Earthstone Energy Inc (ESTE) 2017 Q4 法說會逐字稿

Good morning, and welcome to Earthstone Energy's Conference Call. (Operator Instructions) As a reminder, this conference is being recorded.

Joining us today from Earthstone are Frank Lodzinski, 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 begin.

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 yesterday.

For more detailed information about our company, listeners are encouraged to read our annual report on Form 10-Q for the full year ended December 31, 2017 in its entirety. Our earnings release will be posted to our website, along with an updated corporate presentation 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.

Okay. Thanks, Scott. One minor correction, that's a 10-K that's going to be filed and not a 10-Q. So we're urging everybody to look through all of that information also.

So good morning to everybody. Before we get into a more detailed review, I want to thank all of our employees, both in Houston and in Midland, for making 2017 a great year for Earthstone. At year-end, we sold off our Bakken properties, and I also want to recognize our former Denver-based employees for their support in the transformation of our company to a Midland Basin-focused operating company.

I cannot be more pleased with what we've accomplished during 2017 as this was another transformational year. I think the numbers show that. We initially entered the Midland Basin in 2016. And in 2017, we significantly expanded our activities with the addition of 21,000 net operated acres. Further, we high-graded and streamlined our asset base with the divestiture of virtually all of our legacy properties, including the Bakken assets which I just mentioned and multiple small properties. As of year-end, our portfolio includes our 27,000 core net acres in the Midland Basin and about 16,000 core net acres in the Eagle Ford.

I'm not going to go into the 2017 results in some detail, but I do want to point out a few facts. Our sales volumes in '17 increased 97% from '16. We lowered our LOE per BOE by 33%. Our proved reserves have grown to over 6.5x their 2016 balances. And our adjusted EBITDAX grew over 223% compared to 2016. In addition, we are generating net income. And at year-end, our net debt was only $2 million.

Finally, I want to emphasize that we reported sales volumes within guidance, but with materially lower capital expenditures. In other words, we generated profitable growth while we maintained a strong balance sheet with increased liquidity.

In just 3 years, this management team has taken Earthstone from less than 1,000 barrels a day to a year-end rate of over 10,000 BOE per day. Further, we achieved a corporate milestone of generating over $100 million in revenues.

Looking forward, we will devote the majority of our financial and human resources to further expansion in West Texas in order to achieve greater scale and efficiency and to develop our high-quality asset base in the Midland Basin. Specifically, I'll point out that 90% of our projected 2018 capital expenditures will be devoted to efficiently increasing production in our acreage position in West Texas.

While our clear focus is in the Midland Basin, the Eagle Ford is still an important asset that has contributed over 2,000 BOE per day or about 20% of our sales volumes at year-end. We do not intend to ignore our Eagle Ford assets, but we do not intend to expand our footprint.

For those of you that may be new to Earthstone and this management team, this is our fourth public company. The prior 3 realized significant positive returns for our shareholders. It's our intent to do that again. We will continue to work hard to profitably increase our production and focus in on the 2 things that had benefited us in the past and that we can control. Those 2 things being efficient operations and a strong balance sheet. While we do intend to use leverage to finance acquisitions and operations, and therefore, enhance shareholder returns, we will continue to avoid debt excesses that have occurred in our industry. I want to reiterate before I finish here that we're intently focused on expanding our footprint in West Texas through acreage acquisitions, trades, mergers and other A&D efforts. Hopefully, we will be able to deliver another transformative transaction in the foreseeable future.

I'll now turn the call over to Mark to provide a brief summary of our financial results for the fourth quarter and for the full year. Mark, how about it?

Thank you, Frank. First, I would like to highlight some of our accomplishments in operational execution during the fourth quarter of 2017. As Frank mentioned, our average reported sales volumes approximately doubled in the fourth quarter to an average of 9,071 BOE per day versus the fourth quarter of 2016, and that consisted of 63% oil, 19% gas and 18% natural gas liquids.

One of the key drivers of the year-over-year increase was incremental sales volumes from our operated Midland Basin acquisition that we closed last May and in which we've been continuously running 1 rig. That, combined with our non-op Midland Basin assets, production from the Midland Basin comprised about 75% -- about 70% of company-wide production in the fourth quarter. The Eagle Ford comprised about 20%. And the balance was largely from our Bakken non-op assets, which, as you know, we divested in late December. Currently, we are estimating our average daily production in 2018 to be between 12,000 and 12,500 BOE per day, which will be more back-end weighted than front-end weighted.

From a financial perspective, we released net income of approximately $5.5 million or $0.09 per share in the fourth quarter of 2017. This was after a noncash impairment charge of $5.5 million, which was related to the Eagle Ford where we are limiting our capital expenditures.

Adjusted EBITDAX grew to $22.1 million in the fourth quarter, which represented a 16% increase versus the third quarter and a 182% increase year-over-year in comparison to the fourth quarter of 2016.

During the fourth quarter, we also continued to streamline and optimize our cost structure and have been able to efficiently and significantly reduce our operating expenses on a per unit basis. That continues the trend throughout the year.

LOE per BOE in the fourth quarter was $5.59, which was down 8% compared to the prior quarter. Further, our LOE per BOE for the full year was down to $6.84, which was a reduction of about 1/3 compared to 2016. We do expect continued improvement in LOE per BOE and are guiding toward $4.75 to $5.25 for full year 2018.

With respect to our balance sheet and liquidity, we continue to have a conservative capital structure with low leverage, as Frank mentioned. And as of year-end, we only had $2 million of net debt outstanding and a $185 million borrowing base under our reserve-based lending facility.

Capital expenditures for 2017 totaled approximately $81 million. And for 2018, we budgeted $170 million in total CapEx.

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

Thanks, Mark, and good morning, everybody. 2017 sure was an important year as we positioned the company for growth around our core asset base and strengthened our operations and financial structure to take Earthstone to the next level.

In the fourth quarter of 2017, we initiated a 5-well completion program in the Midland Basin. The results of 3 of those wells that began producing prior to year-end were previously highlighted in our operations update in late January. The final 2 wells in that completion program, the Texaco-Parish 1 #1 HU and the Texaco-Parish 2 #1 HM began producing in January of this year. Earthstone has a 50% working interest in each of these 2 wells which are located in central Reagan County.

The wells were completed in the Wolfcamp A and the B Upper, respectively, with average lateral length of 8,204 feet and 51 frac stages each. As we have discussed with you before, the Wolfcamp A starts out with a lower initial rate and can take 45 days or more to reach its peak rate. Whereas the Wolfcamp B can achieve peak rates within the first 30 days or so. Such is the case with this recent A well. It has been online for over 50 days and it's still increasing in rate every day.

We continue to be pleased with the initial performance of our wells as the results of our drilling program continue to meet or exceed our type curves. Currently, we are drilling the 2-well West Hartgrove pad in Reagan County with our 1 rig running. We have an 87% working interest in these wells and are drilling the Wolfcamp B Upper and our first Wolfcamp C well. We have 5 wells drilled and waiting on completion today that we will start fracking in April and should have 8 wells to complete in total in this package.

A little bit on the Eagle Ford. Late in the fourth quarter, we started an 11-well completion program in southern Gonzales County. 5 wells were discussed in our January update as they came online in December. The last 6 wells came online in January of this year. We have a 25% working interest and operate the 6-well Crosby pad. It had average peak 30-day rates of 507 BOE per day being 94% oil. The average lateral length of those wells is right at 4,900 feet. The wells are still flowing without the aid of artificial lift and are around 400 BOE per day and approximately 700 psi flowing pressure as we continue to produce our Eagle Ford wells on a restricted choke program.

We plan to start drilling on a 5-well pad in our southern Gonzales County acreage in the Eagle Ford in late March where we will have approximately 17% working interest and operations in this pad. With all this new activity and these new wells online in the Midland Basin and the Eagle Ford, we've maintained our estimated current daily production at over 10,000 BOE a day for the month of February.

In our January update, we also provided our 2018 capital budget, which is currently set at $170 million, as Mark pointed out, with $144 million of that earmarked for drilling and completion in the Midland Basin. Our plan is to bring online 22 gross and 19.6 net operated Midland Basin wells during 2018 with our primary focus on the Wolfcamp A and B formations. This plan is based on a 1-rig program throughout 2018, but we are working to be in a position to add a drilling rig in the second half of the year.

In the Eagle Ford, our 2018 plan calls for us to spend $12 million and bring online 16 gross, 3.6 net wells. 6 of these wells being our Crosby pad are already online. Because a majority of our Eagle Ford acreage is held by production, we have the ability to significantly reduce our spending in this area so we can focus on developing our Midland Basin assets.

Now a short comment about our reserves. Our 2017 year-end SEC proved reserves increased to approximately 80 million barrels of oil equivalent comprised of 59% oil and 25% proved developed. This is about a 560% increase over year-end 2016. The pretax, SEC-priced present value of future cash flows of the total proved reserves discounted at 10% or PV-10 increased nearly 600% to $599 million compared to year-end '16. As you will see when we post our updated corporate presentation, when using year-end strip prices, PV-10 is approximately $640 million.

We have a deep inventory of highly economic operated drilling locations with about 526 gross locations on our operated Midland Basin position. This includes benches in the Wolfcamp A and B as well as the C and also the Lower Spraberry. We have additional upside potential in our other identified Wolfcamp targets, along with Middle Spraberry and Jo Mill, which we've not yet included in our well count.

We are seeing quite a bit of activity in Reagan County from other operators drilling and completing Wolfcamp C wells. And as you will note in our updated corporate presentation when we post it on our website, we have included a number of C locations. We have spent considerable time this past year trying to lay out development scenarios where we can maximize lateral length. In some cases, this caused us to realize that we would have additional nonoperated locations but much better economics. As you know, we focus on operations, so we are working to create trades or acquire acreage so that we can turn these non-op locations into operated locations.

Finally, when we do post this presentation, you'll see that our total location count has expanded to 943 when you include the nonoperated locations based on our work to date on identifying all the potential in the zones I've highlighted today.

In 2018, we plan to build on our execution success and continue to optimize our drilling and completion program. After now operating in the Midland Basin for 10 months, our pace of drilling and completions has improved, and we will build on our learnings to date. Our operations team just finished drilling a single-well pad that has established the bar for our program by drilling approximately a 7,300-foot lateral in 12.3 days from big rig spud to rig release for about $2.1 million.

Improved drilling and completion efficiency, along with our well performance relative to prior type curves, will allow us to achieve the economics that we will provide in our upcoming corporate presentation. We will continue to be active in executing acreage trades in the southern Midland Basin with the intent of drilling and completing longer laterals and increasing our operated inventory. We are also actively pursuing acquisitions of bolt-on acreage and producing properties that contain accretive inventory now that we have divested all the noncore assets from our portfolio.

We are excited to now be a company with assets and employees focused exclusively in Texas, and we are proud of the solid execution of our plan. 2018 should be another exceptional year as we continue to work towards profitable growth, both organically and through M&A, while being responsible stewards of our financial capital.

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

Okay. Just to wrap up on the prepared remarks, I just want to reiterate that we're focused on expanding our footprint, our acreage, our drilling locations, our reserves, our production, all in the Midland Basin and keeping this company profitable and growing profitably. We will continue to develop a core acreage position and a largely -- I don't want to say largely unlevered balance sheet, but a reasonably levered balance sheet so we don't go the same way that some of our competitors have. We expect '18 to be an exciting year with good opportunities to achieve our goals of growing profitably and prudently.

So operator, we're now ready to take any questions that the audience has.

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

My first question, Robert, probably for you. How do you guys think about -- I know you haven't put maybe a quarterly out, an entire year, but how do you think about sort of cadence or timing throughout the year? And along with that, how can you be sure of getting the frac spreads when needed?

Well, we're pretty confident that we're going to get the frac spreads when we need them. We've fracked several wells in August time frame. We got the same frac crew back in December to do that 5-well group. And then we've got them lined up to start in April. And by the time we're through with them we'll have fracked 8 wells. So the cadence will be, we'll get 8 done April, May, maybe take into June a little bit. And then we'll take a break with the frac crew, let them go work on their equipment, go somewhere else for a little bit and then come back and hopefully keep them for the last quarter plus of the year busy.

Okay. And then it sounds like -- I agree with you, it sounds like there certainly has been a lot of success with Wolfcamp C by a lot of the peers there. I forget, in your plans and in your -- when you and Frank look at your inventory count now, are you assuming much of that? Or what are you -- how are you thinking about that for the latter part of the year?

Well, we're drilling one right now. It's a 2-well pad. It's B and a C. That will give us a little bit of information to kind of see based on our own data how these wells produce. Over time, we'll figure out whether that becomes more of our current drilling plans in '19 or it's just inventory that we keep until we ramp up to more than 2 rigs.

All right. Then just last, very quick, just on service costs, any change recently?

No, not really. I mean, there's a little bit of creep always, especially as prices move around and you're on the spot market. But we basically, from our frac provider, are seeing relatively minor increases from August to December to what we hope happens in April. We're considering some other things to help alleviate whatever cost increases we may have. We're looking at the use of in-basin 100 mesh in our proppant design. And we're trying to improve the number of stages we do a day. Therefore, we're dropping our total cost. So those are the things we're working on every day.

Our next question comes from the line of Gordon Douthat with Wells Fargo.

Just wanted to get your thoughts on the second rig and what you need to see happen there to get that rig going and what the timing might be?

Well, we're -- Gordon, we've been a little nonmarket committal on that because we're trying to figure out what the prices are going to be doing. We are searching for the appropriate rig with the proper personnel and so on. And the balance really here is committing to that second rig, we got a board meeting upcoming and we're going to talk about that at the board level here. But committing to that second rig, or if one of the acquisitions we're working on works, well, then we might bring the second rig in connection with an acquisition. But you have to -- as you know, you have to start planning for that second rig earlier. You have to work the infrastructure to accommodate and the locations to accommodate that. So we have all that in process. And if we go to a second rig, which I'm kind of leaning to right now, it could be the July, August time frame. Robert, do you disagree with that? You might have looked at some of the timing a little more recently than I have.

That's what we're targeting if we can get all the other things in a row that we need to.

Okay. And then how is the acquisition outlook looking versus where you had -- you previously talked to the market a couple of months ago, how is the pipeline looking from a trade or acquisition standpoint out there in the Midland?

The pipeline, do we have anything ready to go to a PSA? No. Do we have a number of conversations going on trades and swaps and smaller acreage acquisitions? Yes. One of the things that we talked about -- you can't put this into the bank yet -- is trading some of our acreage that we acquired in 2016, our nonoperated acreage, for operated acreage. So we continue to beat that down. So I'd say that the -- Robert, you might adjust what I'm saying here when I'm done. But I'd say our deal flow is pretty good, ranging from small things that are 1,000 acres or less up to very meaningful things that could potentially double the size of the company. So our deal flow is pretty good -- whether we can capitalize on. The A&D market overall is a little squirrelly in terms of whether buyers and sellers can get together. But we've been successful in the past, and we hope to be successful in the future. You got any color you want to add to the A&D market, Robert?

We're plenty busy enough. It's -- our challenge is making sure we're working on the right projects every day and utilizing our limited employee resources on those A&D transactions. But we've got a full pipeline. Can we add to it? Yes, because we could drop something out the other end and hopefully, we get some things accomplished here in the near term.

Our next question comes from the line of John Aschenbeck with Seaport Global Securities.

My first question is in regards with the new type curves in the Midland Basin and just the underlying economics. Robert, I think you briefly touched on this in your prepared remarks. But I believe the range of IRRs from the legacy type curves was in the 34% to 81% range at $60 oil just depending on which asset you were looking at in the Midland Basin. I was curious as to how the new economics compare to those legacy metrics.

Well, we have a big screen that we're going to show those. And we're going to drop the curtain here pretty soon and show you, John. I'm just teasing a little bit. The economics continue to be a little bit better than what we've had previously just because our type curve has changed. We're not moving our EURs, but we are adjusting the profile. And it does have an impact on what those rate of returns look like. So at $60 oil, we're really pleased with what we've put together and the results we've seen to date. And we just keep bumping up our economics. As we get more of our own wells drilled in all these areas and have more data internally, we may move our type curves a little bit, but this is what we're going to stick with.

So I guess, John, if we can get all the filings done and get that PowerPoint presentation out there today or no later than tomorrow, you'll see some new data in the PowerPoint presentation. I'm a little hesitant of throwing it out there until we get it out there for the general public so. But it looks like, as Robert said, we're altering the profile based on the '17 activity and some of the activity that occurred prior. And it's looking positive.

Okay. Great. Understood. That was actually very helpful. My follow-up here is just in regard to what you all think is really kind of the next stage of completion optimization. Seems like you may have hit the upper end of proppant intensity, but there's clearly more levers you can pull. I was just hoping maybe you could share with us what new types of concepts you plan to test during this year.

There's probably not a whole lot that we're going to change other than where we're fracking wells close to existing production, we actually might back off the frac size and intensity a little bit. And then we're reviewing the idea of diverters. And these, again, we'll call them infill for lack of a better word, but where we're close to existing wells to make sure we get the optimum frac. Other people are doing it. We want to look at some data, make sure we understand what's happening with these diverters. That's probably the next big change that you'll see that we incorporate, if and when we get to that point.

Our next question comes from the line of Ron Mills with Johnson Rice & Company.

Robert, maybe just a quick follow-up on the recent question on the type curves. If you're shifting the type curves or at least the shape of the type curves a little bit, but keeping the EURs the same. Is that implication that the wells have come on at a little bit better rates and you're just forecasting a steepening of the decline for now before -- until you potentially revisit that? Or I'm just trying to figure out what your comment or your response earlier.

Yes, no, you got it, Ron. When you look at the results we had throughout 2017, our early time production was performing better than our type curve. And so you guys don't call us sandbaggers, we needed to revisit that. And I wasn't ready to move that EUR up just yet, although I think it probably could in certain formations, in certain areas or certain targets in certain areas. We left it the same and adjusted our type curve up early time. And then, yes, the impact is, is that the decline rate is a little steeper after the first or so year. And you'll see that when we post this presentation.

Okay. Great. And when you think -- you've talked for 2 or 3 months now about getting everything in place to potentially add a second rig. If you think about adding a second rig, what do you think that -- is that more of a 2019 production impact? Did you think you start to see some of that impact in '18? I'm just trying to figure out the lead time on activity.

Sure. And that's a fair question. Even if we brought the rig in, in July and our plan was to go to bigger pads where we're consistently getting 3 or 4 wells per pad, we probably wouldn't bring on a whole lot of extra production in 2018. I'd like to think we could accelerate, but once you get the frac machine moving and you've got these obligation wells and other things that we're committed to putting online sooner than later, some of the second rig may be back-end weighted or early '19 before we start seeing production from it.

Okay. And then when you think about a rig line, since you're drilling with 1 rig now, at least that's the plan, $144 million, I think you said. Is that a pretty good guesstimate as to what you think a rig line costs per year in the Midland?

Yes. I mean, it varies a lot depending on lateral length, if you're drilling 5,000-footer or 10,000 footers. But our internal review of things is that a 7,500-footer is going to average in the high $6 million -- $6.8 million to $7 million range. If we averaged 85%, you'd kind of end up with that if you drill 20 and complete 20 wells a year. That order of magnitude, you're pretty close. But we're going to end up averaging probably north of 8,000-foot laterals, closer to 8,400-foot this year based on what we got on the schedule for 1 rig, and we'll probably average about 85% to 90% working interest. So it's a little bit of a moving target there, but that's about a 1-rig program, $140 million, $150 million a year.

And just to clarify, that $140 million to $150 million includes the longer laterals, so it's a little bit higher than that $6.7 million well cost?

Correct. Yes, it's a blended -- that's a blended number for this year, but that's -- you're right. If we were to drill all 10,000-foot lateral, that's not enough money.

Got you. And then last one, just when you think about -- you've been successful getting your frac crew and seemingly on time. So kudos to you on that. But when you -- especially when you think about later this year and next year, I think 2 rigs still probably isn't enough to necessitate a dedicated frac spread. But how are you thinking of tackling the access to frac spreads when you potentially have 2 rigs going? And that's it.

Yes. I mean, it does become a little bit more of a challenge because now you've got an inventory that's getting -- that's growing pretty rapidly. But under 2 rigs and more pad development, we think we can maybe utilize a frac crew 9 or 10 months out of the year. So far, knock on wood, the service companies have liked working alongside of us. And we've got a good relationship going with them. And our operations team has done a great job of keeping those guys happy and them keeping us happy. So we're going to just continue to use our relationships and use these good vendors and we'll all make a little bit of money.

(Operator Instructions) Our next question comes from the line of John White with Roth Capital Partners.

Yes, you're doing a good job of teasing us on this updated PowerPoint. You mentioned Jo Mill.

We're going to put -- hey, John, we're going to put it out at 11:02 p.m. so you got to work tonight, okay?

You said p.m. Okay. I got it.

Yes, p.m., yes, right, so you got to work tonight.

That's what you like to do.

So go take -- go home and take a nap.

That's what you like to do, Frank.

There you go.

So you mentioned Jo Mill. And I think it's the first time you've talked about Jo Mill on the call. Had there been some recent offset operator Jo Mill completions that you'd want to talk about?

We're not the Jo Mill expert. It is very -- there's a lot of activity in the Jo Mill in Midland County and other counties. We don't even own all rights in certain places so we can't access the Jo Mill without doing some land work in certain places. It's one of those benches or targets that looks very economic. And I think there's a few other operators that are talking about that in a much greater way. But it is very additive to our position up in Midland County in one block. And at some point, we'll add it. I mean, is it going to add 100 locations? No, but it's very good economics.

Okay. So 2018, Jo Mill test probably not likely?

Probably not likely under a 1-rig scenario. If we brought in a second rig somewhere and the acreage was appropriately located, then it could be in the plan, but it's not likely in 2018.

Okay. And Frank, I've got my calendar set for 11:00 tonight.

Okay. Sounds good. We'll try to meet that goal, John.

Thank you. Mr. Lodzinski, there are no further questions at this time. I'll turn the floor back to you for any comment.

Well, ladies and gentlemen, thank you for joining us on our call. We hope the fact that there haven't been a huge number of questions is not a result of a disinterest in what we're doing or so forth. We hope it's rather the fact that we put out our ops update, that we put out our numbers, that we try to be transparent and communicative with the markets. With that said, I will just thank you very much for joining us and see you all later. Thank you.

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