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Good morning, and welcome to Earthstone Energy's Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation [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; Scott Thelander, Vice President of Finance. Thank you, Mr. Thelander, you may begin.
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 accomplishments, and our future plans, followed by remarks from Mark regarding financial matters and performance and concluding with remarks from Robert regarding our operations.
I will now turn the call over to Frank.
Okay. Well, thank you, Scott, and welcome to everybody for joining our call this morning. We’ve had a great start to the year with the 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 a 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 the drill bits.
Our high-quality acreage position provides a substantial inventory of drilling projects that generate attractive rates of return and our operations team is doing an excellent job of extracting that value occasionally.
We’ve also been able to maintain a very strong balance sheet and we have the proven expertise to find a value rate and negotiate successful growth transactions. That combination of strategic options gives us the flexibility to remain disciplined our growth strategy.
I’ll now turn the call over to Mark for a brief overview of our financial situation.
Thank you, Frank. Before I begin, 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 metrics 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 of 2018 and the fourth quarter of 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 improving on the oil price side.
On top of this, the significant discount we are receiving on our oil based on the Midland to Cushing 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 $32.5 million in the first quarter of 2019, up 35% from the $23.9 million we recorded in the fourth quarter of 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 of 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 for 2019, our LOE per BOE has been relatively high over the past two quarters due to a workover program that we initiated late 2018. Robert will reference further, but we expect the recent workover programs to result in greater production and longer run times.
In the first quarter, our recurring LOE was $5.27 per BOE and workover 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 of 2018 and $4.6 million in the first quarter of 2018.
Our G&A per BOE excluding stock-based compensation averaged $5.01 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 are 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 our commodity price hedges. We also reported unrealized mark-to-market loss of $53.2 million. Comparatively, in the fourth quarter of 2019, we reported a $96.0 million unrealized gain on the mark-to-market of our hedges. Largely as a result of this $53.2 million of unrealized mark-to-market loss, we reported a net loss for the quarter of $38.4 million.
As described in our previous earnings calls, GAAP requires us to disclose the amount of net loss of our income associated with the controlling interest which 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 and 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 redetermined as scheduled and was increased by $50 million to $325 million. At March 31, 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 hedges in the first quarter with realized gains of $5.4 million, and we continue to layer on hedges to reduce volatility of our cash flow and have added some additional hedges on 2020 oil volumes in April as prices improved materially 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 position 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 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 budgeted total 2019 expenditures of approximately $190 million and we do expect this to be more back-end weighted. So with that, I will turn it over to Robert to review operations.
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 and Reagan County, the Malone has taken some time to reach peak rates.
However, after 75 days, the well has a peak IP 30 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 a 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. So Wolfcamp B upper had a peak IP 30 of 1467 BOE per day, 94% oil while the B lower well had a peak IP 30 of 1109 BOE per day, 91% oil. As a point of reference the offsetting Benedum Wolfcamp B lower well we completed last September, has a cumulative production of 176,000 barrels of oil equivalent in a 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 Midstates 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 Midstates 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 1100 feet apart in the same landing zone or about 550 feet between the 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 Howard, Martin and Midland counties with interest 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 datapoint 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 of $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, 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 fourth quarter of 2018 where we estimate that we had 11,000 BOE 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 Pen Ranch. Unit where we have a 44% working interest and it could increase our program by adding an additional three wells in this area. We expect to have these seven to ten 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 has 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.
[Operator Instructions] Our first question here is from Brad Heffern from RBC Capital Markets. Please go ahead.
Hey everyone. Robert, at the end 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 are thinking about there?
In terms of the Eagle Ford, we are 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 will have some economics we are seeing. I think we are going to pretty pleased with the ramping up to a second rig. It’s just a matter of timing of when we start.
Okay. And then, on the – I was wondering if you could given an update broadly on just how you are thinking about spacing. We’ve seen a lot of people in the Midland talking about upspacing, it look like the – I guess, TSRH pad that you talked about is a little more widely spaced than what you’ve been doing historically. So, just any thoughts on leading edge spacing?
Yes, I mean, that’s a big issue at the moment. I think it’s area-by-area-specific. I think, as you are in Midland and Upton counties, we are still quite comfortable with 660 foot spacing between the same target interval.
As you move into our TSRH area, we are 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 it maybe even target-specific as well.
Yes, Brad. This is Frank. If you recall our earnings call from year end last quarter, we indicated that we are quite aware that the market is scrutinizing this whole parent child relationship that we have a lot of locations. We are not very densely drilled in any area.
So, it gives us an opportunity to consider that and as you know, we are always focused on economics, right? The last thing we are 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.
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 spuds in most cases.
So, you can kind of figure out the math there on 660 foot spacing what that does, so. 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.
Okay. Got it. And then, just a management question, I think the original budget for the Eagle Ford those seven wells were a 22% working interest, but they are 44% in 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?
The actual increase in the working interest based on certain parties’ decision whether to participate or not participate in wells.
Okay. Thank you.
Our next question is from Neal Dingmann from SunTrust. Please go ahead.
Morning guys. Looking at Slide 10, Robert, I guess, my question you all continue to see nice improvement I think and here it talks about the particular stands out going from five stages to nine stages per day.
So, you did mentioned I think in your remarks that, you know what first cost you saw are staying here flattish, but I am wondering from an efficiency standpoint, and you Frank, step back, are you continuing to see more of these improvements? And are you – I guess, number one, are you seeing these and number two, are they built into your sort of estimates at all?
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 fracking wells was earlier in the year and that, this slide captures that. I just say from a cost perspective, we are looking at somewhere between $8 or $8.5 million or so on a 10,000 foot normalized well.
So, we are seeing those cost stabilize and definitely the leading factor of that is frac costs have come down quite substantially from last year.
Got it. Got it. Okay. And then just lastly on M&A. Frank, for you or Robert, I mean, I k now there is, you are always looking out there. I am just want and is it’s because the cap structure you don’t want to move leverage, or I am just kind of wondering, 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 the radar looking? Is it got more possible?
Well, I think, Neal that the A and B markets all over the place. I think you still have folks out there that have expectations that maybe too high. 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 a larger company and blocking up things in Central Reagan County.
We are quite comfortable, or at least I am 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 factors are not going to let our balance sheet get out of control, right.
We are not going to go to a 3 x or whatever have you, EBITDAX to leverage ratio, because in a commodity price drop you see what that has done to a lot of our brothers 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 followed over more than three decades for me and Robert is spending with us 15 or 16 years and the other guys those control the things we can control, our operations and our balance sheet. So it’s kind of a – kind of answer. But we are in the market every day. So here is…
Got it.
Here is the other thing that I would hope would benefit us, okay? Because, and you know, you’ve been round the block a long time. There is no answer. But the capital markets haven’t been improving, right? There is not a strong capital market.
That has led to modernizations by people in the past. I think that there is 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 of things we keep on saying to people is, why you are – there is not going to be a market that’s going to happen overnight where people are going to pay you $40,000 an acre. So, we are just trying everything that we can.
Now it makes sense. And I look forward to see you all come up with. Thanks guys.
Our next question is from John Aschenbeck from Seaport Global. Please go ahead.
Good morning everyone. Thanks for taking the questions and congrats on the quarter.
Thank you.
So, for my first one, I was just hoping that you could walk us through directionally, just how you see your production profile and commodity mix ploughing 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 BOE at the total company level. Any type of color you could provide on your production profile, commodity mix and capital spend would be really helpful? Thanks.
Sure. Maybe, I’ll take a stab at that. It’s Mark here and Robert can chime in if he want to 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 is nothing coming online between now and later third quarter. So, that will decline from there.
I think, Robert’s comment was, we should be fairly flat production over the next quarter and a half, as you would expect, starting with 13,000 BOE per day in March, it’s going to be a little lower in April and then May and June, et cetera. And we should starting to get some additional pick up in volumes in the third quarter.
So the way we are kind of thinking about it’s – 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 time at when we get wells online et cetera.
So, we are thinking of it that way and really, I mean, honestly, we are a little ahead of what our model kind of had and it 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 obviously we are 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 and 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 were 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 are seeing a little bit less gas in the kind of the wet stream if you will. So, we are not changing the 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 percentage is to tick down a little bit.
We are still with kind of guiding to 65% oil though we are a little above that here in the first quarter. It probably trends down just a little bit until we get more wells online late in the year.
Okay. Mark that was really helpful. And then, sorry if I missed it. But just on the capital side it’s fairly ratable or just how should I think about that?
Well, we spent 42 unchanged in the first quarter and we had decent bit of completion activity. We – probably we will spend a whole lot different than that in the second quarter and it will pick up in the third and fourth quarter.
Okay. Perfect. Thank you for that. The last one for me. I think Robert gave more – you got some really good color on workovers, that’s really helpful, helps explained the increased LOE. I was just curious, how much did those workovers contribute to your Q1 production beat? And then, I apologize if I missed this, I think you did it actually, but, just how should we think about LOE in future quarters? Is the full year guide a good estimate or just how should we think about it?
John, it probably 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. Maybe – yes, in terms of where we are in the range of and obviously, we put out guidance on LOE of 5.5 to 5.75 per BOE for the year. We still think we can fall in that range. Starting out at 6.61 in the first quarter, would you kind of lane toward the higher end of the range?
Yes. But just for context, we were at 6.61 in the first quarter or kind of full year last year, we were about $0.80 less than that per BOE on LOE. So that almost gets you to kind of the top-end of the range and as Robert mentioned, in March, the benefit of the workover activity reducing pretty significantly versus probably December, January and February.
And then having fresh production with much lower than what we reported for the quarter. So, it’s probably still tracking. But if you probably pin this down, we’d tell you, it’s close to the upper-end of the range versus the bottom of the range.
Yes, I will say that one of the things that doesn’t get necessarily a great deal of discussion in the marketplace and all these calls and so forth is what we’ve historically always try to achieve also. You know, aside from efficient D&C 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 got, your field cost and operations are not necessarily variable.
They are kind of step-variable. So, we’ve always focused, those of you that have known us for years and years and years, we’ve always focused on cutting the downtime on wells and making your runtimes longer and longer and longer. And we decided to initiate those kind of activities here in the fourth quarter.
So, hopefully, it’s going to contribute to production going forward. And also reduced LOE per BOE going forward.
Okay. Got it. I appreciate all the detail and thank you for the time.
Aside from everything else we are trying to do, it’s called maximized gross margins by minimizing your costs.
Let’s see end goal at the end of the day. Thanks, Frank.
That’s the goal.
Our next is from Jason Wangler from Imperial Capital. Please go ahead.
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 with 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?
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 a one rig running. So 15 wells, it’s 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 until next year.
Okay. Okay, but obviously that’s going to help you as far as probably by the end, looking at the program, obviously you are focused on the A and B this year. But perhaps, that can expand as you kind of get some information from that and some other stuff I guess around, is that fair?
Yes, definitely it will have an impact on how we view our Midland County asset. It’s not too far south of where this activity is occurring.
Okay. That’s all I have. I’ll turn it back. Thank you.
Our next question is from Ron Mills from Johnson Rice and Company. Please go ahead.
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 non-op program, because I think you have something like – is it a 30% average working interest in those wells?
Do you still expect to have about $50 million of your D&C budget really going forwards projects that won’t provide much productive impact this year, but really kind of sets you up well for 2020?
That’s right, Ron. 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 are just getting started and they’ve only got with 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.
But really, Ron, I mean, overall, whether it’s on our operated schedule or the non-op. I mean, we’ve got no new information now versus our calls on eight weeks ago. And like I said, on the production side, we are probably tracking a little bit ahead on the CapEx side. I mean, we made no changes to the timing assumptions really around anything for this year.
Okay. And then, I can’t remember really it’s, Robert or Frank that mentioned earlier and you talk about potentially going to a 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 end game 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 into [Indiscernible] versus just trying to solve for a free cash flow situation?
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 give 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 will continue to talk with people in the marketplace. Although that won’t necessarily be the determining factor, no offense to you folks. But we are 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? Probably another year. If we continue to see strong commodity prices at next year, I think I looked this morning, I think the scrip price next year was $58 if it’s that or more, we will consider that.
We just want to kind of introduce that topic at this point as a consideration. The second thing I will say, going back to something, a question that was earlier from another person is the fact that, our Eagle Ford drilling maybe stepped up. And we may end up with a 44% interest rather than a 22% interest.
I don’t want anybody to think that some of our partners not going concern on those wells as a function of economics. The economics on those wells are very, very, very strong. And on these wells compete with things that we are 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, at Pen Ranch right now, which well are we on, on Pen Ranch?
The second well.
Well, the second well. So, unfortunately, in the operating environment, and with partners and in the case of West Texas with a non-op program, we are dealing with the opportunities that are available to us on a daily basis.
So we just kind of wanted to drill it out there. So, ending with this, the sum total of that is, if the economics are strong, we are adding proved reserves, okay? We are not being adversely affected by spacing and things along those lines. If we can meaningfully increase our production without destroying our balance sheet, we will consider a second rig later on this year. I don’t know how to say that.
Well, put me in the camp that thinks outspending for economic growth is a far better use of capital. Then one last just – I guess, clarification, you talked a little bit about it on your last call and also today.
In terms of your inventory in well spacing, you talked about the inventory being basically booked on greater than the 660 foot spacing. I know you tested in Midland County. You drilled some wells on kind of 330 foot spacing. Was that equivalent of 660 feet, but you were just doing it in the upper and lower and kind of more of the line rack formation?
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 catched anything tighter than that in the same target zone.
Okay, great. And then, when you were 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?
That’s the wine rack. So we are going to do a three well pad where we are basically a 1100 feet or so in the same bench, 550 feet between wells. So, to be uppers and it be lower.
Okay, great. That’s what I needed. Thank you very much.
Hey Ron, on spacing, and Robert, please correct if I am wrong here, but we have the number of locations. We try to be not aggressive on the number of locations on page 15 in our PowerPoint presentation. We do see all that we have additional upside in the Spraberry to Jo Mill, et cetera, et cetera.
But if you take a look at the charts we have out there, based on lateral lengths where now we think we have, like 450 gross locations and the 8750 to 10,000 foot plus range. I want to point out that if you looked at that, here is where Robert has got to correct me if I am wrong.
If you look at that similar kind of chart year and a half ago or so, you would see that that there was more in the shorter laterals and less in the longer laterals. So, the importance of the acreage trades, the bolt-ons, the swaps and all of that daily activity is leading towards longer laterals and greater efficiencies. Am I saying that the right way, Robert?
Yes, that’s correct.
I guess, that we had 30% or 40%, maybe 50% less in those longer laterals sometime 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.
Great. Thank you.
Our next question is from Jeff Grampp from Northland Capital Markets. Please go ahead.
Good morning guys. Just sticking to Frank on the last topic there on the lateral lengths. Can you guys touch on to the – if you guys did want to make that decision go ahead and add that second rig, can you talk about the sustainability of those kind of 9,000 to 10,000 foot laterals, given the accelerated development pace that you guys could potentially again?
Jeff, where we put that second rig, I mean, obviously, we still move around, because we are 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 if we get, definitely could go out there and develop that unit further and it would have really good economics.
Okay, great. Very, very helpful. And for my follow-up, it looks like on the cost side, I think it’s on Slide 10 you guys are beginning to show cost moving down and looking, I guess, quite a bit below, some of the type curve cost that you guys quote in the back-end of the deck.
So I was just curious if you guys are giving any considerations to updating kind of the AFE numbers that you guys put in your type curves, is there some, I guess, some conservatism in there to just 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?
You are 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 will 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 are not using a 100% in-basin sand, but we are using probably 95%. We still pump a little bit of 3050 at the tail-end of our jobs and that’s not in-basin, but the 100 mesh in the 4070s all in-basin sand.
All right. Great. Appreciate those details and nice quarter guys.
Thanks.
Our next question is from Gail Nicholson from Stephens. Please go ahead.
Good morning everybody. On those line of spacing test that you are testing, anything different with the completion design?
We have kicked that 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.
But I think there is some other things that we are going to consider in these frac designs. It may change the way we are physically pumping the job, but the sizes probably stay about the same.
Okay. Great. Thank you. And then, you guys have a very successful hedging history. I think you have great hedges that would put on in 2019. I think that’s incremental hedges in 2020. Can you just talk about kind of your hedging strategy going forward?
Sure, first, we did have some nice hedges on. We’d love for them to be out of the money, because that would make much as they 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 announcements of volatile last fall when prices were high and kind of being left with some pretty nice hedges whenever prices fell we terminate that deal.
In terms of going forward, I mean we are definitely thinking – into 24 months out or 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 as mid-April, we added some hedges for 2020, I think we got a 1000 barrels on a day at $59.75 and plus $0.25 on the Mid-Cush basis.
We obviously like to hedge higher prices than lower prices. We are not adverse to hedging defensively, but we’ve fortunately been able to hedge kind of offensively and just get a decent bit of kind of protection from a cash flow standpoint.
And we are not going to probably typically be 84% of our guidance hedged. I mean, that’s just not the way we are thinking of things. But we do want 50% to 75% hedged and the current year somewhere around half that amount or so maybe depending on the time of the year for the year out.
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 this 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 to solve on inflation.
We do more should we do more. So I wouldn’t move up 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 go back to balance sheet protection and things like that.
You have to have enough cash flow to pay your G&A and your capital cost and hedging does that for us. And it has done that for us. So, it’s once again an ongoing thought process with a substantive floor, if you will.
Great. Thank you.
Thank you, Gail.
Your next question here is from David Beard from Coker Palmer. Please go ahead.
Hey, good morning gentlemen. Obviously, most of my questions has been asked. But I did want to do a little follow-up relative to M&A and the capital markets. It would seem as capital markets are shut, you’d probably have to deal that doesn’t require a lot of 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 hold that differently? Thank you.
No, we’ve been enhancing our staffing with the addition of folks like Mark and Scott from a 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, just some thoughts. But, you know the way we’ve conducted our lines in the past is we go out there and do deals.
We would increase our debt component. The worst I think I’ve ever had was a 2.7 ratio of debt-to-EBITDAX. That situation, about that situation, it’s where we had a clean, clear and clean line of sight to increase in production to get that down below 2 and then we go to the capital markets to refresh our balance sheet, because hopefully that resulted in greater production and greater EBITDA and increased share prices and so on.
So, without being too smart out like here, turn that back on all these 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 consider debt financing. We need to consider utilizing our stock periodically for good deals that makes sense and facilitate things like scale or efficiency, economic growth.
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, maybe miles away of saying I don’t know, but we are 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 division. So we keep on working at it. So don’t know how to answer that any better, David. I am sorry.
No, that’s just sort of your read on the current market and obviously it changes and all that. But definitely appreciate the color. Thanks a lot gentlemen.
Thank you, David.
This concludes the question and answer session. I’d like to turn the floor back to management for any closing comments.
Well, I think, we pretty much said it all. We appreciate you folks dialing in. We will keep on working hard. We will keep on doing our bolt-ons, trades, improving our efficiency and our drilling and completion, working on our P&L cost, increased gross margins and hopefully have a lot of positive quarters like this in the future. So, thank you very much.
This concludes today's teleconference. You may disconnect your lines at this time. Thank you again for your participation.