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Edited Transcript of ESTE earnings conference call or presentation 6-May-19 3:00pm GMT

Q1 2019 Earthstone Energy Inc Earnings Call

DENVER Jun 11, 2019 (Thomson StreetEvents) -- Edited Transcript of Earthstone Energy Inc earnings conference call or presentation Monday, May 6, 2019 at 3:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Frank A. Lodzinski

Earthstone Energy, Inc. - Chairman & CEO

* Mark Lumpkin

Earthstone Energy, Inc. - Executive VP & CFO

* Robert J. Anderson

Earthstone Energy, Inc. - President

* Scott Thelander

Earthstone Energy, Inc. - VP of Finance

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Conference Call Participants

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* Bradley Barrett Heffern

RBC Capital Markets, LLC, Research Division - Associate

* David Earl Beard

Coker & Palmer Investment Securities, Inc., Research Division - Director of Research & Senior Analyst of Exploration and Production

* Gail Amanda Nicholson Dodds

Stephens Inc., Research Division - MD & Analyst

* Jason Andrew Wangler

Imperial Capital, LLC, Research Division - MD & Senior Research Analyst

* Jeffrey Scott Grampp

Northland Capital Markets, Research Division - MD & Senior Research Analyst

* John W. Aschenbeck

Seaport Global Securities LLC, Research Division - MD & Senior Analyst

* Neal David Dingmann

SunTrust Robinson Humphrey, Inc., Research Division - MD

* Ronald Eugene Mills

Johnson Rice & Company, L.L.C., Research Division - Analyst

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Presentation

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Operator [1]

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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.

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Scott Thelander, Earthstone Energy, Inc. - VP of Finance [2]

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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'll now turn the call over to Frank.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [3]

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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 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 a drill bit. 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 efficiently. We've also been able to maintain a very strong balance sheet, and we have the 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'll now turn the call over to Mark for a brief overview of our financial situation.

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [4]

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Thank you, Frank. Before we 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 volume 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 the 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 $32.4 million in the first quarter of 2019, up 35% from the $23.9 million we've 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 2 quarters due to a workover program that we initiated late 2018. Robert will reference further, but we expect the recent workover program 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 per-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 a commodity price hedges. We also recorded a 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 the $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 or income associated with the controlling interest, which essentially reflects our Class A shares. Accordingly, from a GAAP perspective, we reported a net loss attributable of 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 worth 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 materially from late last year and early this year.

Our hedge position remained 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 haven't placed basis differential hedges for our oil and natural gas at approximately same volumes as the hedges are 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'll turn over to Robert to review operations.

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Robert J. Anderson, Earthstone Energy, Inc. - President [5]

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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 3 operated wells in the Midland Basin. In February, we completed our Malone 1-31A 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 2 Ratliff wells in Upton County way 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 2 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 peak IP30 of 1,109 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 180 days. So we are quite pleased with the results in this area. As we have previously mentioned during the quarter, we commenced drilling of 5-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 5 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 3-well TSRH pad, drilling 2 wells 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 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 nonoperated activity.

During the first quarter, we participated in 2 wells completed in Reagan County in which we have a 50% working interest and 1 well completed in Howard County, where we have a 35% working interest. We're 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 5 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 work over 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 estimated, 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 3 wells in the first quarter. We expect to have the 5 Midland County wells coming on production later in the third quarter. And finally, expect 5 wells coming on late in the fourth quarter. This should leave us with 4 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 7 wells on our Pen Ranch unit where we have a 44% working interest. And could increase our program by adding an additional 3 wells in this area. We expect to have these 7 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'll now take any questions that might be out there.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question here is from Bradley Heffern from RBC Capital Markets.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [2]

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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 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?

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Robert J. Anderson, Earthstone Energy, Inc. - President [3]

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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 of -- at the wellhead and not necessarily trying to be free cash flow next year. I think given our 2-rig program next year, we'll have some -- in the economics we're seeing, I think, we are going to be pretty pleased with ramping up to a second rig, it's just a matter of timing of when we start.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [4]

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Okay. And then I was wondering if you can 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 looks like the, I guess, the TSRH pad that you talked about is a little more widely spaced that what you have been doing historically, so just any thoughts on leading edge spacing?

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Robert J. Anderson, Earthstone Energy, Inc. - President [5]

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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 it may be even target-specific as well.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [6]

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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 at lot of locations. We're not very densely drilled in any area. So it gives us an opportunity to consider 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.

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Robert J. Anderson, Earthstone Energy, Inc. - President [7]

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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. 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.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [8]

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Okay. Got it. And then just an administrative question. I think the original budget for the Eagle Ford, those 7 wells, were 22% working interest, but they're 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?

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [9]

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It's actual increase in the working interest based on certain parties decision whether to participate or not participate in wells.

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Operator [10]

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Our next question is from Neal Dingmann from SunTrust.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [11]

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I'm looking at Slide 10, Rob, I guess my question, you all continue to see nice improvement, I think in here it talks about -- in particular it stands out, going from 5 stages to 9 stages per day. So you did mention I think in your remarks that well size costs you saw are staying near flattish, but I'm wondering from a, efficiency standpoint, you and Frank step back, are you continuing to see more of these improvements and, I guess, #1 are you seeing these, #2 are they built into your sort of estimates at all?

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Robert J. Anderson, Earthstone Energy, Inc. - President [12]

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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'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.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [13]

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Got it. 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 that is it just the cap structure you don't want to move leverage or I'm 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 look and has it got more popular?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [14]

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Well, I think, Neal, that the A&D markets are 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 a 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 are not going to go to a 3x or whatever have you EBITDAX the leverage ratio because in a commodity price drop you've seen what that has done to a lot of our brethren out there. So the 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 2 fundamental strengths that we followed over more than 3 decades for me and Robert's been with us 15 or 16 years and the other guys is control the things we can control, our operations and our balance sheet. So it's kind of a weasely 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 is 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 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 the -- I think we keep on saying to people is, why are you holding onto it? 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're just trying everything we can.

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Operator [15]

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Our next question is from John Aschenbeck from Seaport Global.

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John W. Aschenbeck, Seaport Global Securities LLC, Research Division - MD & Senior Analyst [16]

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Congrats on the quarter. 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 1 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?

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [17]

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Sure. Maybe I'll take a stab at that. It's Mark here and Robert can chime in if he wants too 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 late 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 start to get some additional pick up 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 it also depends on the exact time interval when we get wells online, et cetera. So we're thinking of it that way.

And really, I mean, honestly, we're probably -- I mean, we're 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 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, and some of that's timing and some of it is improvement in the amount of barrels we 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 online, they're 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, guidance of 65% oil, though we're a little above that here in the first quarter. It's probably trends down just a little bit until we get more wells online late in the year.

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John W. Aschenbeck, Seaport Global Securities LLC, Research Division - MD & Senior Analyst [18]

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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?

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [19]

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Well, I mean, we spent $42 million and change in the first quarter, and we had decent bit of completion activity. We probably won't spend a whole lot different than that in the second quarter, and then it will pick up in the third and fourth quarter.

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John W. Aschenbeck, Seaport Global Securities LLC, Research Division - MD & Senior Analyst [20]

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Okay, perfect. Then last one from me. I think Robert and Mark, you had some really good color on workover, so it's really helpful, helps explain the increased LOE. Just curious, how much did those workovers contribute to your Q1 production beat? And then apologize if I missed this, I think I did actually. But just how should we think about LOE in the future quarters? Is the full year guide a good estimate or just how should we think about it?

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Robert J. Anderson, Earthstone Energy, Inc. - President [21]

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John, probably it 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 the rest of the year on those specific assets. I don't know how to answer your second question.

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [22]

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Maybe, yes, in the terms of where we are in the range, I mean obviously we put out guidance on LOE of $5.25 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 lean towards the higher end of the range, yes. But just for context, we're 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 top in 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 fresh production much lower than what we reported for the quarter. So it's probably still tracking, but if you probably pin us down, we'd tell you it's closer to the upper end of the range versus the bottom end of the range.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [23]

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I'll say that one of the things that doesn't get necessarily up, a great deal of discussion in the marketplace and on these calls, and so forth, is what we've historically always tried to achieve also. Aside from efficient D&C 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 costs and operations are not necessarily variable, they're kind of step variable.

So we have 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. Aside from everything else we're trying to do, it's called maximize gross margins by minimizing your costs.

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John W. Aschenbeck, Seaport Global Securities LLC, Research Division - MD & Senior Analyst [24]

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That's the end goal at the end of the day.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [25]

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That's the goal.

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Operator [26]

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Our next question is from Jason Wangler from Imperial Capital.

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Jason Andrew Wangler, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [27]

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Robert, I wanted to ask you on the nonoperated side. I think you mentioned you had some interests in -- I think it was 5 zones. Could you maybe just expand on that program kind of the timing and then when you should maybe start to see some results from them?

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Robert J. Anderson, Earthstone Energy, Inc. - President [28]

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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 1 rig running. So 15 wells going to take a while to drill and then a while to complete depending on how many frac crews, and again, they may use 2 frac crews to complete those wells. So materially, I don't expect to see any production till next year.

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Jason Andrew Wangler, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [29]

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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 the 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?

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Robert J. Anderson, Earthstone Energy, Inc. - President [30]

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Yes, definitely, we'll have an impact on how we view our Midland County asset that's not too far south of where this activity is occurring.

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Operator [31]

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Our next question is from Ron Mills from Johnson Rice & Company.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [32]

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Robert, maybe just a quick follow-up on Jason's last question. I think we've talked in the past, particularly because of that nonop program. You said, I think, you have something like, I don't know, is it 30% average working interest in those wells. Are you still expecting to have about $50 million of your D&C budget really going towards projects that won't provide much productive impact this year, but really kind of set you up well for 2020?

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Robert J. Anderson, Earthstone Energy, Inc. - President [33]

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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're just getting started and they've only got 1 rig running. We kind of thought they might have more than 1 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.

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [34]

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But really Ron, I mean overall whether it's on our operated schedule or the non-op. I mean we have got no new information now versus our call 7 or 8 few 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 timing assumptions really run anything for this year.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [35]

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Okay. And then I cannot remember if it was Robert or Frank that mentioned earlier, you talked about potentially going to a second rig. I think on your last call you talked about looking at growth versus free cash flow, were 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 in the ground versus just trying to solve for our free cash flow situation?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [36]

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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 talk to a lot of folks and we have some that say that the free cash flow deal is not as important as efficient growth and additions to prove reserves. So rather than -- so I would say, it is an 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. Probably another year. 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'll 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% interest, rather than a 22% interest. I don't want anybody to think that some of our partners not having concern on those wells is a function of economics. The economics on those wells are very, very, very strong. And these wells 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, Pen Ranch right now, which well are we on on Pen Ranch?

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Robert J. Anderson, Earthstone Energy, Inc. - President [37]

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The second well.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [38]

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Well, the second well. So unfortunately in the operating environment and with partners, and in the case of West Texas with the nonop program, we are dealing with the opportunities that are available to us on a daily basis. So we just kind of wanted to throw it out there. So anyway the sum total of that is, if the economics are strong, we're adding proved reserves, okay. 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 will consider second rig later on this year. I don't know how to say that.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [39]

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Well, put me in the camp of the things outspending for economic growth is a far better use of capital. Then one last, 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 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 end kind of more of a wine rack formation?

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Robert J. Anderson, Earthstone Energy, Inc. - President [40]

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Yes, that's right Ron, we were drilling an A and 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.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [41]

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Okay. Great. And then when you were talking about widening out in some upcoming tests, 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?

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Robert J. Anderson, Earthstone Energy, Inc. - President [42]

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That's the wine rack. So we're going to do a 3-well pad where we're basically 1,100 feet or so in the same bench, 550 feet between wells, so 2B uppers and a B lower.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [43]

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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 Joe Mill, et cetera, et cetera. But if you take a look at the charts we have out there, based on lateral lengths, we're now we think we have like 450 gross locations in the 8,750 to 10,000-foot plus range.

I want to point out that if you look at that, here's what Robert's got to correct me, if I'm wrong. If you look at that similar kind of chart 1.5 years ago-or-so, you would see 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?

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Robert J. Anderson, Earthstone Energy, Inc. - President [44]

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Absolutely. Yes, that's correct.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [45]

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I guess, that we had 30% or 40%, maybe 50% less than those -- in 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.

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Operator [46]

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Our next question is from Jeff Grampp from Northland Capital Markets.

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Jeffrey Scott Grampp, Northland Capital Markets, Research Division - MD & Senior Research Analyst [47]

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I think, Frank, on the last topic there on the lateral lengths, can you guys touch on, 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 to 10,000-foot laterals, given the accelerated development pace that you guys can potentially be in?

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [48]

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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 3 to 5 well pads or maybe 6 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. 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 can definitely can go out there and develop that unit further and it would have really good economics.

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Jeffrey Scott Grampp, Northland Capital Markets, Research Division - MD & Senior Research Analyst [49]

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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 cost movement down, I guess, 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 did the use of in-basin sand, either currently or prospectively in the future might change some of that math for you?

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Robert J. Anderson, Earthstone Energy, Inc. - President [50]

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You're right. We have not updated our type curve economics, so we've got some upside there because of the current efficiency is in 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 a 100% in-basin sand, but we're using probably 95%. We still pump a little bit of 30-50 at that tail end of our jobs and that's not in-basin, but the 100 mesh in 40-70s all in-basin sand.

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Operator [51]

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Our next question is from Gail Nicholson from Stephens.

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Gail Amanda Nicholson Dodds, Stephens Inc., Research Division - MD & Analyst [52]

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On those wider spacing tests that you're testing, are you doing anything different with the completion design?

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Robert J. Anderson, Earthstone Energy, Inc. - President [53]

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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 may be certain of our design factors change, the amount of fluid or things like that. I think there are some other things that we're going to consider in these frac designs that may change the way we are physically pumping the job, but the sizes probably stay about the same.

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Gail Amanda Nicholson Dodds, Stephens Inc., Research Division - MD & Analyst [54]

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Okay. Great. And then you guys have a very successful hedging history. I think you have great hedges that were put on in '19. I think there are some incremental hedges in 2020. Can you just talk about kind of your hedging strategy going forward?

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [55]

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Sure. First, we do have some nice hedges on. We'd love for them to be out of the money because that will make prices very much higher, but really, I mean, we are more hedged for 2019 then we probably typically will be and that was largely a result of adding some hedges around, having announced the Sabalo deal last fall when prices were high. And kind of being left with some pretty nice hedges whenever prices fell, which happened in that deal.

In terms of going forward, I mean, we're definitely thinking 18 to 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 it was mid-April, we added some hedges for 2020, I think, we put 1,000 barrels on a day at $59.75 and plus $0.25 on the Mid-Cush basis. We obviously like to hedge at higher prices than lower prices.

We're not adverse to hedging defensively, but we fortunately have been able to hedge kind of offensively and just get a decent bit 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 are thinking of things, but we do want 50% to 75% hedged in the current year and somewhere around half of that amount or so may be little more depending on the time of the year for the year out.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [56]

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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 once again an ongoing thought process with a substantive floor, if you will.

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Operator [57]

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(Operator Instructions) The next question here is from David Beard from Coker Palmer.

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David Earl Beard, Coker & Palmer Investment Securities, Inc., Research Division - Director of Research & Senior Analyst of Exploration and Production [58]

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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. It would seem if capital markets are shut, you probably have to do a 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 go a little bit differently?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [59]

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No. We've been enhancing our staffing with the addition of folks like Mark and Scott from Capital Markets and from debt margin standpoint. I have been kind of standing back a little bit on those things to consider it. So this is maybe just some thoughts, but the way we conducted our lives in the past, is as we go out there and do deals, we'd increase our debt component. The worst I think I've ever had was a 2.7 ratio of debt-to-EBITDAX. That's been -- 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 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 Alec here, turn that back on all 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 consider debt financing. We need to consider utilizing our stock periodically for good deals that make sense and facilitate things like scale, 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 mealy-mouth way 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 position. So we keep on working at it. I cannot answer that any better, David, I'm sorry.

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David Earl Beard, Coker & Palmer Investment Securities, Inc., Research Division - Director of Research & Senior Analyst of Exploration and Production [60]

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I had a -- just sort of your read on the current market and obviously it changes and all that, but definitely appreciate the color.

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Operator [61]

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This concludes the question-and-answer session. I'd like to turn the floor back to management for any closing comments.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [62]

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I think we pretty much said it all. We appreciate you folks dialing in. We'll 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 to increase gross margins, and hopefully, have a lot of positive quarters like this in the future. So thank you very much.

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Operator [63]

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