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Thank you for calling in for the replay for the Earthstone Energy Full-Year and Fourth Quarter 2017 Financial Results Conference Call, which originally took place March 15, 2018, at 11:00 A.M. Eastern Time.
Good morning, and welcome to Earthstone Energy's conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded.
Joining us today from Earthstone are Frank Lodzinski, 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.
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 a more detailed information about our company, listeners are encouraged to read our annual report on Form 10-Q for the full-year ended December 31st, 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 a 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 on file, 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 our 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 form Denver-based employees for their support and 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 six-and-a-half times the 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 three years, this management team has taken Earthstone from less than a thousand 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 and our acreage position in West Texas. While our clear focus is in the Midland Basis, 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 intent to ignore our Eagle Ford assets, but we do not intent 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 three 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 two things that had benefit us in the past, and that we can control, those two 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 the 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, have about it.
Thank you, Frank. First, I would like to highlight some of our accomplishments and the 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 the incremental sales volumes from our operated Midland Basin acquisition that we closed last May, and we have been continuous running one rig. That combined with our non-op Midland Basin assets, production from the Midland Basin comprised about 70% of companywide production in the fourth quarter. The Eagle Ford comprised about 20%, and the balance was largely 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 backend 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 non-cash 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% [technical difficulty] versus 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 a 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 is a reduction of about one-third compared to 2016. We do expect continue 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 have $2 million of net debt outstanding, and a $185 million borrowing base under our reserve base running facility. Capital expenditure for 2017 totaled approximately $81 million. And for 2018, we budgeted $170 million in total CapEx.
With that, I will turn it over to Robert.
Hi. Thanks, Mark, and good morning everybody. 2017 sure was an important year as we positioned the company for growth around our four 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 five-well completion program in the Midland Basin. The results of three of those wells that began producing prior to year-end were previously highlighted in our operations update in late January. The final two 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 as a 50% working interest in each of these two 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 base 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 as the case with this recent A well, it has been online for over 50 days, and it's still increasing in rate everyday. 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 two-well West Hartgrove pad in Reagan County with our one rig running. We have 87% working interest in these wells and are drilling the Wolfcamp B Upper and our first Wolfcamp C well. We have five wells drilled and waiting on completion today that we will start fracing in April, and should have eight wells to complete in total in this package.
A little bit on the Eagle Ford, late in the fourth quarter we started 11-well completion program in Southern Gonzales County. Five wells were discussed in our January update as they came online in December. The last six wells came online in January of this year. We have a 25% working interest and operate the six-well Cross B pad. It had average peak 30-day rates of 507 Boe per day, being 94% oil, but average lateral length of those wells is right at 4900 C. 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 show program.
We plan to start drilling on a five-well pattern 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 in these new wells online in the Midland Basin and the Eagle Ford have 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 primarily focus on the Wolfcamp A and B formations. This plan is based on a one-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. Six of these wells being our Cross B pad are already online. Because of the 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 pre-tax SEC priced present value of future cash flows of the total proved reserves discounted at 10% or PV10, increased nearly 600% to $599 million compared to year-end '16. As you will see when we posted our updated corporate presentation, when using year-end strip prices, PV10 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 have not yet included in our well count.
We are seeing quite a bit of activity on Reagan County from other operators drilling and completing Wolfcamp C wells. And as you will know it in our updated corporate presentation when we posted on our Web site, we have included a number of C locations. We have spent considerable time this past year trying to layout development scenarios, where we can maximize lateral length. In some cases, this caused us to realize that we would have additional non-operated 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 will see that our total location count has expanded to 943 when you include the non-operated 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 7,300 foot lateral in 12.3 days from big rigs 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 non-core 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 will turn it back to Frank.
Okay. Just to wrap up on the prepared remarks, I just want to reiterate that we are 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 in a largely -- I don't want to say largely un-leveraged balance sheet, but a reasonably leveraged 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 and growing profitably and prudently.
So, Operator, we are now ready to take any questions that the audience has.
Thank you [Operator Instructions] Our first question comes from the line of Neal Dingmann with SunTrust Robinson Humphrey. Please proceed with your question.
Good morning, guys. My first question, Robert, probably for you; how do you guys think about -- I know you haven't put maybe a quarterly out [Ph] to the entire year, but how do you think about sort of cadence or timing throughout the year, and you know, along with that, how can you be sure of getting the frac spreads when needed?
Well, we are pretty confident that we are going to get the frac spreads when we need them. We fracked several wells in August timeframe, we got the same frac crew back in December to do that five-well group, and then we got them lined up to start in April. And by the time we work through with them, we will frac eight wells. So the cadence will be we will get eight done April-May, maybe taken to June a little bit, and then we will 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 agreed that, it sounds like there certainly has been a lot of success with Wolfcamp C by lot of the peers there. I forget, in your plans, you know, when [indiscernible] account now, are you assuming much of that, or what do you -- how are you thinking about that for the latter part of the year?
Well, we are drilling one right now. It's a two-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 will 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 two rigs.
All right. Then just last, very quick, just on service cost, any change recently?
No, not really. I mean, there is a little bit of creep always especially as prices move around, and you are 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 are considering some other things to help alleviate whatever cost increases we may have. We are looking at the use of in-basin 100 mesh [Ph] in our proppant design. And we are trying to improve the number of stages we do a day. Therefore, we are dropping our total cost. So, those are the things we are working on everyday.
Very good. Nice update. Thanks, guys.
Thank you. Our next comes from the line of Gordon Douthat with Wells Fargo. Please proceed with your question.
Hi, good morning everybody. Excuse me.
Good morning.
Just wanted to get your thoughts on the second rig and what you need to see happen there to get that rig on, and what the timing might be?
Well, we are -- you know, Gordon, we have been a little non-market to meddle [Ph] on that, because we are 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 are going to talk about that at the Board level here. But committing to that second rig, or if one of the acquisitions we are 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 timeframe.
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 are 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'd previously talked to the market a couple of months ago, how is the pipeline looking from a trade or acquisition standpoint in the Midland?
The pipeline, you know, do we have anything ready to go to our 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 are non-operated acreage, operated acreage, so we continue to beat that down.
So I would say that the - Robert, you might adjust what I am saying here when I am done. But, I would say our deal flow is pretty good ranging from small things that are a 1000 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 little [indiscernible] in terms of whether the buyers and sellers can get together. But, we have 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 are plenty busy enough. Our challenge is making sure we are 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 at the other end. And hopefully, we get some things accomplished here in the near term.
Okay, thanks very much guys.
Thank you.
Thank you. Our next question comes from line of John Aschenbeck with Seaport Global Securities. Please proceed with your questions.
Good morning, everyone and thanks for taking my questions. My first question is in regards to 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 IORs from the legacy type curves was in the 34% to 81% range of $60 oil depending on which asset you are looking at in the Midland Basin. Was curious as to how the new economics compared to those legacy metrics?
Well, we have big screen that we are going to show those. We are going to drop the curtain here pretty soon and show you, John, I am just teasing a little bit. The economics continue to be a little bit better than what we've have had previously. Just because our type curve has changed, we are 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 are really pleased with what we have put together and the results we have 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 are 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 am little hesitant throwing it out there until we get it out there for the general public so. But it looks like as Robert said, we are 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 followup here is just in regard to what you all think is kind of the next stage of completion optimization. Seems like you may have hit the upper end of proppant [Ph] intensity, but is clearly no leverage you can pull. I was just hoping maybe could share with us what new types of concepts you plan to test during this year.
There is probably not a whole lot that we are going to change other than where we are fracking wells close to existing production, we actually might back off the frac size and intensity a little bit. And then, we are reviewing the idea of diverters in these again we will call them infill for lack of a better word, but very 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.
Okay, great. Appreciate that. That's it from me. Thank you for the time.
Thanks, John.
Thank you. Our next question comes from the line of Ron Mills with Johnson Rice & Company. Please proceed with your question.
Hey, Robert. Maybe just a quick follow-up on the recent question on the type curves. If you are shifting the type curves or at least the shape of the type of curves a little bit but keeping EUR as the same, is that implication that the wells have come on a little bit better rates and you are just forecasting a steepening of the decline for now before and until you potentially revisit that, or -- I am just trying to figure out what are 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 cure. 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 and certain areas or certain targets in certain areas. We left at the same and adjusted our type curve up early time. And then, yes, the impact is that the climb 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 have talked for two or three 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? Do you think you'll start to see some of that impact '18? I am just trying to figure out the lead time on activity.
Sure. And that's a fair question. Even if brought the rig in July and our plan was to go to bigger pads where we are consistently getting three or four wells per pad, we probably wouldn't bring on a whole lot of extra production in 2018. And I would 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 are committed to putting online sooner than later, some of the second rig maybe backend weighted or early '19 before we start seeing production from it.
Okay. And then when you think about a rig line, since you are drilling with one 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 are drilling 5000 footer or 10,000 footers. But our internal review of things is that a 7500 footer is going to average in the high 6 million -- $6.8 million to $7 million range. If we averaged 85%, you kind of end up with that if you drill 20 and complete 20 wells a year. That order of magnitude you are pretty close. But we are going to end up averaging probably north of 8000 foot laterals closer to 8400 foot this year based on what we've got on the schedule for one rig. And we will probably average about 85% to 90% working interest. So, it's a little bit of moving target there. But that's about a one rig program, 140 - 50 million a year.
And just to clarify that 140 to 50 includes the longer laterals, so it's a little bit higher than that 6.7 million well cast?
Correct. Yes, it's a blended -- that's a blended number for this year, but that's -- you are 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 have been successful getting your frac crew and seemingly on time, so kudos to you on that. But especially when you think about later this year and next year, I think two rigs is 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 two rigs going? And that's it. Thank you.
Yes. I mean it does become a little bit more of a challenge because now you have got an inventory that's growing pretty rapidly. But under two 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 are going to just continue to use our relationships and use these good vendors. And we will all make a little bit of money.
Thank you. [Operator Instructions] Our next question comes from the line of John White with ROTH Capital Partners. Please proceed with your questions.
Good morning, gentlemen. Thanks for taking my call.
Hey, good morning, John.
Yes, you are doing a good job at least on this updated PowerPoint that you mentioned Jo Mill…
You are going to put it -- hey, John, we are going to put it out at 11:02 pm, so you got to work tonight, okay?
You said, pm, okay, I got it.
Yes, pm. Yes, right. You have got to work tonight.
That's what you like to do.
So 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 first time you talked about Jo Mill on the call. Have there been some recent offset operator Jo Mill completions that you would want to talk about?
We are not the Jo Mill expert. It is very -- there is 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 planned work in certain places. It's one of those benches or targets that look very economic. And I think there is 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 will 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 one rig scenario. If we brought in a second rig somewhere in the acreage where it's appropriately located, then it could be in the plan. But, it is not likely in 2018.
Okay, thanks. And Frank, I have got my calendar set for 11 o'clock tonight.
Okay, sounds good. We will try to meet that goal, John.
All right, thank you.
Thank you. Mr. Lodzinski, there are no further questions at this time. I'll turn the floor back to you for any thoughts.
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 are 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 you will all later. Thank you.
Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.