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Edited Transcript of ESTE earnings conference call or presentation 13-Mar-19 3:00pm GMT

Q4 2018 Earthstone Energy Inc Earnings Call

DENVER Mar 19, 2019 (Thomson StreetEvents) -- Edited Transcript of Earthstone Energy Inc earnings conference call or presentation Wednesday, March 13, 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

* Jason Andrew Wangler

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

* Joel P. Musante

Alliance Global Partners, Research Division - Director of Research & 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 call 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. 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 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 Exchange Act of 1933 as amended and Section 21E of the Securities and Exchange Act of 1934 as amended. Although management believes these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in the earnings announcement we released yesterday and in our annual report on Form 10-K for 2018.

These documents can be found in the Investors section of our website, www.earthstoneenergy.com, along with an updated corporate presentation. 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 yesterday. Also please note information recorded on this call speaks only as of today, March 13, 2019. Thus, any time-sensitive information may no longer be accurate at the time of any replay.

A replay of today's call will be available via webcast by going to the Investors section of Earthstone's website and also by telephone replay. You can find information about how to access those on our earnings announcement released yesterday.

Today's call will begin with remarks from Frank, providing an overview of our activities and future plans, followed by remarks from Mark regarding financial performance and matters, 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. Thank you, Scott, and thank you for all of you folks that are on the line. We made great progress developing our Permian Basin assets in 2018 and have high expectations for '19. Before we get into the details, I'd like to remind you that a couple of weeks ago, we put out a press release related to our reserves and also tell you that yesterday, we posted an updated presentation for the company as a whole on our webpage. In that presentation, I'd like to refer you to Page 8 in particular to demonstrate the progress that we've made over the last couple of years.

Using 2016 as a base, in 2017 and 2018, we increased our average daily production by over 260%. We've increased our adjusted EBITDAX fivefold. We've cut our lease operating expenses in half, and we've lowered our G&A per BOE by about 10%. We -- our expectations is that we can continue to do those types of things, at least that we're working very hard to do so. We've accomplished all of that in a couple of years, while ending up 2018 with a debt-to-adjusted EBITDAX ratio of 0.8:1. So we're under levered, strong cash flows and looking forward to '19.

During '18, we substantially increased our proved reserves and production. And as mentioned, we've reduced our administrative costs and LOE on a per unit basis. We've also increased our efficiencies in our drilling and completion operations, and we are targeting free cash flow in 2020, if not before. Our balance sheet remains very strong, and we have substantial liquidity. We've set our 2019 capital budget at about $190 million, which assumes a 1-rig operated program and nonoperated activities as they are currently proposed by operators. We also have some minor activity in our operated Eagle Ford.

As we've demonstrated in '18, we will continue to effectively exploit our asset base while we enhance our acreage and increase production through acreage trades, drilling and completions and acquisitions that will continue to allow longer laterals and even greater efficiencies. And of course, we'll continue to pursue significant transactions to build scale and market relevance. But I do want to stress that we will also remain capital-disciplined and only pursue acquisitions that we believe will create substantial value for our shareholders.

I'll turn this call over to Robert to provide some added highlights. Then Mark will discuss financial matters, and Robert will follow up with details on operations. Mark -- Robert, I'm sorry.

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Robert J. Anderson, Earthstone Energy, Inc. - President [4]

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Thanks, Frank. A few highlights from last year. Our 2018 total net production grew 26% over 2017's volume to 3.6 million barrels of oil equivalent, just under 10,000 BOE a day. Our proved reserves grew 24% to 98.8 million BOE from 80 million BOE at the end of 2017, primarily through the drill bit, with approximately 22.3 million BOE of proved reserves added from extensions, discoveries and revisions. The efficient development of our quality acreage allowed us to generate a significant increase in adjusted EBITDAX, which grew to $96.2 million for the full year 2018 versus $60.6 million in 2017, an increase of almost 60%. Based on our capital expenditures for development activities, our extensions and discoveries of 16.2 million BOE in 2018 resulted in a finding and development cost of just $9.49 per BOE of proved reserves. And our overall finding and development costs, including acquisitions, amounted to $7.79 per BOE of proved reserves.

As we evaluate what we've learned in almost 2 years of operating our position in the Permian, we are pleased with the well performance and the quality of our acreage position and are targeting even greater operating improvements and efficiencies. We expect to build production without proportionate increases in fixed operating and administrative costs, which will continue to drive down costs on a per BOE basis and increase margins. We continue to work on our acreage position to accommodate longer laterals and increase our operated footprint. As an example, for 2019, we expect to complete wells with an average lateral length of close to 9,600 feet, which will be more than a 20% increase in lateral lengths compared to 2018 completions. And our 2019 completion program is somewhat back-end weighted, and as mentioned, we expect to be able to cross into free cash flow territory in 2020 based on our 1-rig Midland Basin program, with moderate non-op activity and assuming a similar commodity price as we are currently experiencing.

With that said, I'll turn it over to Mark for a review of our financials.

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [5]

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Thank you, Robert. Looking at our financial metrics for the quarter and starting with the top line, revenues of $41.2 million were up 16% over Q4 2017 and down 11% sequentially compared to the third quarter of 2018. The sequential revenue decline was due largely to a decline in realized prices in the fourth quarter compared to the third quarter. Our fourth quarter 2018 production of 10,454 BOE per day was negatively impacted by approximately 1,100 BOE per day of production that was shut in across 11 gross operated and 3 gross nonoperated wells during the period due to offset completion activity.

We're projecting that production for 2019 will average approximately 11,000 to 12,000 BOE per day, which is an 11% to 20% increase over 2018 results.

Our production mix during the fourth quarter reflected a higher crude component at about 70% crude, with NGLs coming in at about 17% and natural gas making up the balance. This compares to our mix for full year 2018 of 65% oil, which is in line with our 2019 expectations for a mix of about 65% oil, 19% NGLs and 16% natural gas.

We reported fourth quarter 2018 net income of $81 million or $1.26 per share. Fourth quarter net income includes a $96 million unrealized gain on the mark-to-market of our hedges and $12.6 million in transaction costs, largely related to our proposed transaction with Sabalo Energy, which was terminated in December. For the year, we reported net income of $95.2 million or $1.50 per share.

Adjusted EBITDAX, as we define and report it, was $23.9 million in the fourth quarter of 2018, down from $26.4 million in the third quarter and up from $22.1 million in the fourth quarter of 2017. For the full year, adjusted EBITDAX grew 59% to $96.2 million from 2017's $60.6 million. LOE per BOE for the fourth quarter was $6.25. For full year 2018, LOE averaged $5.66 per BOE, continuing a downward trend compared to $6.84 per BOE in 2017. We anticipate average LOE per BOE in 2019 of $5.25 to $5.75 per BOE and are continually striving for improvement. Our G&A, excluding stock-based compensation for 2018, was just over $21 million, relatively flat versus 2017's $20.5 million. This includes a fourth quarter accrual of $2.4 million for annual cash incentive compensation that was paid out in the first quarter of 2019 but accrued as an expense in the fourth quarter of 2018. Our G&A per BOE metrics excluding stock-based compensation averaged $5.81 per BOE for the full year. We are presently guiding toward projected G&A per BOE in 2019 of $5 to $5.50. We do continue to focus on managing our cost structure as efficiently as possibly -- as possible.

Now moving to the balance sheet and liquidity. During the fourth quarter, we closed on the acreage trade and acquisition in Reagan County for approximately $28 million. This was largely funded with additional borrowings from our credit facility, which in November, saw the borrowing base increased by $50 million up to the current $275 million borrowing base. At December 31, 2018, the company had outstanding borrowings under the credit facility of $78.8 million and a cash balance of approximately $0.4 million. This leaves us with almost $200 million of undrawn capacity on our credit facility, so our liquidity remains very strong. Our capital expenditures for the fourth quarter totaled $41.4 million, resulting in full year capital expenditures of approximately $153.2 million excluding acquisitions. As Frank mentioned, in 2019, we expect total CapEx to be approximately $190 million. We're very well hedged at favorable prices for 2019 and 2020, with swaps in place for 2019 on 84% of the midpoint of our 2019 oil guidance at an average price of $65.67. And we've got a decent bit hedged in 2020 at even slightly higher prices on the oil side.

So with that, I'll turn it over to Robert to review operations.

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Robert J. Anderson, Earthstone Energy, Inc. - President [6]

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Thanks. As we've highlighted, we're proud of our operational accomplishments in 2018. And in 2019, we will continue to focus on effectively executing our 1-rig program. During 2018, we maintained a 1-rig program throughout the year and drilled 16 wells, with an average working interest of 89%, and we completed 19 wells in Midland, Reagan and Upton counties with a 79% average working interest. These wells targeted multiple formations, including the Lower Spraberry and Wolfcamp A, B and C intervals, with an average lateral length of 7,900 feet. Our well performance on average is in line with or exceeding our type curves and is expected to generate attractive well level economics in the current commodity price environment, even before considering our oil-hedged position, averaging close to $66 per barrel in both 2019 and 2020.

In the fourth quarter, we completed 8 gross, 6.7 net wells, including 3 gross wells that were completed in late December. We ended the year with 6 gross, 4.2 net wells in progress, which includes both operated and nonoperated activity, all of which are now online and producing.

Let me highlight a 3-well pad we completed in Western Reagan County in late December. It is our Sinclair unit, where we hold a 93% working interest. The average lateral length of those 3 wells was 6,883 feet, and the wells were completed in the Wolfcamp A, B Upper and B Lower. These wells offset 2 existing Wolfcamp B wells, with the closest offset being approximately 775 feet in the same target. After about 70 days of production, the new wells are still increasing in rate and have not hit their peak 30-day rates yet. We have experienced this in the past, and it's quite common with Wolfcamp A completions, but extended time to peak rates on the Wolfcamp B zones is likely due to the existing Wolfcamp B producers in the unit, which have been producing since May of 2017. Although these 3 new wells are still cleaning up, current 30-day rates are ranging from 400 BOE to 800 BOE per day, with oil cuts of 78% to 88%. They are starting out at a little lower rates than the prior wells. However, 2 of the 3 wells are performing in line with our expectations. The -- for instance, the B Upper well is tracking the 2 original completions. Although those -- these 2 original completions have only been producing for around 20 months, we expect them to average an ultimate recovery of approximately 110 barrels of oil equivalent per foot. I will also note that the 2 original wells were shut in during the fracking of the 3 new wells but are now back online and producing as expected.

Our takeaway from these results is that we are still evaluating our operations to determine the parent-child well issues as it relates to optimum spacing between wells, co-development of multiple benches and frac design when completing new wells and existing units. Each area and each bench will be somewhat unique. We are, however, comfortable with 660-foot spacing in certain areas and recognize that we may need wider spacing in other areas in order to achieve acceptable economics. These lessons and what we've observed from industry well data are driving decisions for our future development program. The good news is that we have not been aggressive in our spacing practices nor in the number of benches we can complete economically.

Having operated our Midland Basin asset for close to 2 years now, we are seeing tangible improvement in operational metrics as our team has focused on maximizing efficiency and reducing costs on both a relative and absolute basis.

If you refer to our presentation on our website, Page 9 has similar statistics that I'm about to go through. We've been able to achieve significant cost reductions in drilling completion and production operations in 2018 by improving efficiency of our operations. We drilled the last 8 wells in 2018 from spud-to-rig release in an average of 15.3 days, with an average completed lateral length of 8,632 feet, which is a 30% reduction in time compared to the second half of 2017 despite increasing the lateral length by 11%.

On the completion side, efficiency gains were even more substantial. In January 2018, we were completing multi-well pads at 5.7 stages per day. But by year-end, we were up to 8.2 stages per day, a 44% increase in stages per day, and we recently finished fracing a 2-well pad averaging 9 stages per day. From a cost standpoint, our last 3 wells completed in early 2019 averaged an all-in frac cost under $62,000 per stage, which is down from $85,000 to $90,000 per stage last summer, driven by both our improving operating efficiencies but also cost reductions from our shift to using more in-basin sand. For our operated program, we expect to spud 16 wells in 2019, with an average working interest of 85%, while completing 13 wells with an average working interest of 86%. Our 2019 focus is on the Wolfcamp A and B zones, which have proven results across our acreage positions.

Currently, our rig is in Midland County, drilling 5 Wolfcamp wells in our Mid-States unit, where we have a 67% working interest. We're also participating in a 2 Wolfcamp wells just offsetting this unit, where we have a 35% working interest.

All of these wells will be approximately 10,000-foot laterals as a direct result of land trades we did during 2018. We have completed 3 wells so far in the first quarter of 2019: 2 in Upton County, each with a 100% working interest that are beginning to flow back; and 1 in Central Reagan County, that has been online for less than 30 days, where we have an 89% working interest. So first production dates for the remaining 10 operated wells expected to be online over the balance of 2019, are the 5 Midland County wells in the third quarter and then the final 5 wells in November and December of this year. We expect production growth in 2019 will result from a total of 16 new wells, including the 3 Sinclair wells that came online right at the end of 2018.

And we plan to end 2019 with 4 gross, 3.4 net operated wells drilled and waiting on completion. As mentioned, our 2019 capital budget is $190 million, which includes $118 million from our operated Midland Basin 1-rig program and $47 million for nonoperated activity in the Midland Basin. We are also targeting $10 million for our operated Eagle Ford activity. Given the second half weighting of our completions, approximately $50 million of our 2019 capital is applicable to production growth for 2020 rather than 2019, which should position us really well to end the year and begin 2018 -- 2020. We will continue to pursue acreage trades in the Southern Midland Basin, with the intent of increasing our operated acreage and drilling inventory, with a focus on longer laterals and realizing greater operating efficiency. Our strong balance sheet supports potential acquisitions as well, and as we have demonstrated, we intend on being strategic and disciplined in pursuit of growth. We have an attractive acreage position, and corporate level returns will benefit from our efficient operations and our hedge position.

As I have already mentioned, our program is currently designed to reach positive cash flow in 2020 under our 1-rig program and current commodity prices, while maintaining our low leverage profile. Frank, you want to wrap this up?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [7]

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Sure. We've said it twice, and I'll say it a third time, we are targeting positive free cash flow. We're also highly aware of the market concerns about the so-called parent-child effect on well economics. I want to point out specifically that our acreage positions are very lightly drilled, and we continue to evaluate both industry results and our practices in order to mitigate the effects of our prior -- of prior production on new wells.

Once again, to be redundant, based on our results to date, we believe our location count and type curves are reasonable and achievable. Finally, I want to stress that our fundamental practices for more than 3 decades in multiple basins have been to control those items that we can on a daily basis. Meaning, to maintain a strong balance sheet and focus clearly on effective and cost-efficient operations that generate good shareholder returns. We'll continue to work diligently to increase our scale through acquisitions and mergers but only if transactions are accretive and provide value for our shareholders.

Thanks for listening to our prepared remarks. And now, operator, we'll take any questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from the line of Neal Dingmann with SunTrust.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [2]

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Robert, my question is for you. Could you talk a little bit how you plan to -- I know you mentioned the sort of cadence, but how you plan to, sort of, cluster the wells going forward like you have in the past?

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

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Sure, Neal. Like I said, we've got 5 wells in Midland County we're in the process of drilling right now. Those will all be completed at one time. And then the last 5 wells we get completed this year will probably be a 3-well area and then a 2-well following that in a little bit separate area. So again, that's how part of our completion efficiency works is that we don't try and do one-off wells, we try and do them in groups or batches and definitely on a pad basis, you've got to do that. But that's the way we planned out our year.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [4]

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And then could you talk maybe, Frank, just about your thoughts about organic growth versus M&A if free cash flow ends up being a bit better than expected?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [5]

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Well, Neal, you've known us for a long time. I'll try to do this distinctly. Our primary focus on a day-to-day basis is to do acreage trades and acreage -- and maybe smaller-acreage acquisitions that block up some of our current acreage positions and move to longer laterals. You can see that I think we've achieved -- although, we have some where there's -- I'm babbling. There is a presentation in our webpage that shows what our inventory is by lateral length, and I think if you compare that to prior that we put out there, you'll see that our count towards longer laterals is improving. So we're going to do that on a daily basis. We are in the market every day to look for larger accretive positions, whether that's M&A or whether it's large acreage acquisitions. The trick there, of course, is to build the scale that the market and the analysts are looking for without overleveraging the balance sheet, and that's easier said than done. But we're at it every day. We had a great acquisition last year, and unfortunately, in the fourth quarter, had a perfect storm. So we're not going to do something and -- just to overleverage the company. But I don't know how to answer that any better, Neal.

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Operator [6]

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Our next question is from the line of Brad Heffern with RBC Capital Markets.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [7]

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Robert, I wanted to dig in a little bit more on the Sinclair unit. It sounded like maybe it's the B Lower well that the one -- that's the one that's not performing on type curve, so I was just curious if you have any thoughts about having 2 targets in the B? Or whether that test makes you think that maybe there's only 1 in sort of a full-field co-development mode?

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Robert J. Anderson, Earthstone Energy, Inc. - President [8]

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Brad, that's -- that is quite possible. But we're still trying to figure out if you adjust spacing, maybe you do decrease the total number of wells but you still have multiple targets within the B. It's definitely thick enough where we can see the oil in place and the ability to go drill 2 wells. Again, it's just how close they are together.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [9]

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Okay, got it. And then I guess, on the other side of the M&A question. I guess, any new thoughts about the Eagle Ford and how it fits in longer term?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [10]

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We continue to consider that every day. We're not going to expand in the Eagle Ford. We'll maintain our acreage position or the preponderance of our acreage position. There is some offset activity that -- from a production standpoint and from some, lack of a better word, science that was put on some of those wells, looks encouraging. We have a small program that is like $10 million or $11 million. I don't see us putting a lot of money into it, and I don't see us, right now, of being an aggregator in the Eagle Ford. Pending commodity prices, offset activity, it will likely become a divestiture candidate at some point.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [11]

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Okay. And then one more, if I could sneak it in. Just on the LOE for the fourth quarter, it's certainly elevated versus the third quarter on a per BOE basis. So I was just wondering what that was. Was it workovers? Obviously, it's higher than the guidance for 2019.

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

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Yes, I think part of it, Brad, was a relative -- the relationship of how much our vertical wells cost and the trade that we did ended up with some of that causing us a little higher LOE in the fourth quarter. There's nothing that stands out where we had unusual workover expenses or anything like that.

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Operator [13]

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The next question is from the line of John Aschenbeck of Seaport Global Securities.

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John W. Aschenbeck, Seaport Global Securities LLC, Research Division - MD & Senior Analyst [14]

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For my first one, Robert, I was hoping to follow up on your remarks on parent-child well interference. And just curious if your ultimate conclusion there is that you need to move to a multi-zone development going forward. How quickly could you flex your plan? I suppose the limiting factor would be drilling obligations. And then also, how do you think about feathering in tests of your less-delineated intervals if you do pursue kind of a multi-zone development going forward?

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Robert J. Anderson, Earthstone Energy, Inc. - President [15]

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John, we're -- we do have some obligations this year, and they're built into our plan, obviously. We are fully developing the A and B in our Midland County asset where we operate, and so that'll be completely drilled up. And so we're taking it into account where it makes sense, but it won't happen this year in terms of a co-development of multiple benches. The Sinclair was a good example for us to test, 3 benches in an area where we already had 2 wells producing. So it's a 2020 event where -- and we're already starting to plan on certain areas where we would co-develop and drill 5 wells in some kind of pattern and trying to figure out how to mitigate the parent-child relationship and ultimately, hurting the existing production and -- while maximizing the new wells also. Regarding testing, we feel pretty strongly that the 3 benches, for instance in Reagan and Upton County, the A and 2 benches in the B, all have good economics, and we're going to just stick with those 3. We're not going to do any testing. But we also recognize that certain benches in certain areas, like up in Midland County, where we might have a Middle Spraberry in one of our blocks of acreage, could be developed later or the Wolfcamp D in Reagan County with some recent results that look really enticing could be developed at a later time without being influenced by the existing parent wells or whatever development we have out there. So we're not planning on doing any testing. We're going to stick to what we'll call the money benches and develop those for the foreseeable future.

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

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Okay, got it. Great, that's helpful. Appreciate it. For my follow-up, I was hoping to dig a little deeper into some of your comments regarding achieving free cash flow in 2020. More of a conceptual question, if you will, in that I know the concept of free cash flow has gotten a lot of press in the industry recently, but it's certainly not the be all end all of value creation. So just curious, Frank, Robert, Mark, when you guys think about Earthstone today and where it is in its business life cycle, how important is reaching a state of free cash flow generation as opposed to maybe the benefits of continuing to grow, add some more scale to the business and then increase your future free cash flow-generating capabilities?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [17]

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Well, that's a -- okay, this is Frank. So if I had my druggers, I would keep on building up value provided, however, that we didn't get into the trap of being overlevered that so many of our peers have, unfortunately, experienced, okay? That said, after more than 3 decades of being an independent in 45 years, it's -- we're not smart-alecky enough to preach to the market. So if the markets want free cash flow, we're going to work really diligently to get there, while we continue to block up our acreage, increase our inventory, develop, perhaps, a prove-up over time, additional benches, solve this parent-child relationship, such that when the market perceptions change -- and the staffing here, and the staffing here, such that when and if market perceptions change, we can bring on that second rig or that third rig or whatever have you. But right now, it's the old adage of not trying to sell ice to Eskimos.

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [18]

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John, it's Mark. I'll just follow up just with a couple of comments. One, just rest assured that we're thinking about how to create shareholder value every day. And clearly, in the last year or so, the focus on free cash flow from investors has been heard by all E&P companies, large and small. Certainly enough, not all E&P companies have all the same characteristics, and we don't think that -- we could go and cut our drilling programs tomorrow and achieve free cash flow, but we don't think that's a panacea for all that could possibly ail the E&P industry. To your point of, well, if you have a little more outspend, you've got more cash flow per share in a few years versus otherwise, part of the math would seem to say that, well, investors are asking for free cash flow, in order to have a similar stock price, they've got to trade at a couple -- at a higher multiple in a couple of years. We don't know what it looks like in a couple of years. And certainly, the industry has digested that and this earnings season, we've seen plenty of guys cut and maybe experience some frustration what the reaction from the investors initially. How that plays out over 2 years may be a different story. But we're thinking through this every day and looking for the best way to create shareholder value. We don't know what that is in 2020. We know we're positioned to -- with a lot of great options in terms of with our program, we think we'll be free cash flow positive. But we certainly have a great inventory and continue to learn more about our asset, improve our operations, where whether it's organically or through acquisitions, there's other things that we've got the options of doing.

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Operator [19]

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The next question is from the line of Ron Mills with Johnson Rice & Company.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [20]

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A couple of questions, really follow-ons to earlier ones. I just want to make sure I understand on the parent-child issues, Robert. You're referencing not just spacing with each -- within each formation but also relative spacing between the different formations, whether it's the A or the Upper or Lower B, is that a fair representation?

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

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Yes, it is, Ron. We worry about vertical spacing as well as horizontal -- into horizontal sense too. So not only 660 feet between 2 wells in the same bench but what is that distance between an A and a B Upper and a B Upper and a B Lower. And we're going through that exercise with things we're doing and learning and then what the industry is telling us as well in terms of their data.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [22]

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And in reference to the earlier question about the Lower B on the Sinclair pad, do you -- in your response, you talked about you still think the Lower B is thick enough to support a couple of different laterals in -- as you go back and review the, at least, early data there, is there something about the targeted lateral zone? How is your lateral target compared to any offset operators that may be in the area? And how can you go back and optimize that in future activity?

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Robert J. Anderson, Earthstone Energy, Inc. - President [23]

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Yes, it's a good question. But we have been pretty consistent about where we're landing our wells. And every area is a little different just because of the geology local to an area. In this particular area, we landed our Lower B in the same as the original Lower B well, same with the Upper B. So there's nothing different about that. Again, it's just how widely spaced do wells need to be. I'll make one kind of global comment is that we have a large number of sticks, so we have a lot of locations. Obviously, not all of those are proved, and our proved undeveloped locations, our puds, are on a lot wider spacing than 660 feet. So if we determine down the road that, that is too tightly spaced, it doesn't affect our proved reserves in any event at all.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [24]

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Yes, Ron, as you know by knowing us over the years, we've never been "aggressive" in our reserves or our sticks. We think these are reasonable and achievable, but this is an issue that you just can't wake up on Monday and have solved with all the drilling in different areas and slightly different geology and so forth, all I wanted to do was point out that we are very cognizant of it. We don't think we have been aggressive in the information we've put out there and let you guys know that we're studying it every day.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [25]

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Great. And then just when I look at Slide 14 of your presentation where you have your inventory then on those gross locations, that includes both booked and unbooked locations, right, Robert?

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Robert J. Anderson, Earthstone Energy, Inc. - President [26]

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Yes, it's proved and nonproved locations, that's exactly right.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [27]

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And do those -- I know your proved, you said are still booked well above the 660-foot spacing. But when we look at this particular table, should we assume from a proved and nonproved standpoint, you move down to 660, or is that unfair?

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

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In general terms, this layout of number of locations is based on 660-foot spacing.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [29]

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Okay, great. And then, Frank, as it relates to acquisitions, the Sabalo deal was one where you -- I think you were kind of going down the path where, hey, we have our balance sheet, we're not afraid to use it for the right kind of acquisition as long as there's line of sight to get your leverage ratio back to an acceptable level for you within a reasonable time frame. So given the -- what happened with commodity prices since then and walking away from that deal, I assume that's not the only deal in the basin that suffered a similar fate due to pricing. So if you had to weigh an opportunity set for larger transactions, how does it look today versus even 5 or 6 months ago when you were set to announce that past deal?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [30]

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Well, I'll say that, that probably changes out there every week, our sentiment changes. I'll say that there's a lot of things that we'd like to chase, there's some that we are chasing, none of which were as large as the transaction we were on. It's all a matter of a buyer and seller sentiment. And it's -- and the secondary matter is that we're not going to let our balance sheet get out of control. So I just can't tell you. We have to find some deals out there that have a good production component because the last thing we're going to do is buy 20,000 acres on debt, right? A noncash flowing asset on debt. So we're just on it every day. We're working hard on stressing to folks that we have a long track record that the core -- I shouldn't say the core with Mark here, that the longer-term executives that have been together have done this repeatedly over time, that we brought in folks like Mark and Scott and others that we can double our production without doubling our G&A. So we're out there every day. I don't know what else to tell you.

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Operator [31]

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The next question is from the line of Joel Musante with Alliance Global Partners.

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Joel P. Musante, Alliance Global Partners, Research Division - Director of Research & Senior Research Analyst [32]

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I just had a question on the -- given your back-end weighted development program, I was just wondering if you can give us an exit rate for the year? What that might look like?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [33]

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Hey, Joel. Since we've known each other so long, I'll just say no.

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Robert J. Anderson, Earthstone Energy, Inc. - President [34]

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I was going to say higher.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [35]

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Higher? No, no. Higher than this? Okay, that's good. Higher than this year?.

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [36]

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Joel, I mean I would say directionally, and we're not going to give what an exit number is, but directionally, with the back end weighting, there is fairly flat to moderate growth the first half of the year in the quarterly production rate, and we expect that to start growing a bit more substantially in the third and fourth quarter.

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Joel P. Musante, Alliance Global Partners, Research Division - Director of Research & Senior Research Analyst [37]

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Okay. And do you foresee any maybe downtime from offsetting completion activity during any period that you might want to...

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

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Well, you would have to kind of factor that in. I think we've built in a little bit of lag -- just some general lags into our models. Our models are dependent, of course, on commodity prices, availability of high-quality services. And we can't really forecast at all when some offset operator is going to be fracing, and we have to -- it's just a situation that all of us in the industry have to deal with. It's an unpredictable situation.

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Mark Lumpkin, Earthstone Energy, Inc. - Executive VP & CFO [39]

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We do think we have a much better kind of handle on that in what might look like on average. The fourth quarter, no doubt, was a bad confluence of events that led to the 1,100 BOE per day. That was shut in due to offsetting fracs. With the guidance that we put out in January, we did embed some risk factor into that, that we clearly hadn't done a very good job of before. And as Robert mentioned, we've been operating these assets for less than 2 years. And if you think about that, 2018 was the first full calendar year we were operating the assets. Operationally, we've continued to improve and really, from a modeling standpoint, we understand the asset better and what can go wrong, and we think we've accounted for that in an appropriate and reasonable manner in our guidance.

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

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The other thing I'll say, Joel, is where our plan is this year in terms of the physical locations, at least as far as it relates to our own properties and where we're going to have to shut in our own offset producers, we have limited number of wells where that's the case. We could get some issues from offset operators who've frac wells have some impact on us, and that's where we're going to have limited line of sight on when that could occur.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [41]

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So, Robert, for Joel and whom else is out there, at Mid-States, where we're going to have 5 wells and we're going to start fracing when?

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

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About June.

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

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About June. Right now, we don't see problems associated with those, right?

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

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No, no.

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

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It just depends on what offset guys are doing.

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Robert J. Anderson, Earthstone Energy, Inc. - President [46]

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Exactly.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [47]

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So that could be delayed, it could be shut in, it could be whatever. That's just the issues that the industry has to deal with, particularly us smaller companies out there.

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Joel P. Musante, Alliance Global Partners, Research Division - Director of Research & Senior Research Analyst [48]

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Right, right. Okay. And then just one last one. On -- you mentioned that you want to achieve cash flow neutrality, and that would be based on a similar program next year to this year, does that include the non-op activity, or is that just operated?

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Robert J. Anderson, Earthstone Energy, Inc. - President [49]

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It includes non-op activity at a lower CapEx in 2020 than this year. We kind of think that this year is a little bit of anomalously high. But again, we have good some non-op assets, and if 2020 rolls around and somebody says, "Hey, we want to go drill 10 wells in a particular area," we'll look at the economics and make sure it makes sense. And if it does, then we will participate, and our capital expenditures would be higher than kind of what we're -- a normal run rate, whatever normal is.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [50]

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Yes, we think that $45 million, $47 million for non-op this year is -- may be high on a continuing basis. And, Joel, no guarantees, but you look like back in whatever it was, September, October we did that trade of non-op for op. We're always looking to increase our op position. We like operating, as you know. And maybe some of the trades we can do this year will enhance that. So we'll be more solidly in control of our capital budget. But then like Robert says, the non-op stuff is looking pretty good, and we'd be shooting ourselves in the head this year if we didn't participate.

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Joel P. Musante, Alliance Global Partners, Research Division - Director of Research & Senior Research Analyst [51]

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Okay. Yes, it looked like it was pretty high working interest. So...

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Operator [52]

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Our next question is from the line of Jason Wangler with Imperial Capital.

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Jason Andrew Wangler, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [53]

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Maybe the dovetail on Joel's question on the non- side, is -- a lot of that acreage capture, perhaps, or is it just simply some opportunities that are there from the operators and you guys are coming along that makes that number maybe higher than as you look at 2020 or beyond?

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Robert J. Anderson, Earthstone Energy, Inc. - President [54]

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It's where an operator has gotten around to certain trades or what have you in order to drill 10,000-foot laterals and the ability to go out there now and implement it in their plan in -- that's in one particular case. The other case, where we have a big acreage block, and we're participating. And again, it fit into their planning cycle, and it's happening this year.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [55]

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Yes, so I don't think -- I don't know what you mean by acreage capture, but this is not -- but this is, for lack of a better word, this is discretionary or optional on our part.

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Jason Andrew Wangler, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [56]

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Got it.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [57]

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But it's good areas and things that we want to participate in.

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Robert J. Anderson, Earthstone Energy, Inc. - President [58]

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Yes.

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Jason Andrew Wangler, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [59]

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Okay, so it's more of -- like you said, it's more of a timing thing and it just happens that it's right now?

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Robert J. Anderson, Earthstone Energy, Inc. - President [60]

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Exactly.

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Jason Andrew Wangler, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [61]

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And, Robert, on the operated side, obviously, it's a few months off, I guess. But as you look at the completions and things, I'm assuming that it's pretty easy to kind of get into a calendar in things now. But how do you kind of think about setting up the batch completions and things as they are a few months off going into later this year? Is there -- can you get those plans now or just kind of the thought process there to kind of get them in line with your expectations?

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Robert J. Anderson, Earthstone Energy, Inc. - President [62]

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No, they're planned. We worked very closely with one frac company to integrate our timing with their schedule and to make sure that we're -- we've had it nailed down pretty -- as close as possible. I would say that if oil prices all of a sudden skyrocket, their demands may go up, but my guess is they have a pretty full schedule for the full year of a frac fleet, and they know when our schedule and theirs, the timing works out. So it's -- we've planned the whole year out with the frac company and the other service companies.

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Operator [63]

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(Operator Instructions) Our next question is from the line of David Beard with 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 [64]

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Maybe just going back to the well count, and any color you could give relative to spacing assumptions in your well inventory. I think you'd mentioned some were at 660, but the puds were wider than 660, so I was a little confused. And maybe what percent of your inventory is at 660? Or if you're looking at spacing between zones, what's that just to give some color there so that we just better understand the assumptions behind the 866 gross well locations?

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Robert J. Anderson, Earthstone Energy, Inc. - President [65]

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David, this is Robert. I'll tell you that when we put out our reserves press release a couple of weeks ago, I think we said in here that there's -- I'm going off memory, 189 pud locations. But I think you could do some math there to kind of back into what that means compared to the 860. It's much wider spacing than we've even drilled wells on for our puds. And that's about all I'm going to say on that. 660 is the absolute 8 wells across a mile, and our puds are obviously spaced at much wider than that.

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Operator [66]

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It appears there are no further questions at this time, so I'd like to pass the floor back over to Mr. Lodzinski for any additional concluding comments.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman & CEO [67]

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The only concluding comments are thank you. We're always available to answer questions, and thank you for calling in. With that, we'll shut down.

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Operator [68]

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Thank you. Ladies and gentlemen, this does conclude today's teleconference. Again, we thank you for your participation, and you may disconnect your lines at this time.