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Edited Transcript of ESTE earnings conference call or presentation 6-Nov-17 4:00pm GMT

Q3 2017 Earthstone Energy Inc Earnings Call

DENVER Nov 8, 2017 (Thomson StreetEvents) -- Edited Transcript of Earthstone Energy Inc earnings conference call or presentation Monday, November 6, 2017 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Frank A. Lodzinski

Earthstone Energy, Inc. - Chairman, CEO & President

* Mark Lumpkin

Earthstone Energy, Inc. - CFO & Executive VP

* Robert J. Anderson

Earthstone Energy, Inc. - EVP of Corporate Development & Engineering

* Scott Thelander

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Conference Call Participants

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* Benjamin James Wyatt

Stephens Inc., Research Division - Senior Research 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

* Michael Dugan Kelly

Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research

* 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 Energies Third Quarter 2017 Conference Call. (Operator Instructions) As a reminder, this conference is being recorded.

Joining us today from Earthstone are Frank Lodzinski, President and CEO; Robert Anderson, Executive Vice President, Corporate Development and Engineering; Mark Lumpkin, Executive Vice President and Chief Financial Officer; and Scott Thelander, Director of Finance. Mr. Thelander, you may now begin.

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Scott Thelander, [2]

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Thank you, and welcome to our conference call. Before we get started, I need to disclose that the conference call today 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.

For a complete description of this disclaimer, please refer to our press release that was issued in connection with our third quarter 10-Q on November 2.

For a more detailed information about our company, listeners are encouraged to read our quarterly report on Form 10-Q for the quarter ended September 30, 2017 in its entirety, our earnings release posted through our website as well as all other reports and documents filed with the SEC. Our earnings release includes 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 release.

The content of today's call will include remarks from Frank regarding our activities and how we are positioned for profitable growth, remarks from Mark regarding financial matters and performance and remarks from Robert regarding operations.

I'll now turn the call over to Frank.

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

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Okay. Thanks, Scott. Good morning to everybody on the call. We're pleased to say that we now have our first full quarter of operations under our belt after closing a significant operated position in the Midland Basin just last May. We really begun to hit our stride in terms of the pace of drilling and completions with the 1 rig that we've been running since closing. We expect a steadier pace of completions, and therefore, production growth beginning this quarter and throughout 2018 as we have established an initial inventory of wells to be completed, the 5 wells to be completed. We have a deep inventory of higher economic operated positions, locations with over 500 gross locations on our operated Midland Basin position, targeting only 3 benches in the Wolfcamp A and B with significant upside potential in other identified Wolfcamp benches. Specifically, and one of the things that's very exciting to me in the nearest term is that we're seeing quite a bit of activity in Reagan County from other operators drilling and completing Wolfcamp C wells, which, as most of you know, we have not counted in our operated locations. We will consider drilling a C well in the future, perhaps in '18 as we see additional results offsetting our acreage.

Beyond the C, we also see other benches as potential inventory additions in the future. Those are kind of laid out and delineated in our updated corporate presentation that we put on our webpage just last Friday. Mark will tell you about some of our current corporate streamlining activities. But consistent with our continued shift to be a Midland Basin-focused operator, aside from the streamlining we've accomplished to date, we are considering the divestiture of our non-operated Bakken assets and perhaps could transact in the very near term should we find a buyer on an acceptable price.

In summary, our employees, both in Houston and in Midland, are executing our plan exceptionally well, and our focus and pace of growth in the Midland Basin is on track. We will continue to look towards profitable growth, both organically and through M&A while being responsible stewards of our financial capital.

I'll now introduce you to Mark Lumpkin who recently joined us as EVP and CFO and will provide a brief summary of our operational and financial results for the third quarter of '17.

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

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Thank you, Frank. From a production standpoint, things really are going well with 9,671 BOE per day of production in the third quarter. Assuming our current frac schedule remains on place, we're expecting to meet our guidance for this year. This is despite close to 500 BOE per day of reduced production in the third quarter, resulting from the temporary shutin of certain wells due to offset completion activity in the Midland Basin, and to a lesser degree, to reduce production resulting from Hurricane Harvey.

In order to position ourselves strongly as we enter 2018, we recently completed an equity offering of 4.5 million shares that resulted in net proceeds of $39.2 million after estimated expenses. We'll enter 2018 with limited debt after having further strengthened our already strong balance sheet.

Our significant liquidity and projected 2018 cash flow positions us well to add acreage and other acquisitions in 2018. And to continue to drill and complete our high-margin properties with the financial optionalities that would allow us to add a second rig in the Midland Basin in 2018, pending our assessment of returns in the current commodity price environment.

As part of our corporate streamlining which Frank mentioned, year-to-date, we've realized about $8.1 million of cash proceeds from divestitures. The producing properties that we've sold were gassy, low-margin legacy gas builds that contributed about 341 BOE per day of production and comprise of about 64% gas.

As we projected, economies that we're creating in the company are having a positive impacted on our financial performance. LOE and cash-based G&A on a per-BOE basis for the third quarter were $6.08 and $6.30, respectively per BOE, both of which were down significantly from prior periods. We'll seek further improvements in this metric for 2018 as we focus clearly on delivering the strongest possible corporate level returns in order to maximize shareholder value.

As I mentioned, for the quarter ended September 30, 2017, our production averaged 9,671 barrels of oil equivalent per day, which represents a 22% increase compared to the second quarter of 2017 and a 143% increase, relative to the third quarter of 2016.

Production consisted of 63% oil, 18% gas and 19% natural gas liquids. We reported total revenues last week of $31.3 million and adjusted EBITDAX of $19.1 million and also reported net income of $4.0 million for the third quarter.

Capital expenditures for the quarter totaled approximately $27.3 million.

And going forward, we remain focused on keeping a clean balance sheet with very reasonable leverage. As measured by total debt to annualized third quarter EBITDAX, our leverage at 9/30 was only 1.0x, and it was down to 0.5x pro forma for the application of proceeds from our recent equity raise.

At the end of the quarter, we had approximately $11 million of cash on hand and approximately -- or exactly $70 million of bank debt outstanding. Our borrowing base under our reserve base lending facility remains at $150 million, and liquidity at quarter end pro forma for the proceeds of equity is about $130 million.

With that, I'll turn it over to Robert.

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [5]

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Thanks, Mark. We released an operations press release that most of you are aware of on October 18 with a lot of information about our activities, especially those in the Midland Basin. We have maintained our full-year production guidance of 7,800 to 8,200 BOE per day, while lowering our exit rate production guidance slightly by the 500 BOE a day that Mark mentioned to get us to 10,000 to 11,000 BOE per day exit rate due to these legacy asset divestitures.

As outlined in our operations release, our exit rate is dependent upon completing a majority of the 5 wells that we have waiting on completion in the Midland Basin. We began these completions on the first of these wells earlier this month and expect to get at least 3 of these wells completed and flowing back by year end.

We also reduced our capital budget for 2017 by $30 million to $85 million in total, largely as a result of the reduction of approximately $17 million of drilling and completion capital based on our joint development agreements in the Eagle Ford and a reduction by approximately $10 million in our land and infrastructure expenditures in the Midland Basin.

With respect to land, we won't spend as much in 2017 as we initially budgeted due to our focus in the second and third quarter on acreage trade that will benefit us in the near term. We continue to see success on the Midland Basin acreage trade front as demonstrated by these 2 recent trades in Upton and Reagan Counties, which are highlighted in operational update as well as our most recent corporate presentation on our website. We continue to pursue acreage trades and acquisitions that position us to drill longer laterals and increase our economic inventory.

We continue to operate a single rig in the Midland Basin with current plans to maintain this pace at a minimum throughout 2018. We currently are drilling a 2-well pad on our Hartgrove unit where we hold a 60% working interest. These will be our eighth and ninth wells in the Midland Basin, and we continue to examine adding a second rig in 2018 and are actively preparing operationally in order to efficiently run a second rig should we choose to go down that path.

At the end of the third quarter, we brought 3 wells online, the #4, 5 and 6 wells in the TSRH 28S unit located in Reagan County, which are 100% working interest wells. These wells average about 7,585 feet of lateral length and were completed on average with 47 stages and 2,350 pounds of proppant per foot approximately. These wells are completed in the Wolfcamp with 2 wells in the B Upper and one well in the B Lower.

The #5 and #6 wells have reached peak IP 30 rates, an average 904 BOE per day with 77% oil or about 119 BOE per day per 1,000 foot lateral.

The #4 well is still cleaning up, and over the past 15 days, has averaged 664 BOE per day with 65% oil.

As mentioned, there are 5 wells, which we will be in the completion phase between now and year end with the frac crew currently completing the first of these. The first 3 wells are all single-well pads being the RCR 180, the WTG 4-232 and the WTG 5-234 which are all 100% working interest wells, while the last 2 are on our Texaco Parrish 2-well pad in which we have a 50% working interest.

Moving over to the Eagle Ford. We recently finished the 11-well drilling program in Southern Gonzales County by drilling 6 wells in our Crosby Unit. Completions on these 11 wells are on track to start later this month.

And as detailed in our operational update, during the third quarter, we entered into a second joint development agreement in Southern Gonzales County where our financial partner is paying a majority of our share of the capital expenditures to earn 50% of our original working interest in the unit and adjacent acreage.

The 2 JDAs have resulted in an estimated CapEx savings of $17 million, further allowing Earthstone to refocus capital on the Midland Basin.

Lastly, during the third quarter, our non-op Bakken assets produced 876 BOE per day. And as mentioned, we are in the process of evaluating a potential sale of the Bakken assets which could occur soon as year end.

With that, I'll turn it back to Frank.

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

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Okay. Robert. Good summary. Thanks. For all you folks on the line, I want to tell you that I believe that this quarter provides a good picture and a solid view into Earthstone's future. We're working everyday to expand our acreage and inventory of locations, increase our reserves, improve our operating metrics, thereby, increasing our margins and our profits.

We have begun to build significant momentum with our Midland Basin assets and we are pleased with the integration of these assets and the contributions of our Midland base personnel into Earthstone. The recent small divestitures was the potential sale of our Bakken non-op assets will further strengthen our ability to grow competitively in the Midland Basin. While we're working towards another major acquisition, each day we're pursuing trades and acquisitions that can enhance our current positions, result in longer laterals and more efficient operations.

Finally, with a strong balance sheet and liquidity as a result of our recent equity offering, we're well-positioned to pursue bolt-ons and significant acquisitions. We do value and appreciate our employees, our bank group, our equity investors, and thank you all for your help and support.

Operator, that concludes our prepared remarks, and we'll now open the line to questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question will be from the line of Neal Dingmann with SunTrust Robinson Humphrey.

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

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I think my first question -- my first question, I think, Frank is probably for Robert. Robert, I know there's been -- there was (inaudible) about a month ago that had a pretty big well by y'all in Reagan. I guess my question around that is, the day -- I mean, I'm sure you saw it as well -- is there something they did especially with the completion? Or if you could just talk about you mentioned those, what, I guess, 5 or so wells coming up. Can you maybe just talk about the enhanced completions that you and Frank and the guys have designed or think about doing for that and going on in '18?

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [3]

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Sure, Neal. We don't have all the frac details on that well you're talking about. We're well aware of it. It's very close to our WTG block of acreage, so it probably looks very similar to our WTG well that was completed earlier this year. So we hope and would expect that our first 3 wells that we're fracking down there that are in close vicinity to that would all look about the same.

As far as the frac and the design goes, not much has really changed as the bold fracs had triangulated to kind of what the current technology and designs are in the area, but we're still 160 to 165 foot stage spacing using 2,200 to 2,300 pounds per foot of proppant. We may up our 100-mesh percentage a little bit. And with a few more clusters along the pathway of the lateral in each stage, maybe we've got some better fracs coming down the road. We'll see. But other than that, not much has changed.

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

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Okay. And then could you talk about -- you mentioned, I think you or Frank, in the prepared remarks talked about some -- in fact, I think it was the 500 barrels a day that you were off because of offline operators, the offsite operators. Do you see, I mean -- I guess from the plannings you've done now for the upcoming months, will there be similar or much of that going on?

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [5]

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So what happened was is that we had a 3-well pad that we shut in while we were fracking a 3-well pad offsetting that, and that's where the 500 barrels came from roughly. In these first 3 wells, we don't have any wells that are directly offsetting that we should have the same type of impact. Although at WTG, we may see some of that, we may shut our well in there, but we'll play that by ear as we get a little closer. And then we've got a 2-well pad at the very end of the year we'll start fracking where we may have to do some adjustments to the offset wells. Again, it's at a lower interest, working interest, so the impact to that, we haven't really taken into account because I don't think it's going to be off that much.

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

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Neal, this is Frank. Robert's out in Midland right now, and I had this kind of conversation a little bit with a few of our folks this morning when we've had some of this conversation. Please bear in mind that this is our first full quarter that we're tweaking all of our plans and tweaking all of our schedules. And let me say that, hopefully, as we improve our tweaking, our schedules, and so forth, we can anticipate perhaps better or we'll anticipate where we might have some production declines temporarily while were fracking offset wells. Of course, we don't have access to know what other operators are going to be doing offsetting our acreage, but we'll try to take that into consideration and make sure that our guidance is as close to accurate as possible.

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Operator [7]

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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 [8]

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Robert, I think you mentioned in your prepared remarks about the timing in getting these 5 wells online the rest of this year and maybe even the 2018. As you look at the completion side of the business, how tight is that? And do you have those all in the calendar? And what maybe would be the swing factor, I guess, on the timing of getting those online?

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [9]

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Well, these 5 that we've got planned between now and the end of the year are pretty locked in. It's just a matter of executing on the timing of getting each well fracked and then drilled out and put online. So 3 of them are going to be on before year-end. The other 2, we'll be fracking right across year end. So we've been very fortunate in being able to find windows of opportunities that match up well with the service companies that we're using. And to date, everything's worked out pretty well from a timing standpoint. 2018 is still a little fluid for us and we haven't walked anything down. But as we get an inventory of wells, we -- or can see an inventory of wells, we usually get a frac company kind of lining out their schedule to match ours.

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Jason Andrew Wangler, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [10]

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Okay. And maybe just we talked about this a few weeks ago as well, but you just mentioned, as you look at 2018, you have the 1-rig program. Maybe just the thoughts on where you're going to be working with that rig and kind of the plan? And as you think about a 2nd rig, where that would be incrementally kind of focused, I guess, for the development of your assets?

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [11]

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Sure. We have 10 obligation wells just from timing wise that have to be started in 2018, and those are all in Reagan County. So half of our program with the 1-rig program will be in Reagan County. And then we'll balance it a little bit around between Upton and perhaps Midland County. If we bring in a 2nd rig at some point during the year, Upton and Midland County would be probably the area where we'd like to focus with that rig and drill multi-well pads and not have to worry about bouncing around, but that's still up in the air and trying to figure it all about.

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Operator [12]

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Our next question is from the line of Jeff Grampp with Northland Capital.

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Jeffrey Scott Grampp, Northland Capital Markets, Research Division - MD & Senior Research Analyst [13]

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Kind of building off of Jason's question on that second rig in the Permian. What are kind of the, I guess, kind of checkboxes or things you guys need to see to maybe feel a little bit more comfortable adding that? Is that more discontinued stability on the oil price side? Is it getting the Bakken sales done? Or just kind of getting your ducks in a row in terms of service availability and procurement of crews and equipment? Just kind of how wondering how you guys holistically do that?

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [14]

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Frank, you want to take that or you want me to?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman, CEO & President [15]

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Well, why don't you go ahead and take it. And then I'll give my two cents. Jeff, as you know, we don't always agree in this conceptual framework that we're in, and so forth. But between the two of us, we'll kind of give you what our collective thinking is. Go ahead, Robert.

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [16]

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Okay. So the first thing would be if we can land some additional opportunity, then we would definitely look to put a second rig to work sooner than later. I think prices -- commodity prices are going in the right direction and look pretty good. I don't know if they're going to firm up in the 55 range, but that's not necessarily at this point given our economics and our results, the only driver. And then I think lastly is making sure that we can get quality services in order to be able to drill effectively, and we're working through that right now in trying to figure out when we start and who might [have the ability] to help us out.

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

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Yes. Jeff. As you know and as we've told everybody, we're clearly focused on acquisitions, and so forth. And acquisitions that could bring some additional production with them, plus supplement and complement our existing acreage positions, and so forth. So excluding the fact that we will bag acquisitions in '18 one way or another, I would like to see a second rig sooner rather than later. I think Robert hit the nail on the head in that if we're running one rig continuously, we'll drill some in Midland and in Upton, but we'll probably focus on building efficiency also in Reagan while we satisfy obligations but also drill multiple wells on a given path. The least efficient thing we can do is go forth and drill one well pads because you have drilling obligations. So if I had my druggers, I would give you a clear line of sight to having a second rig in there focused on Midland and Upton County perhaps in the second quarter of the year or maybe by the end of the second quarter of the year. As far as price is going, we can be kind of mealy-mouthed and noncommittal on that. But clearly, with the price deck of starting at $54, $55, even though the last time I looked, it was down $51 or $52 a couple of years up. But that price deck locks in some great economics for us, and God bless us if it ever goes the other way starting from $54, $55, up to $56 or $58 or whatever have you. But that's also going to depend on the quality of services. The last thing we're going to do is go out there and adversely affect the economics because the services aren't available. So I guess the takeaway there is a combination of what Robert and I both said. With that acquisition, bringing in a second rig and associate it with that acquisition without a clear line of sight as long as the industry and the commodity price deck doesn't crater by the end of the second quarter.

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Jeffrey Scott Grampp, Northland Capital Markets, Research Division - MD & Senior Research Analyst [18]

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Okay, perfect. I appreciate all the thought. And for my follow-up kind of building on the acquisition side of things. I know it's still kind of early into this recent momentum we've had, but can you guys maybe kind of talk about how those conversations are going? Are those maybe easier or harder to have with the recent strength in crude? Or can you just generally about how those conversations have been trending?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman, CEO & President [19]

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I'll let -- Robert's much closer to that than I, so I'll give you my two cents. But clearly, I think while we were digesting the merger and so forth and after May 9th closing, we had an adverse price impact. And if I recall, the prices kind of dropped down to $42, $43, which kind of just stalled everything in terms of discussions about acquisitions, and so forth, which is why -- which is one of the reasons, just one, that we focused more clearly on these trades where we can add lateral length and do something that's going to impact us appreciably in the near term and why we're not going to get another $10 million spent in land. With the prices having moved up, it just seems that the -- that there's more conversation out there, if you will, as opposed to sellers saying (inaudible) there ain't a thing talk about it, $42 or $45 or $48 a barrel. Robert, you want to add anything to that?

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [20]

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No, I think you got it right in that there's -- the activity is picking up on the A&D, side but there's nothing new -- we're not far enough along to have any solid information about deals that we're working on.

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Operator [21]

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Our next question is from the line of Mike Kelly with Seaport.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [22]

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Speaking on the acquisition front, Frank, you mentioned in your prepared remarks that you're working towards the next significant acquisition, and just would love to hear your thoughts on how significant is significant and really what that criteria kind of looks like post the bold deal on something that's more larger in nature.

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

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Well, I don't want you to think we're a bunch of -- I don't want anybody on the line to think we're a bunch of cowboys around here and not methodical and organized and focused and so forth. So with that said, this may be a goal that I don't want anybody just to snicker and to laugh at. But you might take a look at what we've done in the last 18 months with the non-op acquisition and this one. In another 18 months, I'd be fibbing if I told you we didn't have a goal of doubling our acreage out there. Whether that can be accomplished is something that time will tell. And -- but in less than 2 years, we've gone from 0 to 27,000 acres, the majority of it operated. We're pushing 7,000 BOE a day not counting these fracs on our West Texas position. So what the hell, if you don't set the bar and say we'll try to double our acreage economically, appropriately, and so forth, to generate profits for our shareholders, that's kind of the goal. So there you have it. You can either pat us on the back in 18 months or slap us upside the head, but that's the goal.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [24]

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Okay, great. And just switching over to the Bakken and on the sell side for you guys, can you just maybe characterize with this position looks like for you? I mean, there's been lot of hype on wells now that have 1 million to 1.5 million barrel type EURs associated with it. Is this in your eyes kind of around that territory? And maybe the number of undeveloped locations here? I'm just trying to get a sense of how much this could be worth for a potential buyer and the interest...

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

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I think it's out there buried in one of the slides in our PowerPoint that's been out there and is out there. Robert, why don't you take that one?

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [26]

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Okay. Mike, we -- like I said, we had about 875 BOE a day in the third quarter, which is probably the best metric to consider on these kinds of acquisitions given that it's non-op and given that it's, maybe it's 50-50 developed versus upside. It's in a really good area in McKenzie County for the most part in the core. A little lower oil cut there because you're a little deeper so you got a little bit more gas component, but that helps drive up those EURs. So I think you can look at prior -- recent transactions and -- that are non-op in particular and compare our rate to that and it might give you close to a value range.

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Operator [27]

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Our next question is from the line of Ben Wyatt with Stephens.

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Benjamin James Wyatt, Stephens Inc., Research Division - Senior Research Analyst [28]

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Maybe Robert, for you, just back to kind of on the completion side of things. What's kind of the magic number before you guys do go get a full-time frac crew? Is it 3 rigs, is it 2 rigs? Just trying to get a sense of what that is.

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [29]

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Definitely 2 and maybe 3. So we've had some discussions with other operators saying maybe we team up on a frac crew if we're only running one rig and they're only running one rig. It sounds really good. It's a little harder to put into practice, but there is some potential for something like that. But I think we need at least 2 rigs running full-time and having an inventory already built up before we get a frac crew out there committed 100% of the time.

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Benjamin James Wyatt, Stephens Inc., Research Division - Senior Research Analyst [30]

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Go it. Appreciate that. Maybe just switching over on the cost side of things, on the operating cost side of things, can you guys just give us a sense of maybe where LOE is Midland versus Eagle Ford versus Bakken? And I guess the reason why I asked is just as Midland continues to grow at a quick rate and potentially get rid of Bakken, just trying to get a sense of maybe where LOE could head lower -- where it could head to here over the next year or so.

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [31]

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Sure. I'll start and let somebody else to jump in. But the Midland Basin, on an operated basis now, is in the $3 range. Obviously, that's -- per BOE. That's driven by high initial rates. But it's also driven by low cost for saltwater disposal. And again, that's something we have within our operated position where we've got access to very inexpensive water disposal, which is a really important innovation. When you get into vertical wells in the basin, in the Midland Basin, that number is 2.5x to 3x that amount on a per BOE basis. The Eagle Ford is running $6 to $7 per BOE. If you get into the Chalk wells, they're a little bit higher, just a little higher operating cost. The Bakken is north of $10 for us, a $10, $12 range. So at that -- and cleaning out the rest of our noncore legacy assets, you'll see us get in to the $5 range, and Frank's target is lower than that.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman, CEO & President [32]

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Yes. I think just to clarify what Robert said, that's fully loaded on the LOE pretty much, including normal and recurring lease operating expenses, what we've called reengineering and workovers, but the workovers, which are an inherent part of the business and the ad valorem taxes. So it's kind of fully loaded for all those things. And of course, the severance taxes show up separately in the financial statements.

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Benjamin James Wyatt, Stephens Inc., Research Division - Senior Research Analyst [33]

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Yes. Good stuff, guys. That's helpful. Maybe if I can just ask one more. With Mark kind of coming on board, just curious how -- if he's brought a different way of thinking, if you guys are having discussions on just kind of the hedging -- how you guys are thinking through hedging now, maybe even now that crude's north of let's say almost 57. So just curious on your thoughts there.

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

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Yes, sure, Ben. First of all, I think the I always have, but happy to be here. And I think on the hedging side, to answer your question, with the production base that we have and certainly with prices having moved up, we have layered on a chunk of hedges. I just recently, in the past week, would put on the first of our 2019 hedges, which is a little bit further out than probably the team here has historically done. We're pretty well-hedged on oil side for 2018 as it relates to PDP. Certainly, as we drill throughout the year, we may look to add a little bit more in 2018. But really, I mean, our goal is to be fairly well-hedged on the PDP, 12 to 24 months out, and certainly, north of 50, the economics on our wells are really good and we feel good forget about having some chunk of the portfolio locked in with that.

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Operator [35]

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Our next question is from the line of Ron Mills with Johnson Rice.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [36]

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A lot's been answered already, but Robert, on your presentation, you provided a chart on downspacing results in Reagan County from those 2 Coates wells. Can you provide some more color there, the 660-foot spacing. What's that down from? And how do you plan on utilizing that in terms of incorporating that into your development program?

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [37]

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Sure, Ron. The wells that we compared to are standalone wells that are probably 2,500 feet apart from other existing wells in the same bench or target. So that kind of gives you a sense of those are more oneoff-type wells, and these 2 being 660 feet just give us a sense that there's nothing in that completion, both design and production, that would want us -- make us rethink our development spacing at this stage. Maybe that changes as you develop an entire block, but at least those 2 wells kind of validated what we were thinking might happen when you frac wells like that, that you actually have an increase and a little bit of benefit from having wells that close and being fracked at the same time.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [38]

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And is your current inventory based on 660-foot spacing? Or is there upside there?

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [39]

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It is. No, it's based on 660. There's people testing 330-foot spacing or even -- or thereabouts in certain places in the basin, and we'll look to them to be really successful and prove to us that, that's going to work, and then we have a whole lot more locations. But our whole plan of development was all based around 660-foot spacing.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [40]

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Great. And then I know in terms of additional upside zones, a couple of things jumped out at me. In your new presentation, you now show Wolfcamp D and you also show added benches in the Wolfcamp B. Are those added benches in the B incremental to the 2 B zones that you already included in your inventory? And what testing is going on in those added benches, if you don't mind?

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [41]

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Okay. So what we've got in our inventory of about 500 operated locations is just one bench in the A and then a B Upper and a B Lower. What we show on that slide is, on the type log, is where other operators have also tested additional branches within those same intervals, so an additional B Upper and an additional B Lower. And those are not counted -- as well as another A zone. And those are not counted in our inventory of 500. The C obviously is not counted. Frank has already talked about that. The Wolfcamp D, in some areas, operators call it decline; we've chosen to call the Wolfcamp D. And again, it's not counted in our inventory.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman, CEO & President [42]

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(inaudible)

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Robert J. Anderson, Earthstone Energy, Inc. - EVP of Corporate Development & Engineering [43]

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I was going to say as far as testing goes, Ron, that we're going to let -- there has been some testing in Reagan County in multiple benches outside of the one we're developing -- outside of the 2 we're developing in the B, for instance and the A. We're going to continue to watch what other operators are doing and how tightly delineated within a B interval those operators are completing the wells and kind of see what that does for us. The C is probably the most relevant in terms of us drilling any time soon. There's been some really good C wells put out there by public companies, and they continue to drill C wells. In fact, there's 3 C wells from 2 different operators that are directly offsetting acreage that we have. And hopefully, those are all completed and we have a little bit of news by year end, but we'll start to look at adding to our inventory, C bench wells.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman, CEO & President [44]

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Say, Ron, this is Frank. Just to point you to a couple of pages. We've put that PowerPoint out there, and I'm not -- I just don't recall if we had -- I know we had one of the slides. But if you look at Page 14 and Page 17, when you get around to it, 14 has the counted operational benches and where the upside potential could be. Page 17 has kind of a listing by zone and so forth. And if I'm not mistaken -- Robert, correct me if I'm not mistaken. But as far as the C goes on Page 17, we did have some C locations, but when we put this out, we didn't have any in our operated. That's probably associated with the nonoperated. Anyway, that will give you a feel for, Ron, for what we've counted and where the upside could be.

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Ronald Eugene Mills, Johnson Rice & Company, L.L.C., Research Division - Analyst [45]

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Great. And then one last one for me. I appreciate all the A&D commentary you've provided that you have announced the success of a couple of different acreage swaps. Anything else going on, on the acreage swap as you continue to evaluate acquisition opportunities that -- those things could take quite a while, but once completed, they really appear additive. Just curious where you are in that process and if there's any particular area you're focused on, on additional swaps?

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman, CEO & President [46]

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Well, clearly, the swaps and trades and bolt-ons, clearly, what you want to do is do those in reasonable proximity adjacent to your existing acreage positions and improve -- just like the 2 that we have on our PowerPoint, improve the lateral length and the number of locations in that strand in the acreage. So we're working on that all the time daily. And what's refreshing to me, having been involved in the Eagle Ford for quite some time, is there seems to be a good amount of cooperation by companies to accomplish the same thing. So we'll just keep working on that. We've set up a team to do that, so that Robert and I can chart -- and Mark here can start chasing bigger deals. But it's a clear focus for us. And if you take a look at what we've done, the incremental results of that, perhaps small in relation to the overall corporation are small, but very important and very accretive on an inventory basis.

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Operator [47]

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At this time, I will turn the floor back to management for closing remarks.

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Frank A. Lodzinski, Earthstone Energy, Inc. - Chairman, CEO & President [48]

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Well, this is Frank. So thanks to all of you who found the time to dial in. As I mentioned, we're focused on this everyday. We have a game plan. We're cleaning house. The contributions of our folks here in Houston and in Midland, a shout out to all of those folks because it takes people to get these things done, and thanks for calling in.

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Operator [49]

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