say that that one of the things that doesn't get necessarily a great deal of discussion in the marketplace along these calls and so forth is what we've historically always tried to achieve also -- aside from efficient DNC and operations and keeping our balance sheet under control, of course our capital expenditures are the big part of that. But, as many of you know we've always kind of focused in on the income statement also. And that means controlling and reducing over time your LOE per BOE and your G&A per Boe and that's a function of absolute cost, plus increased production, right. You've got -- your field costs and operations are not necessarily variable. They're kind of step variable. So, we've always focused those of you that I've known us for years and years and years, we've always focused on cutting the downtime on wells and making your run times longer and longer and longer. And we decided to initiate those kind of activities here in the fourth quarter. So, hopefully that's kind of contribute to production going forward and also reduced LOE per BOE going forward.
John Aschenbeck -- Seaport Global Securities LLC -- Analyst
Okay. Got it. I appreciate all the detail and thank you for the time.
Frank A. Lodzinski -- Chief Executive Officer
Aside from everything else we're trying to do it's called maximize gross margins by minimizing your costs.
Robert J. Anderson -- President
That's the end goal at the end of the day. Thanks, Frank.
Operator
Our next question is from Jason Wangler from Imperial Capital. Please go ahead.
Jason Wangler -- Imperial Capital, LLC -- Analyst
Hey, good morning guys. Robert, I wanted to ask you on the non-operated side, I think you mentioned that you had some interest in -- I think it was five zones. Could you maybe just expand on that program kind of the timing? And when you should maybe start to see some results from that?
Robert J. Anderson -- President
They've just gotten started Jason, drilling in that part of the area, it's right on the Midland Martin County line. And they may use multiple rigs. Right now they just have one rig running. So 15 wells is going to take a while to drill and then a while to complete depending on how many frac crews and again they may use two frac crews to complete those wells. So materially, I don't expect to see any production till next year.
Jason Wangler -- Imperial Capital, LLC -- Analyst
Okay. But obviously that's going to help you as far as probably by then looking at the program, obviously you're focused on the A and B this year, but perhaps that can expand as you as you kind of get some information from that and some other stuff I guess around, is that fair?
Robert J. Anderson -- President
Yes. Definitely will have an impact on how we view our Midland County asset, that's not too far south of where this activity is occurring.
Jason Wangler -- Imperial Capital, LLC -- Analyst
Okay. That's all I have. I'll turn it back. Thank you.
Operator
Our next question is from Ron Mills from Johnson Rice & Company. Please go ahead.
Ron Mills -- Johnson Rice & Company, L.L.C. -- Analyst
Hey Robert. Maybe just a quick follow up on Jason's last question. I think we've talked in the past particularly because of that that non-up program, because I think you have something like a 30% average working interest in those wells? Do you still expect to have about $50 million of your DNC budget really going toward projects that won't provide much productive impact this year, but really kind of sets you up well for 2020.
Robert J. Anderson -- President
That's right Ron. That that number probably hasn't changed, although it is dependent upon the timing of these operators getting things drilled. So this 15 well program, they're just getting started and they've only got one rig running. We kind of thought they might have more than one rig at some point in that program to help speed up the drilling side of it. So the $50 million of capital we spend this year may actually go up a little bit with -- in terms of how it contributes to production. On the other hand, we may not spend it all this year and it may flow into next year, so it's really hard to tell until we get closer to the end of the year.
Mark Lumpkin -- Executive Vice President and Chief Financial Officer
But really Ron, I mean overall whether it's on our operated schedule or than on up, I mean we've got no new information now versus our call seven or eight weeks ago. And like I said on the production side, we're probably tracking a little bit ahead, on the CapEx side, I mean we made no changes to the time and assumptions really Ron anything for this year.
Ron Mills -- Johnson Rice & Company, L.L.C. -- Analyst
Okay. And then -- if it was Robert or Frank that mentioned earlier, you talked about potentially going to the second rig, I think on your last call you talked about looking at growth versus free cash flow, where really the driver is ability to continue to have a strong balance sheet, not necessarily with the endgame of generating free cash flow, if your drilling activity generates far greater returns. Can you just expand a little bit on your thoughts of putting money in the (inaudible) versus just trying to solve for a free cash flow situation?
Frank A. Lodzinski -- Chief Executive Officer
Hey, Ron. This is Frank. Many of you folks on the call, we've known a long time. And if we took a poll of everybody that was on the call, we would get mixed answers as to the importance of free cash flow versus growth in a smaller company. We've talked to a lot of folks and we get some that say that the free cash flow deal is not as important as efficient growth and additions to proved reserves. So rather than -- so I would say it is a unsettled issue for us and we'll continue to talk with people in the marketplace, although that won't necessarily be the determining factor, no offense to you folks, but we're focused on building shareholder returns positively impacting our stock price.
Now with that all said, obviously if we bring in a second rig it would push out that free cash flow dynamic, probably another year. Okay? If we continue to see strong commodity prices next year, I think I look this morning I think the strip price next year was $58, if it's that or more, we will consider that. We just didn't -- we just wanted to kind of introduce that topic at this point as a consideration.
The second thing I'll say going back to something a question that was earlier from another person, is the fact that our Eagle Ford drilling may be stepped up and we may end up with a 44% percent interest rather than a 22% interest. I don't want anybody to think that some of our partners, not going concern on those wells is a function of economics. The economics out of those wells are very, very, very strong. And and on these wells to compete with things that we're doing in the Midland Basin, we very well could bring in a partner on those or we may just choose to retain that 44% interest and I guess Robert, Penn Ranch right now, which well are we out on Penn Ranch?
Robert J. Anderson -- President
The second well.
Frank A. Lodzinski -- Chief Executive Officer
Well, the second well. So unfortunately in the in the operating environment and with partners and in the case of of West Texas with -- with a non-op program, we're dealing with the opportunities that are are available to us on a daily basis. So, we just kind of wanted to throw it out there. So anyway that the sum total of that is if the economics are strong, we're adding proved reserves, OK. We're not being adversely affected by spacing and things along those lines. If we can meaningfully increase our production without destroying our balance sheet, we'll consider a second rig later on this year. I don't know how to say that.
Ron Mills -- Johnson Rice & Company, L.L.C. -- Analyst
Well put me in the camp that thinks outspending for economic growth is a far better use of capital. Then one last -- just a -- I guess clarification, you talked a little bit about it on your last call and also today, in terms of your inventory and well spacing, you talked about the inventory being basically booked on greater than the 660-foot spacing, I know you tested it in Midland County, you drilled some wells on kind of 330-foot spacing, was that the equivalent of 660 feet, but you were just doing it in the upper and lower and kind of more of a wine rack formation?
Robert J. Anderson -- President
Yes that's right, Ron. We were drilling an A and a B and so they were actually probably a little wider than 330-foot spacing, but anyway essentially a 660-foot pattern in the same target zone. We haven't tested anything tighter than that in the same target zone.
Ron Mills -- Johnson Rice & Company, L.L.C. -- Analyst
Okay great. And then when you're talking about widening out in some upcoming tests up to -- I think you said something like 525 feet, is that within the same target zone or was that also kind of the wine rack separation?
Robert J. Anderson -- President
That's the wine rack. So we're going to do a three well pad, where we're basically 1,100 feet or so in the same bench 550 feet between well, so two B uppers and a B lower.
Ron Mills -- Johnson Rice & Company, L.L.C. -- Analyst
Okay great. That's what I needed. Thank you very much.
Frank A. Lodzinski -- Chief Executive Officer
Hey, Ron on spacing and Robert, please correct me if I'm wrong here. But we have the number of locations. We try to be not aggressive on the number of locations on Page 15 on our PowerPoint presentation. We do feel that we have additional upside in the Spraberry, the Jo Mill et cetera, et cetera. But if you take a look at the charts we have out there based on lateral lengths where we are now -- we think we have like 450 gross locations in the 8,750-foot to 10,000-foot plus range. I want to point out that if you look at that -- here's where Robert got to correct me if I'm wrong. If you looked at that similar kind of chart, a year and a half ago or so, you would see that was more in the shorter laterals and less in the longer laterals. So the importance of the acreage trades, the bold-ons. the swaps and all of that daily activity is leading toward longer laterals and greater efficiencies. Am I saying that the right way, Robert?
Robert J. Anderson -- President
Absolutely. Yes, that's correct.
Frank A. Lodzinski -- Chief Executive Officer
I guess that we had 30% or 40%, maybe 50% less in those longer laterals some time ago, but that's kind of a guess. So, I just want to point that out also. We haven't been aggressive on all of that.
Ron Mills -- Johnson Rice & Company, L.L.C. -- Analyst
Great. Thank you.
Operator
Our next question is from Jeff Grampp from Northland Capital Markets. Please go ahead.
Jeffrey Grampp -- Northland Capital Markets -- Analyst
Good morning, guys. Just second, Frank on the last topic there on the lateral lengths. Can you guys touch it on the -- if you guys did want to make that decision to go ahead and add that second rig. Can you talk about the sustainability of those kind of 9,000-foot to 10,000-foot laterals given the accelerated development pace that you guys can potentially be in?
Robert J. Anderson -- President
Jeff, where we would put that second rig, I mean obviously we'd still move around because we're not in a situation where we can go out and develop a really big unit with lots of capital and all that, we'd rather bounce around a little bit. But drilling anywhere from three to five well pads or maybe six well pads in areas where we do have longer laterals 10,000 footers like in Southeast Reagan County, 10,000 footers like on the Upton Reagan county line, those areas are where we have the highest capital efficiency and good economics.
We have a couple of units where we've got shorter laterals, so the capital efficiency isn't as good, but the economics are really good on those wells, like in Upton County we have a 5,000-foot lateral length unit, but we've got lots of opportunity. We've been kind of holding that back for now just because of capital efficiency, but we definitely could go out there and develop that unit further and it would have really good economics.
Jeffrey Grampp -- Northland Capital Markets -- Analyst
Okay. Great, really helpful. And for my follow up, it looks like on the cost side, I think it's on Slide 10, you guys are continuing to show costs moving down and looking -- it gets quite a bit below some of the type curve costs that you guys quote in the back end of the deck. So I was just curious, if you guys are giving any consideration to updating kind of the AFE numbers that you guys put in your type curves, is there some I guess conservatism in there to kind of get to that type curve number? And then can you touch on how the use of in-basin sand currently or prospectively in the future might change some of that math for you?
Robert J. Anderson -- President
You're right. We have not updated our type curve economics. So we've got some upside there because of the current efficiencies and cost improvements that we've had. We'll probably go through the middle of the year and update things as it makes sense. I think that the in-basin sand has really helped on the completion side and driving those costs down? We're not using 100% in-basin sand, but we're using probably 95%. We still pump a little bit of 30/50 at the tail end of our jobs and that's not in-basin, but the (inaudible) in the 40/70s all in-basin sand.
Jeffrey Grampp -- Northland Capital Markets -- Analyst
All right. Great. I appreciate those details and nice quarter guys.
Robert J. Anderson -- President
Thanks.
Operator
Our next question is from Gail Nicholson from Stephens. Please go ahead.
Gail Nicholson -- Stephens -- Analyst
Good morning everybody. On those wider spacing tests that you're testing. Are you doing anything different with the completion design?
Robert J. Anderson -- President
We have kicked out around a little bit Gail, but we have not come up with anything yet that would make us want to change anything. We recognize that if we're drilling at pretty tight spacing, maybe certain of our design factors change the amount of fluid or things like that. I think there's some other things that we're going to consider in these frac designs that may change the way that we're physically pumping the job, but the sizes probably stay about the same.
Gail Nicholson -- Stephens -- Analyst
Okay, great, thank you. And then you might have a very successful hedging history. I think you have great hedges that were put out in 1980, I think there's incremental hedges in 2020. Can you talk about kind of your hedges -- hedging strategy going forward?
Mark Lumpkin -- Executive Vice President and Chief Financial Officer
Sure. First we do have some nice hedges on. We'd love for them to be out of the money because that would mean the prices are much higher. But, really I mean we are more hedged for 2019 than we probably typically will be and that was largely a result of adding some hedges around having announced (inaudible) deal last fall when prices were high and kind of being left with some pretty nice hedges whenever prices fell, we terminated that deal. In terms of going forward, I mean we're definitely thinking 18 months to 24 months out, maybe a little longer than that. We want just a decent chunk of our ongoing production hedge here at the beginning of April or maybe mid-April, we added some hedges for 2020. I think we put a 1,000 barrels on a day at $59.75 and plus $0.25 on the mid-cash basis. We obviously like to hedge at higher prices than lower prices. We're not adverse to hedging defensively, but we've fortunately been able to hedge kind of offensively and just get a decent bet of -- kind of protection from a cash flow standpoint. And we're not going to probably typically be 84% of our guidance hedge, I mean that's just not the way we're thinking of things, but we do want 50% to 75% hedged and the current year and somewhere around half that amount or so maybe a little more depending on the time of the year for the year out.
Frank A. Lodzinski -- Chief Executive Officer
Yes. I think, this is Frank. I think this is another juggling act on hedging. I think historically, we've been kind of like 50% to 65% hedged, as we do see greater prices like I think it's kind of gangbusters to be hedged at $65 or $66, as we see more, I will come in here and talk to Mark and Robert and our consultants and so on and say should we do more -- should we do more. So I wouldn't rule out being 80% hedged in the future with strong prices, but I think our sweet spot is probably 50% to 65% or something like that. You have to -- going back to balance sheet protection and things like that, you have to have enough cash flow to pay your G&A and your capital costs and hedging does that for us and has done that for us. So, it's up -- it's once again an ongoing thought process with a substantive floor if you will?
Gail Nicholson -- Stephens -- Analyst
Great. Thank you.
Operator
(Operator Instructions) Our next question here is from David Beard from Coker Palmer. Please go ahead.
David Beard -- Coker & Palmer Investment Securities, Inc. -- Analyst
Hey, good morning gentlemen. Obviously, most of my questions have been asked, but I did want to do a little follow up relative to M&A and the capital markets. You would seem if capital markets are shut, you'd probably have to do a deal that doesn't require a lot outside financing, debt or equity, is that the case? And does that mean smaller deals are easier to get done than bigger deals? Or do you see the market go a bit differently? Thank you.
Frank A. Lodzinski -- Chief Executive Officer
No. I -- we've been enhancing our staffing with the addition of folks like Mark and Scott from the capital markets and from a debt market standpoint. I've been kind of standing back a little bit on those things to consider it. So this is maybe -- maybe just some some thoughts, but the way we've conducted our lives in the past is we go out there and do deals. We'd increase our our debt component. The worst, I think I've ever had was a 2.7 ratio of debt to EBITDAX, That's been a -- that situation -- about that situation, it's where we had a clean -- clear and clean line of sight to increasing production, to get that down below two and then we go to the capital markets to to refresh our balance sheet because hopefully that resulted in greater production and greater EBITDA and increased share prices and so on.
So you know without being in too smart alec here, turn that back on, are you smart people that have been on the phone. I don't know when the capital markets are going to be there so we need to -- we need to consider debt financing, we need to consider utilizing our stock periodically for good deals that makes sense and facilitate things like scale, efficiency, economic growth and and so I don't know what else to say. I mean if anybody could tell me if the capital markets are ever going to come back to the small cap sector, then maybe we could be a little more definitive. But again a mealy mouthed way of saying, I don't know, but we're out there talking. The good news is that we do have a track record. We do have people that want to finance us. We do have people that have indicated that they may take a stock position. So we keep on working at it. I don't know how to answer that any better, David, I'm sorry.
David Beard -- Coker & Palmer Investment Securities, Inc. -- Analyst
No, no I just, sort of your read on the current market and obviously it changes and all that, but now I definitely appreciate the color. Thanks a lot gentlemen.
Robert J. Anderson -- President
Thank you David.
Operator
This concludes the question and answer session. I'd like to turn the floor back to management for any closing comments.
Frank A. Lodzinski -- Chief Executive Officer
Well, I think we've pretty much set it all. We appreciate you folks dialing in. We'll keep on working hard. We will keep on doing our bolt-on trades, improving our efficiency in our drilling and completion, working on our P&L cost to increase gross margins and hopefully have a lot of positive quarters like this in the future. So, thank you very much.
Operator
This concludes today's teleconference, you may disconnect your lines at this time. Thank you, again for your participation.
Duration: 56 minutes
Call participants:
Scott Thelander -- Vice President of Finance
Frank A. Lodzinski -- Chief Executive Officer
Mark Lumpkin -- Executive Vice President and Chief Financial Officer
Robert J. Anderson -- President
Brad Heffern -- RBC Capital Markets -- Analyst
Neal Dingmann -- SunTrust Robinson Humphrey, Inc. -- Analyst
John Aschenbeck -- Seaport Global Securities LLC -- Analyst
Jason Wangler -- Imperial Capital, LLC -- Analyst
Ron Mills -- Johnson Rice & Company, L.L.C. -- Analyst
Jeffrey Grampp -- Northland Capital Markets -- Analyst
Gail Nicholson -- Stephens -- Analyst
David Beard -- Coker & Palmer Investment Securities, Inc. -- Analyst
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