Earthstone Energy, Inc.
Q1 2016 Earnings Call Transcript

Published: 11 May 2016

[Operator:]

Good morning and welcome to the Earthstone Energy First Quarter 2016 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] And as a reminder, this conference is being recorded. Joining us today are Frank Lodzinski, President and CEO; Robert Anderson, Executive Vice President, Corporate Development and Engineering; and Neil Cohen, Vice President, Finance and Treasurer. Mr. Cohen, you may begin.

[Neil Cohen:]

Thank you. Welcome to our first quarter 2016 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. For a complete description of this disclaimer, please refer to our press release from May 10th. Also, listeners are encouraged to read our 10-K for the year ended March 31, 2016 in its entirety as well as all other reports and documents filed with the SEC for more detailed information of the Company. The content of today’s call will include remarks from Frank regarding near term priorities, remarks from me regarding recent financial performance and remarks from Robert regarding operational performance. I’ll now turn the call over to Frank.

[Frank Lodzinski:]

Well, thanks Neil and welcome to all for this conference call. Look, given our reduced activities because of the global prices we've seen in the first quarter, we're going to keep our formal remarks rather short and focus on just a handful of topics. As Neil mentioned, he'll give you a brief financial overview and Robert will talk about operations. That said, I will tell you that we are on track to close our acquisition of Lynden Energy very soon. We expect the shareholder meeting tomorrow and closing in the near term just waiting -- we just have to wait hopefully a very short period of time we get final approval of the British Columbia courts. So, Lynden will close soon. We anticipate adding about 1,300 Boe -- over 1,300 Boe a day and about 5,900 net acres in the Midland Basin that are largely held by production. So with that, kind of answer, I'll turn it back to Neil.

[Neil Cohen:]

Thanks Frank. For the quarter ended March 31, 2016 our production averaged 3,576 Boe per day which is a 7% decrease quarter-over-quarter and year-over-year. Production consisted of 63% oil, 25% gas and 12% natural gas liquids. From a finance perspective, we reported adjusted EBITDAX of $1.9 million, a net loss of $6.4 million or $0.46 per share and cash flow from operations before change in working capital of $0.04 per share. During the quarter we focused on preserving our liquidity and enhancing our cost structure. We incurred approximately $2.4 million of capital expenditures, some of which was related to the drilling of our South Green Upper Austin Chalk well in Fayette County that we drilled in late 2015, commenced early 2016 and then brought online in February 2016. In addition, we spent a small amount of money on procuring our four well Boggs Unit for completion later in the year. Total cash operating expenses inclusive of LOE, reengineering workovers, ad valorem taxes and services taxes as adjusted totaled $3.6 million or a 30% reductive year-over-year. G&A totaled $3.2 million or $9.83 per Boe both skewed higher by approximately $700,000 due to cost related to our transaction of Lynden Energy, professional fees related to Sarbanes-Oxley compliance and severance payments to employees. We anticipate our G&A to be less than $5.50 per Boe in the second half of the year primarily due to production contributed to Lynden has little reoccurring corporate G&A associated with the properties as well as reduced salaries and certainly offset have recently gone into effect. In March and April we layered on hedges opportunistically. From April through December 2016 we hedged approximately 50% of the midpoint of our oil and gas production at $50.46 per barrel and $2.51per MMBtu, respectively. We're currently going through our annual re-determination process to announce our new borrowing base as soon as we get from our lenders. Pro forma for the Lynden transaction, we expect to have approximately $48 million of debt outstanding and $12 million of cash as of March 31. I'll now turn the call over to Robert.

[Robert Anderson:]

To talk about given our reduced activities in the quarter, but as Neil mentioned, our production was down about 7% compared to the fourth quarter of last year. This decrease was due to lack of completion activity on the 12 Eagle Ford wells that we have drilled, but are waiting on completion along with natural declines on well drilled in 2015 and the fact that we chose to allow flowing wells to continue to produce at lower rates as a result of postponing the capital expenditures for installing artificial lift on those flowing wells. While it's difficult for us to see our production decline, we chose to prioritize and defer capital expenditures in this low price environment. We always work to optimize our field operations. In the first quarter, we had a few producing units that needed to be taken offline for a few days for normal field maintenance. As an example of how we've controlled our operating cost in our operated Eagle Ford asset, our field guys have done a great job reducing lease operating expenses. Even with a little bit of reduction in production volumes, these guys have helped improve our margin by reducing the operating cost per barrel of oil equivalent by about 24% in the first quarter when comparing to the 2015 LOE per Boe. In this area we're producing for less than $6 a barrel of oil equivalent. We're thinking hard about fracing and bringing online our four well Boggs Unit in Karnes County in the second half of the year, which we can deliver an attractive internal rate of return of 80% when considering current strip prices and just the completion cost of approximately $4 million gross cost per well. So while our drilling and completion activates have been limited, we are well positioned to achieve production growth via our Eagle Ford well inventory and the acquisition of Lynden. I want to remind you all that we have accomplished a great deal in terms of preserving future upside. We have converted a large portion of our acreage to held-by-production status while improving our lease exploration profile to minimize the near-term exploration. In our operated Eagle Ford area, we preserve upside opportunity associated with the Eagle Ford, Upper Eagle Ford, Austin Chalk and potentially other formations for the future. Approximately 60% of our operated Eagle Ford acreage is HBP. In the Williston Basin, nearly all of our acreage is HBP and held for future Bakken and Three Forks development. Our 12 well frac inventory provides us an opportunity to rapidly and significantly ramp up production pending commodity price improvement, while at the same time reactivating our drilling programs when prices do improve. Finally, as previously communicated, we chose to stack our rig for an initial three month period through the end of April. In doing so, we incurred a $1.3 million rig idle expense in the first quarter. We will likely incur a similar charge in the second quarter as we have decided to stack the rig for another three month period through the end of July. Our remaining total liability for the rig contract is $3.9 million. We continue to have constructive conversations with our rig contracts on various alternatives. I'll now turn the call back to Frank.

[Frank Lodzinski:]

Okay. Thanks Robert. I want to wrap up, at present we're clearly focused on completing our Lynden acquisition which as mentioned brings additional production and derisked upside. We've identified about 100 vertical and 50 horizontal drilling locations. I notice, it's redundant, but I want to stress that the leasehold is largely HBP and I believe we can maintain -- that we can initiate drilling operations and still remain within cash flow. So in the near term, we intend to integrate Lynden into our activities and continue to focus on optimizing our cost structure field operations and preserving the upside in our assets. You know, we've been -- I think very cautious in starting of the fourth quarter and throughout the first quarter in the approach to our activities and therefore our guidance. I just felt it appropriate that with oil heading down in the 20s, as it did in the first quarter. So, we put out our guidance we have generally indicated that our current plan is to stay within cash flow. But I do want to say that pending price cooperation, we can accelerate capital expenditures and hence production very, very quickly. We can start up by accelerating the completion of our 12-well frac inventory, while we're ramping up drilling again very quickly. To kind of give you an order of magnitude if you will, our 12 well frac inventory alone, if you add up our 12-well frac inventory and take a look at the IP 30s Forum, that could add cumulative collectively about 3,000 Boe a day and that's in our interest. And I think that's frankly a conservative to realistic number, and it could actually be a little bit better, because some of these wells have longer laterals than surrounding wells. So, one way that's our plan right now to stay within cash flow, preserve our upside, maintain post Lynden production levels and be ready to accelerate capital expenditures when we deem it appropriate. The last thing I want to say is that we continue to remain active in pursuing both corporate and asset acquisitions with current production and development potential. It appears to us that the recent uplift in commodity prices has resulted in additional activity in the A&D market, and perhaps the disconnect between buyers and sellers is narrowing. With that said, we are going to conclude our formal remarks and open up the line to questions.

[Operator:]

Thank you. At this time, we'll be conducting a question and answer session. [Operator Instructions]. Our first question comes from Neal Dingman from SunTrust Robinson. Please go ahead.

[Neal Dingman:]

Good morning guys. Frank, let me ask on a typical question first as part as when you and Robert and you are looking at bringing the rig back, bringing activity, is it more looking at the strip, or how are you guys versus like the questions is just a certain price? But how do you'll think about kind of bringing activity back on a sustained basis?

[Frank Lodzinski:]

Well Neal, as i think I indicated you know in the prior call that we had after year-end, that's a very difficult question. I mean at -- what you have right now is you have a strip that's relatively flat and you know we could probably justify bringing the rig back. Where the price is going in the near term? I'm looking for a little bit of price stability, so I can tell you right now, that, we could think about bringing the rig back at the current strip, but you know, then you are incurring all those costs and then you are going forward. So, then you got to get the -- I don't know qualitative is the right word, but subjective judgment in there. So, it's just difficult decision, and sorry I'm being meanly mouthed about that.

[Neal Dingman:]

No, is it -- and I think Robert had alluded to, [indiscernible] talk about, is it remainder of this year or in next year as far as HBP, is there a well or two, or how many wells you'll have to drill just to -- I know you got almost everything HBP'ed, but how do you think about what you have for requirement?

[Frank Lodzinski:]

Well, as I mentioned, I think and Robert jump in here if I get some of my stats wrong please. But generally in the southern Gonzales and northern Karnes area where we have the three project areas, the Boggs Unit, the unit next to it is HBP and the one up to the north has ample lease time going into late 2017 and 2018?

[Robert Anderson:]

Yes.

[Frank Lodzinski:]

So we're good there. The Lynden stuff is mostly HBP. A lot of the smaller stuff that we're doing the Bakken in the core areas of the Bakken, that's largely all HBP. So where the question comes up is in the Fayette, Gonzales area, the primary lease block that we have Flatonia Energy. And I'm sure I have the stats right now, but that's about -- if I had to guess, that's about 60% HBP and the remaining 40% could expire over 2.5 years, is that generally about right, Robert?

[Robert Anderson:]

Yes. That's right. Neal, some of those we can extend with very little dollars and that's why we got a little bit of money in our capital budget for the year to be able to extend some leases out and help us out there.

[Neal Dingman:]

Got it. Then guys, last -- just sort of last question. By having now after that Lynden closes, by having that foothold, does that -- do you think give you an edge as far as either bolt-on or other acquisitions in the area? How do you think about that?

[Robert Anderson:]

Definitely gives us an edge that we're sort of boots on the ground I guess with a good partner and hopefully the ability to see a different kind of deal flow and just the asset shots selling deals, maybe we're getting involved on the front-end of some things.

[Neal Dingman:]

Would you all stay non-op, I mean if you saw some other things, or is the choice still if you have your…

[Frank Lodzinski:]

No. I mean you know, I'll say absolutely not. I'll say that historically we've operated 75% to 80% more than two-thirds of our production. We like to be in control where we can from an operation standpoint where we can realize the benefit of the cost effective operations that we demonstrated project after project and year-over-year. Now that said, if there was an exemplary opportunity in a non-op situation, I wouldn't disregard it, but that clearly is not a primary focus.

[Operator:]

Our next question comes from Steve Berman from Canaccord. Please go ahead.

[Steve Berman:]

Good morning everyone. Expanding on the, when you get more active kind of theme, and most companies are going to work their DUC inventory down before bringing back rig. Can you talk a little bit more about your 12 wells in the Eagle Ford that are not the four Boggs opportunity, other eight now, where are they, which are likely complete first, if pricing got better out there?

[Robert Anderson:]

Steve, those are all in southern Fayette County, the other eight wells. There is three in two units that are fully HBP'ed by two other producing wells in those in those unit, so there is six wells in two separate units that are already HBP'ed, so there is no issue there with just sitting around waiting for some period of time, and the other two are in a unit that has some immaterial lease extension dollar that we'd have to spend to keep that unit alive. So, I think it's all, what the commodity price is and balance between cash flow and capital expenditures and there is -- we're ambivalent as to which unit we go do first from a performance standpoint, it's not going to make a whole lot of difference other than two of them have three units in them and one unit has only two wells. So…

[Steve Berman:]

Then Frank, in terms of the A&D markets, just thinking about what you said before, what's more likely to happen, more small fill-in things or something a little bit bigger? I don't know if there is any more Lynden deals out there? But based on what you are seeing now, how do you think this plays out from kind of 30,000 feet?

[Frank Lodzinski:]

I may have to move up to 40,000 feet, but I'll get you there, okay. Look, we've had significant meeting and discussions amongst our Board members, our joint owners, and our management staff here. So, the intent is to close Lynden, get that integrated, move forward. And we are entirely focused on finding a bigger deal, operated deal with a focus in the Permian and the Eagle Ford, okay. I would really like to try to build this and this might differ from some other people out there, but I'd really like to build this to be a -- basically a Permian Eagle Ford company, okay. And, so we are focused on trying to find deals that are substantial, three digits that have a lot of running room and that have appeal in this market place both to the public markets and so forth. Now that said, that's all a lot easier said than done. You know, you guys are call or the experts in terms of flow volume and following and investors and all of that kind of stuff. I really think that getting this Lynden deal closed is a step in the right direction, might bring some additional trading volume, might bring some additional interest to Earthstone, not that there is not interest, but low flow volume and so forth. We do have a lot of friends in the industry that have -- in the financial community that have indicated that if we can find a substantial deal that likely given our track record and so forth, we could get it financed. So, we're clearly focused everyday on finding a bigger deal, a bigger operated that appeals to the market, and our secondary view is that, we'll continue to look for bolt-ons like we've done in northern Karnes and southern Gonzales County.

[Operator:]

Our next question comes from Jeff Grampp from Northland Capital Markets. Please go ahead.

[Jeff Grampp:]

Frank, you mentioned in your prepared remarks that the net incremental production potential on those DUC to potentially be conservative. Is that all, lateral length driven you think? Or are you guys looking at anything on the completion front? I know you guys have that restricted choke program you saw some good results on it. Can you guys talk about any other factors that may lead to that number being potentially conservative?

[Frank Lodzinski:]

Well, I'm going to turn that over to Robert in a second, and I'll give you my two cents. My two cents is that we've had a goodly amount of understanding on the control frac. We have a goodly amount of understanding of what the well performance in surrounding some of this DUC stuff is, and for an example, in the Boggs track down there, I guess Robert -- tell about the length of the lateral on the Boggs and the lengths of the laterals that are going into some of these estimates offsetting the Boggs.

[Robert Anderson:]

The way we designed our Boggs type curve is based on all the offsetting wells which average about 4,700 feet in lateral length, competed lateral length and our Boggs wells are on the order of 6,700 feet across the average of all four wells. But we didn't adjust our type curve necessarily for the lateral length. But we think there is some conservatism built into our type curve in that area. The same thing applies in southern Fayette County where we've got some longer laterals on these uncompleted wells compared to the offset wells that we're using.

[Frank Lodzinski:]

So it's not arm waving on EURs, it's just saying conservative based on longer laterals generally.

[Jeff Grampp:]

Then, shifting over to the Permian side, can you guys just remind me on that, the one non-op horizontal you guys are going after? What county and what zone you are going after there?

[Robert Anderson:]

It's in Howard County and it's to be determined. It's likely going to be a Wolfcamp interval, but at this point. That's about all I'm going to say.

[Jeff Grampp:]

Then, last one from me on the completion front. You've seen a lot of peers in the Midland Basin talk about some different completion optimization test frac stages, proppant, all that good stuff. Are you guys -- you and CrownQuest looking at doing anything there, or do you guys kind of feels like you a standard recipe that you think gets some pretty good results here?

[Robert Anderson:]

It's too early for me to comment on how CrownQuest is fracing wells, but I will tell that, in Howard County, pulling public data, CrownQuest has some of the best wells in the country, so whatever their secret sauce is, it seems to be working.

[Operator:]

Our next question comes from Welles Fitzpatrick from Johnson Rice. Please go ahead.

[Welles Fitzpatrick:]

Just follow-up I think on Steve's questions. Did you guys say how much capital will be needed to run through this 12 DUCs and have the 3,000 Boe.

[Robert Anderson:]

I'm going from memory, it's $18 million I think total.

[Welles Fitzpatrick:]

Okay. That's perfect. And then in regards to, look to Lynden, at least before the borrowing -- the new borrowing basis come through, is it fair to mile out the straight map on a combo of $80 million as reported.

[Frank Lodzinski:]

No. No. Come on Welles. You're much better than that.

[Robert Anderson:]

We wish.

[Welles Fitzpatrick:]

I'm trying to be optimistic here Frank.

[Frank Lodzinski:]

I know.

[Robert Anderson:]

We are every day.

[Frank Lodzinski:]

Look, I'll put you on retainer, run around New Orleans for me and find me a bank that will do that. We don't know where we're going to come out, but you know, you got to expect a significant reduction like preferred [ph] or something, just like everybody else is going through.

[Operator:]

Our next question comes from Brad Carpenter from Cantor Fitzgerald. Please go ahead.

[Brad Carpenter:]

Just a few quick ones from me. Frank, assuming the Lynden deal closes as anticipated, could you provide us with some preliminary thoughts around how you think about D&C capital allocation for 2017 between the Permian, Eagle Ford and Bakken? Obviously there is lot of moving parts between now and then, but is it right to think about the Permian getting incremental dollars based on rates of return or would incremental dollars go towards the DUCs in the Eagle Ford first, just how we should think about that?

[Frank Lodzinski:]

The outside of that was, could I give you some additional color around the capital expenditures and the allocation. And the short answer is no. Now, with that said, okay, look, we're going to -- what we need to do, and I'm sorry, I'm stuttering. What we need to do is get Lynden closed, get it -- what's the word, integrated into our organization and so forth. And then we need to go sit down and talk with the CrownQuest people. You know we think they are first class guys. And we have not really bothered them to any length as we're not in control right now of the entity and so forth. So, we need to sit down and visit with them to understand what their capital plans. The acreage situation that we have is small in relation to their overall acreage position. And you know, if we like what's going on, and maybe we can visit with them about moving some of their capital budget around -- towards our joint acreage rather than other acreage that they have and so forth. Given the fact that our Boggs and DUC inventory and so forth, we have no immediate needs to do that from a lease preservation standpoint. In the Bakken virtually everything is HBP and if we chose to go non-consent, I think our average is less than a 5% working interest up there. If we chose to go non-consent on a well in favor or doing something else, we're only out of the wellbore and there is a lot of wellbores to be drilled up there. Then finally, up in Fayette and Gonzales, you know we've commented on how much is HBP and the fact that a lot of these leases, we can extend them. So, really I use the term meanly mouthed a lot, but that's the situation we're in right now. We hope to get this closed and perhaps in connection with the second quarter or this summer, get out some more definitive guidance on our capital program and so forth. Sorry, I can't be much more specific.

[Brad Carpenter:]

No. That's understandable. It's still very helpful. And then if we could just back to M&A, I know you have discussed this a few times throughout the call today, and I know you guys do a great job of tracking the pulse of the market. But, I'm curious with the prolonged slump in WTI prices. Are you starting to see higher quality packages come to the market? And then I guess the second part of that question is, Frank you mentioned the bid/ask spread, you are starting to see some collapse in that. What's driving that near view? Is it the sellers going to accept lower prices, or is the amount of capital especially from the private side shaking some of these deals, that's pushing up bid price?

[Frank Lodzinski:]

I'll let Robert comment, and then if I have any differing or alternative views, I'll chime in. Go ahead.

[Robert Anderson:]

The quality of packages is definitely improving and has improved, and because of that the price you are seeing paid for packages is going up, because it's -- the dollar per acre hasn't changed in the Permian Basin regardless of where the price, the WTI price has been over the last two years. So, I think that's what's driving the higher purchase prices, and I think there is various reasons why we're seeing more and more quality come to the market and more and more assets come to the market. We've gone through a retraction of people, and therefore companies can't spend time on assets and to raise money to go fund other projects, this is the best way to do it and they are never going to get the people invested into those projects, so may as well sell them. And I think they refine -- realize that the prices aren't really going to change all that much. So that's my two cents work.

[Frank Lodzinski:]

And although we do look at brokered transactions, we are working very diligently to find deals where people will stand still. I think the two things that we still have working for us is the fact that we have a significant historical track record of creating value. So in a privately negotiated transaction there may be an element of cash and stock. And a seller -- clearly it's not -- clearly that's not going to be if Anadarko puts something on the market or Devon put something on the market, that's not going to be a course action. But in other kind of transactions, perhaps that's a deal, because we do have the track record. And there you have it, so like I said we're focused. I mean if I had my drudgers, I'd love to do you know a $200 million Permian based deal and a $200 million Eagle Ford based, and we're working diligently towards that every day. We have some conversation going with some sorts, but no guarantees yet.

[Operator:]

[Operator Instructions]. Our next question comes from John White from Roth Capital Partners. Please go ahead.

[John White:]

I wanted to make sure, I got the numbers correct. Neil, did you say pro forma for the Lynden closing, it's going to be $40 million of bank debt, $12 million of cash.

[Neil Cohen:]

Yes $48 million of bank debt, maybe a snitch higher and around $12 million or $13 million or cash.

[John White:]

The debt number is $48 million.

[Neil Cohen:]

Yes.

[John White:]

Okay.

[Neil Cohen:]

Then that's as of March -- using March 31st, balances.

[John White:]

Thanks very much and you are steering the ship prudently as you guys know how to do. So thanks for taking my question.

[Frank Lodzinski:]

I wish I had a $60 environment to steer this ship, but we'll just continue to trying to do what we're doing. Thank you all for the calls for participating. Thank you for the questions. You know we're always open and call us if you have any further questions. And operator, we're done right now.

[Operator:]

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