Ring Energy, Inc. (REI) Q2 2017 Earnings Report, Transcript and Summary

Greetings, and welcome to the Ring Energy, Inc. 2107 Second Quarter and 6-month Financial and Operating Results Conference Call. [Operator Instructions] It is now my pleasure to introduce Tim Rochford, Chairman of the Board and Co-founder of Ring Energy, Inc. Thank you, you may begin.

Thank you, operator, and I'd like to welcome all listeners to the second quarter and 6-month 2017 financial and operations conference call for Ring Energy, Inc. Again, I'm Tim Rochford, Chairman of the Board. Joining me on the call this morning is our CEO, Kelly Hoffman; David Fowler, our President; Randy Broaddrick, our CFO; and Danny Wilson, Executive Vice President and in-charge of all operations. Now today, we will cover the financials and operations for the second quarter and six months ended June 30, 2017. We will review our results and provide some insight, as to our current progress thus far, in the third quarter. At the conclusion of the second quarter and six month overview, we will open up the call for any questions you may have. And at this point, I'd like to turn it over to Randy Broaddrick, our CFO, and ask Randy to review the financial highlights. Randy?

Thank you, Tim. Good morning, everyone. Before we begin, I would like to make reference that any forward-looking statements, which may be made during this call, are within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. For a complete explanation, I would refer you to our press release issued Tuesday, August 8. If you do not have a copy of the release, one will be posted on the company website at www.ringenergy.com. For the three months ended June 30, 2017, the company had oil and gas revenues of $14.5 million and net income of $1.9 million, as compared to revenues of $7.1 million and a net loss of $15.9 million in the second quarter of 2016. For the six months ended June 30, 2017, the company had oil and gas revenues of $26.75 million and net income of $3.2 million, as compared to revenues of $13.2 million and a net loss of $31.2 million in 2016. The two primary factors behind the change in net income are increased revenues due to increased production and not having a ceiling test to write-down in 2017, versus a pretax write-down of $25.45 million for the 3-month period and $46.9 million for the 6-month period ended June 30, 2016. For the three months ended June 30, 2017, our oil price received was $45.33 per barrel, an increase of 10% from 2016. And our gas price received was $3.22 per Mcf, a 38% increase from 2016. On a per BOE basis, the second quarter 2017 price received was $42.90, an increase of 17% from the 2016 price. For the six months ended June 30, 2017, our oil price received was $46.81 per barrel, an increase of 35% from 2016, and our gas price received was $3.23 per Mcf, a 52% increase from 2016. On a per BOE basis, the 6-month period ended June 30, 2017, price received was $44.11, an increase of 43% from the 2016 price. Production cost per BOE for the three months ended June 30, 2017, decreased to $10.40, as compared to $11.31 in 2016. For the 6-month period, production cost per BOE decreased to $10.26, as compared to $10.94 in 2016. Going forward, we anticipate our production cost per BOE to be below $12, though we continue to use $12 in our internal models. Most production taxes are based on values of oil and gas sold. So our production tax expenses directly correlated to the commodity prices received. Our production taxes, as a percentage of revenues, remained relatively flat and should continue to be. Our total depletion, depreciation and amortization, or DD&A, including accretion of asset retirement obligation per BOE increased for the three months ended June 30, 2017, to $15.71 per BOE as compared to $13.90 for the same period in 2016. Our total DD&A per BOE increased for the six months ended June 30, 2017, to $14.71 as compared to $14.48 for the same period in 2016. Depletion calculated on our oil and gas properties subject to amortization constitutes the bulk of these amounts. As to total amounts, total DD&A increased approximately 96% for the 3-month period ended June 30, 2017, at approximately 44% for the 6-month period as compared to the same periods in 2016. This increase is primarily the result of increased production volumes. Our overall general and administrative expense, or G&A, increased $446,000 for the three months ended June 30, 2017, as compared to the same period in 2016. And $1.1 million for the six months ended, as compared to the same period in 2016. On a per BOE basis, this equates to a decrease from $9.87 in 2016 to $7 in 2017 for the 3-month period and from $9.66 in 2016, to $8.59 in 2017 for the 6-month period. The increase in total was primarily a result of an increase in stock-based compensation of $304,000 for the 3-month period and $711,000 for the 6-month period, as compared to the same periods in 2016. On a per BOE basis, the decreases were - the increases were partially - the per BOE decrease was the result of increased production volumes. On a diluted basis, the income per share for the three months ended June 30, 2017 was $0.04. Excluding the $812,000 noncash charge for share-based compensation, this income is increased by approximately $0.01 per share for income of $0.05 per diluted share, as compared to a loss per share of $0.41 as reported, or a gain of $0.01 per share, excluding both a pretax ceiling test write-down of $25.45 million and a $508,000 noncash charge for share-based compensation in 2016. On a diluted basis, the income per share for the six months ended June 30, 2017 was $0.06. Excluding the $1.8 million noncash charge for share-based compensation, this income is increased by $0.03 per share for income of $0.09 per diluted share, as compared to a loss per share of $0.90, as reported, or a loss of $0.03 per share, excluding both a pretax write-down of $46.9 million and a $1.1 million noncash charge for share-based compensation in 2016. As of June 30, 2017, we had no amounts drawn on the $60 million borrowing base on our credit facility and had cash on hand of $12.1 million. Subsequent to June 30, 2017, the company completed an underwritten public offering, resulting in a net proceeds of approximately $59.2 million. For the three months ended June 30, 2017, we had positive cash flow of approximately $8.8 million or $0.17 per diluted share, compared to approximately $3.1 million or $0.08 per diluted share for the same period in 2016. For the six months ended June 30, 2017, we had positive cash flow of $16 million or $0.32 per diluted share, compared to approximately $4.4 million or $0.32 per diluted share for the same period in 2016. With that, I will turn it back to Tim.

All right. Thank you, Randy. We appreciate that report. I'd like to now turn it over to Kelly Hoffman, our CEO, and Kelly's going to give us a review and kind of an overview, if you will, of both the second quarter as well as the first half of the year. Kelly?

Thanks, Tim and thank you, everyone for joining us on the call today. In the three months ended June 30, the company on our Central Basin Platform asset drilled five 1.5-mile lateral wells and three 1-mile laterals, and we're currently drilling the ninth well, which is also a 1.5-mile well. We completed and put into production four of the new wells drilled in the second quarter of 2017, two of which are in the testing phase and the others were recently just drilled of course, and then the remaining four wells drilled in the second quarter are awaiting completion. And on our Delaware Basin property, we drilled two new vertical Cherry wells but we're awaiting completion on those and we did complete two wells within that same - from the first quarter that were leftover. For the six months ended June 30, the company drilled five 1.5-mile laterals, 11 1-mile laterals and we're currently drilling the 17th well, which is the one, I just mentioned a moment ago, it's 1.5-mile on the - and those are all in the Central Basin Platform asset. In addition, we drilled two new saltwater disposal wells, performed a lot of extensive work, upgrading a lot of the facilities, oil and gas facilities, as well as the water handling infrastructure. On our Delaware property, we drilled four new vertical Cherry wells, performed recompletions on two existing Cherry wells and we drilled a new saltwater disposal well and we're going to continue to upgrade and expand all the water hauling systems out there too in preparation for the future. Net production in the three months ended June 30, 2017, was approximately to 338,000 BOEs, barrel of oil equivalent, as compared to the net production of 191,000 barrel of oil equivalent the same quarter in 2016, and that's a 77% increase. Net production was 266,000 barrels of oil equivalent in the - for the first quarter of 2017, and would've been a 21% increase over that quarter. So June 2017 average net daily production was approximately 4,110 barrel of oil equivalent, as compared to net production of 2,296 barrel of oil equivalent in June 2016. The net daily production of 3,618 barrel of oil equivalent in March of 2017. For the six months ended June 30, 2017, net production was approximately 604,000 barrel of oil equivalent, as compared to 416,500 for the six months ended June 30, 2016. And that's a 45% increase. Our average net daily production increased to approximately 3,337 barrels of oil per day and the average sales price for that was about $44.11, I think, as compared to $30.78 in 2016, and that too is an increase of 43%. And as you know, we recently extended our contract on the first rig that we had out there drilling through the year-end of 2017, adding somewhere around 8 to 10 new wells, and we've added the second rig we just announced recently and we can talk more about that in the question and answers. With that, Tim, let me turn it back over to you, you got to introduce Danny.

You bet. Thank you, Kelly, very good. Lots of nice things have been taking place, obviously. With that, I will turn it over and introduce Danny Wilson, Executive VP, in-charge of all operations and ask Danny to, if you would, Danny just kind of give us some highlights and overview as to what's taken place now and for the remainder of the year.

Sure. Tim, thank you. Kelly give you the well counts for the 3-quarter - for the second quarter and for the 6-month period. At the end of the six months, we were finishing up our - or had just spudded our 17th well for the year, which would be our 20th well overall since we started the horizontal program. Just as an update to that, we have finished now our 19th well and are moving to our 20th well today. As far as the IPs go for the wells drilled in the second quarter, as Kelly mentioned, we IP-ed 2 of the wells that were drilled in that quarter, in addition to two wells that were left over from the first quarter, the average of those was between - or the - those wells IP-ed between 420 and 1,100 BOE per day with an average of 750 BOE per day. Since then, we have IP-ed 2 more wells that were drilled in the second quarter. The average of those two wells was 690 BOE per day, which brings the average for the quarter to 733. In addition now, we've drilled on - IP-ed 14 wells total from the beginning of the program, of those we are now sitting at an average of 658 BOE per day. When we did our original projections, we were looking at 550 BOE per day to 650 BOE per day, we're still very comfortable with that being an average, as we move forward. In addition, we had announced previously that we were seeing about 59 BOE per foot, that was at the end of the first quarter on our recoveries, and we still are looking at that average on a net BOE per foot of 59 BOE, we're still very comfortable with those numbers. Our GOR, I know there's been a lot of discussion about that with some of the other companies, particularly in the Delaware and Midland basin. We still are looking at a 93% to 95% oil ratio in our CBP, a little higher than that. The gas in the Delaware is a little higher than that, it runs at about 20%. But overall, we're looking at about a 93% to 95% oil cut. The Delaware Basin, as Kelly mentioned, we've drilled four wells to-date in that area and we have, on average, been seeing what we thought we would see. These are vertical Cherry Canyon wells are coming in on an average of about 60 barrels a day, which falls right in line with everything we had expected there. I would like to mention one thing on our CBP drilling program, we continue to see our drilling cost to be in line with our original estimates that we began the year with, which looks like we're drilling them at about $2 million per well for the 1-mile and $2.4 million for the 1.5-mile. And with that, I will turn it back over to Kelly.

Thanks, Danny. Tim?

You bet. Thank you, Danny. And I know that all of our listeners are looking forward to the Q&A. So back into some of this here very shortly. But I would like to turn this over now to David Fowler, our President, and then ask David just to kind of give us an overview of how things are moving along on the leasing end and what we're seeing, David. Thank you.

Thank you, Tim. We continue to press forward to expand our leasehold position in our horizontal target area on the platform, and in the second quarter, we really had some great success. On the platform, we added over 40,000 gross acres and over 34,000 net. So this now brings our leasehold total on the platform to over 100,000 gross acres and over 70,000 net, with over 90% of those acres located in our horizontal focus area. And looking back to the beginning of the year, we've added just over 50,000 gross, 40,000 net from a platform footprint. The 40,000 net acres we've added actually more than doubles what our net position was at the beginning of the year. So with the inclusion of our Delaware Basin acreage, this brings our combined Permian basin presence over 124,000 gross acres and over 91,000 net acres. One of the goals that we gave the land department was to increase the net-to-gross percentage on our leasehold. At end of Q1, our net-to-gross was just over 56%. Over the course of the second quarter, we can now report that our net-to-gross has increased from just over that 56% to now over 68%. Looking forward, we continue to pursue leasing opportunities that our land department mostly originates internally. And, we've always got acquisition targets on our crosshairs. Many of these ideas are sourced internally and others are brought to us from our network of Permian relationships. The second half of this year we'll continue to strive to increase our net-to-gross and with our clean balance sheet, we remain poised to react quickly and aggressively to acquisition our opportunities that fit our criteria. And now I'll turn it back to Tim for closing comments.

Okay. David, thank you. Appreciate that. Well listen, this concludes the company's portion of the review for the second quarter and the six months finance and operational updates. What I am going to do now is turn it back to Danielle, our operator. And go ahead and open it up for our Q&A, please.

[Operator Instructions] Our first question comes from Neal Dingmann with SunTrust.

Kelly, my first question maybe for you or Danny. Just once you're done with this initial program. I guess now up to about 30 wells. Can you talk a little bit about, you've got a pretty large footprint now with that almost 100,000 gross acres. Are you going to really continue to delineate? Or I guess, most specifically, I'm kind of wondering where you'd start to, regionally speaking, between sort of Northern Gaines and working down towards the Andres, where you'd start focusing the next wells, I guess, let's say beginning in '18?

In acquiring this acreage, of course, we took what we consider to be our signature, if you will, and applied it to those areas that we felt like it was best to go after acreage and then, of course, the acreage that we picked up is obviously resulted from that decision. And we like very much several of those areas that we have picked out, that we think are great areas that equal the type of things that we want to go after and we intend to go after those next, and we're currently have permitted a couple of wells up there, and the testing phase of those wells we're seeing everything we want to see, we like what we're seeing. And so I think, to specifically address your question, would be to say, we're going to move the rig into those areas where we can continue to see the tests that indicate to us that those are great areas to pursue, to maintain our average in our 55-barrel oil model that we built originally on the type curve.

And then with the new rig contract if I understand that right, you still have the flexibility, I guess, what, begin in '18, if you need to go to one rig or if you want to go up to three rigs?

Yes. Absolutely, always the case. The contractual relationships that we have with those rig companies are very short. And so we have a lot of optionality there, we could add a rig or we could delete a rig, before it would've moved against us and we felt that was necessary we could get down to one rig and continue to grow the company with that, or if we really feel like that the market's going with us and everything's up and up and we want to add a third rig, we could always give consideration to that.

And then lastly, Tim, just wondering if you have anything up your sleeve M&A-wise these days?

Well, that's a good question, Neal. And I'd tell you, as you know, Neal, we're constantly looking for opportunity. And at the end of the day, we've always had a track record and we still have that same goal and that's to build value and bring value to the shareholders. So we're constantly looking for opportunities as David pointed out on the horizon of the acquisitions, or any other ideas that come along, we're very in-tune and postured in which to explore that, if that, in fact, becomes a reality.

Our next question comes from Mike Kelly with Seaport Global Securities.

Just want to see - get kind of a sanity check here on our '18 thoughts. I mean, we've got you with two rigs ramping production fairly aggressively year-over-year, and just really I guess, wanted to get your thoughts on the '18 program and what type of growth we could potentially expect from you?

That's a good question. Danny, would you like to address that? And then maybe we can add a comment or two as well.

Sure. As far as the next year, we're looking at scheduling around 60 wells was kind of with that being the mix of 1-mile and 1.5-mile, leaning more towards the 1-mile. So that's kind of our plan for the year. As far as from what we can see about production, typically, we don't give a lot of guidance on production. So I may let Kelly and Tim, or one of the two address that question.

Yes. As it relates to Mike and others that are on the call, as you know, historically, we're very - we try to be as helpful as we can with the analysts in providing as much basics or fundamentals as we can but we do not put out formal guidance and that's not changed, we still don't. But as Danny pointed out, as we wrap up this year and we're somewhere in the neighborhood of 40 wells under our belt for the year, maybe as many as 41 or 42, and as we enter 2018 with the goal of reaching at least 60 plus or minus wells, you can see that, you're right, about the ramping up. We feel very strong and very comfortable that as we go through '18 and then on into '19, depending, of course, on our very good friend, the commodity price, we're prepared to even escalate further if it warrants that. So as far as production growth, I think, you're going to continue to see double-digit growth quarter-over-quarter for some time.

We can get in the model here and just extrapolate your type curve and really get, again, a pretty stout number. Is there anything though that you'd see potentially, Tim or any of the guys, is just a constraint to just - maybe just push back on us instead of just don't let the model completely rip here, is there anything else at play that maybe would have some sort of constraint in your eyes?

Look, I think, in all fairness, we've said this over and over again about the crystal ball that sits on all of our desk and the cracks that are there. We can't foresee, we can't look out and determine where the market's going to be in the commodity at the end of the year or this time next year. So there's always that and I'd like the question that was asked earlier from Neal Dingmann that Kelly actually responded to and we do have that flexibility. And the flexibly is to go to back to one rig, the flexibility is to easily go to three rigs, warranting the circumstances at that particular time. So constraints, Danny, I don't know, do you see anything that - I know, our infrastructure is a very important part, I know that's moving along very nicely. Is there anything, Danny, that you would see that might be some issues?

No, not at this time, Tim. As you mentioned, one thing especially in the North Gaines area that we're going to be working on very hard between now and year-end is developing the infrastructure up there. And we had the luxury in the Andres and the South Gaines, of having a fairly robust infrastructure already in place due to our vertical program. Up in the North Gaines area, we are going to have to come in and do a little bit of prep work, prior to getting an aggressive program started up there. I think you could see us do something up there towards the end of the fourth quarter or first of next year as far as starting the horizontal program, but we do have some prep work on the infrastructure to get done.

Mike, let me add a comment there, this is Kelly, and that is we are well in the process of that prep work, we don't expect that to be a problem Danny is being very conservative, but that's fine. And we're well down the road in that regard. So we're excited about what we think we could be able to get done.

And switching gears a little bit on the leasing front. It's not - it's almost hard to keep track of you guys, you've been adding so much here, it's been great. I think the last update we got from you guys was 34,000 acres added in April. It could - just what has been added since then? What's kind of the most incremental additions here that maybe we didn't know about? And maybe give us a sense of where the market's at? Is it still being able to get acreage at similar prices you had been, similar attractive prices over the last couple of quarters?

That's a good question. David, can you address that? And also David as you pointed out earlier, and I think now will be a good time, again, to point out and underline the importance of narrowing the gap between gross and net and how we've been focusing on that as well. But that's a good question, David.

You bet, absolutely. Mike, as we reported in just into the second quarter, we made that acquisition of a little over 33,000 net acres. We ended up the quarter with a little over a 40,000 acre add, net add. So we were able to add additional 7,000 in relationship to that first announcement that we made in the second quarter. We are continuing to see opportunities that come from a variety of different sources, obviously. But as I mentioned, we've always got acquisition and leasehold targets in our crosshairs, we never let off the pedal. And as a result, those come in at different times and in different quantities. Our leasing as far as pricing is concerned, I think that there's been a little bit more competitiveness out there. But we've been able to hold strong. We're one of the largest producers out there and one of the most active. And as a result, that puts us high on the list and when people start looking at who they want to swap acreage off to, so it gives us a real advantage. And as Tim mentioned, one of the things that we really focused on was increasing our net-to-gross on our leasehold. And the land department's done really well, that acquisition at the beginning of the quarter came with a really high net-to-gross and as a result - and really helped our numbers. But it's something that we're going to continue to look at and focusing on and continuing to increase. We're really optimistic about it.

Our next version comes from John White with Roth Capitals.

Everything is looking good and everything is sounding good on the call. I've got several questions but they're pretty brief. Consistent with your earlier remarks, I did notice your completed well costs for your both types of wells are staying pretty steady with previous guidance. Is that because you've got all the - you've got the rig and all the services under contract for the rest of the year?

Danny?

Yes, John, that in some cases that's correct. We again, we have gone out aggressively. When prices took a little dip, you know a couple of months ago or a month ago, we were able to go out and secure additional pipe at a very attractive price. We've also - that little dip also helped keep pressure on the drilling companies to not raise the rate. And in addition to that, we've - I will say we've had a slight increase in our frac cost but we've been able to offset that, as we've continued through the program, we've identified other areas where we've been able to find cost savings to offset that. So that so far has been what's been able to keep us with our drilling cost that we've been talking about. We - so I think, we've been able to save costs where things have gone up and we've been able to offset those but then we've also aggressively been going out and picking up equipment when it's available at very desirable prices.

Don't worry, I won't ask - I won't try to get guidance because Tim already said his crystal ball's got a crack in it. But would you - that's what he said. Would anybody want to say what July production was?

Danny, you can touch on that a bit with - to the extent that you can.

To the extent that I can. We were very happy with July's production, let me put it that way. I have - actually we haven't reported July yet and so I don't have a firm number for you.

Danny, when you're thinking about all the wells that we have to-date, what would you say our average is?

Our average...

Yes, as it relates to the horizontal wells.

Yes, we've had - we've averaged 658 BOE per day for the 14 wells to-date. But as far as July's production, no, I don't have a number for you. But it's in line with any projection you've probably worked out.

And Kelly, your prepared remarks on the completed well counts, those sounded like they're unchanged from the recent operations update.

That is correct. Well, with the exception of the...

Well, but I did add, right. And John I did add two more wells. We did have IP-ed 2 more wells since that time. So since two weeks or well, I guess a month ago, we've obviously…

Yes, you mentioned those.

Yes, and so - and then we've still got several testing and several in various stages of completion since then.

John, those two wells averaged about 690.

Yes, I do recall that, that was part of your remarks. And lastly on the GOR issue, which is not a concern of mine but just out of curiosity. I believe, your crude is a bit heavier than most of the Midland crude that Pioneer and some others produce. And being a little bit heavier, that would mean less of an increase in GOR over time, is that correct?

That's probably safe to say but the San Andres is just not a gassy formation overall. And as far as being heavier, it - from the properties of the oil standpoint you're correct, but as far as pricing that doesn't affect us at all. But in general, the San Andres is just not a very gassy formation.

Our next question comes from Richard Tullis with Capital One Securities.

Question for Kelly or Danny. With the addition of that second rig, how are you currently looking at potentially drilling any horizontals over on the Delaware side second half of this year or into 2018? I know you have a lot of horizontals planned for 2018. Any Delaware fitting into the schedule?

I can just tell you that the way - Richard, sorry about that. The way that we have thought of the Delaware is that it's 20,000 acres that we hold by production by drilling sort of 0.5 to one well a year. With the performance that we're seeing up on the platform and there's a little bit more of a drilling commitment up there, not one that's giving us any a heartburn at all but at the same time, with the performance that we're seeing up there, it make sense to apply the resources and things that we have currently in place to pursue that as much as possible. We don't want to take away from that today. Having said that, we have enormous amount of confidence in what's going on at the Delaware and what potential is there. I think that - and if we have continued to say that between now and the end of the year, don't be surprised if we don't go out there and do something. But at the same time, don't be surprised if we don't. It just largely depends on several factors and one of those would be the price of oil and whether it makes the most sense. But we'll get the bang for a buck up on the platform right now. And I think it's real smart to continue to take advantage of that as much as we can.

Question for David. Gave a good update on the acreage adds and the potential to add more. What do you think is a reasonable expectation? You've always had good insight into the acreage. Adds going forward, what do you think is reasonable to potentially add by year-end, David? And would you look to pick up anything over on the Delaware side as well?

Richard, we - I believe that we're going to continue to see some adds on the platform definitely. And because we're pretty optimistic about some opportunities that we're looking at today. Now whether or not - whether those materialize time will tell, but we're pretty encouraged on our ability to add to our current footprint there on the platform. On the Delaware side, always keep an eye open and - but not anticipating an add, it would be not just something came our way, obviously. But we're not, it's not as active in an area as the platform is and that's where our focus is primarily now.

Our next question comes from Jeff Grampp with Northland Capital Markets.

With the second rig coming on here in the next, I Imagine a few weeks or so, just kind of wondering as we think about well completions moving forward, when you guys think we might see some initial production contribution from that second rig? And then just generally, I know last week you guys talked about getting as many as 42 wells drilled by the end of the year here with two rigs. Do you have a general sense plus or minus, how many of those reach, I guess, the kind of a PDP status by year-end?

That's a good question, Jeff. And Danny and I, and Kelly and David were talking about that earlier. And so, Danny, why don't you go ahead and address that? Because I think it's important that our listeners know as even though we're moving the second rig here in just a number of days, that it certainly - you have to go through the process. And so maybe you could shed some real color on that, Danny.

Yes, you bet. No, with the rig coming on, we're looking at 10 days to 14 days to drill the wells and then it takes a while to get them completed and get them pumped down. So I don't think we're going to start seeing significant results, probably until Q4 on the second rig. And then by the year-end, out of 42, I think, we are anticipating we'll have about 38 of the 42 online by the end of the year.

And just I guess from a high-level strategically with the Devon acreage on the north here. I know you guys plan a couple of vertical well tests. Can you just maybe give us some high-level thoughts on kind of how you guys move forward there? I mean, will those effectively, I guess, kind of set up drilling some horizontals off of those or will it require a couple of more verticals before turning right here? Just generally, how you guys are thinking on moving forward on that asset here into '18?

When we look at that acreage up there, obviously as I mentioned earlier, we moved in on that acreage because it matched to the signature that we used in the southern portion of the area where we started our initial program. And of course, we feel very confident about it based on the data points, the information we've got. So moving forward, our goal is to get those few test wells down that we plan to drill and we've got the first two down. And as I mentioned, we're seeing what we want to see. We're excited about it, we like what we're seeing, it's exactly what we're hoping for. And we're going to continue to move in there and probably put down a couple of more test wells, don't know exactly when yet, but as long as we're doing that. And that is, by the way, the same formula that we followed on our initial concept in our initial well program when we started down in Andres County. So we're just following suit, it's the same plan, just being executed as we expand out our acreage. We still have a lot of drilling on the southern end that we're continuing to run the first rig on and we - again, that's just kind of our plan right now is to continue developing that out and along with - alongside going up north and developing some of that acreage based on the test wells.

Jeff, this is Tim. I'd like to just add to Kelly's point that don't misunderstand that the two test wells or science wells that we're developing right now, we're not going to have to wait on yet another one or two beyond that to start a development program in that immediate area of the test wells. So don't be surprised, if we're not active in that close proximity to those test wells - those first two test wells sooner than later, as it relates to the overall science wells that will be drilled possibly the rest of this year early part of next year.

Our next question comes from David Beard with Coker Palmer.

Just you're giving a lot of details, so I've got two bigger picture questions. You know the front, I think I know the answer but I'd like to hear your updated thoughts. I assume commodity is the biggest factor to adding a third rig or going down to 1. Kind of what levels and what duration at that level would cause you to think about adding a rig or dropping to 1?

Well, certainly between the $40 and $45, we've made it very clear through our recent conversations and updated releases that we bring to the bottom line a very nice internal rate of return and return on investment, even at the $40, $45 level, David. But as far as the possibility of yet accelerating again as we get into next year, I think we can comfortably say that you shouldn't anticipate a third rig this year. But as we get into the next year and things are moving on and we're still in this current environment of pricing or what we hope will be even better, it' something that we're going to consider as time goes on. As it relates to actually retracting or if you will, drop a rig. If we were to drop into the 30s, that would be a signal that we possibly could drop that second rig and then still maintain probably the first rig.

And on another front relative to capital allocation. Given your inventory position and the high IRR's in the well, would you skew towards either raising the bar on the hurdle rates on an acquisition in favor putting money in the ground? Or are you still comfortable with your existing parameters surrounding an acquisition? What do you think? I'm sorry.

Yes, we are. We love the parameters that we're working with on the leasing/acquisition side. But right now, there's no question the value that we're adding is through the organic, turning right, drilling - adding the second rig, et cetera, is going to create a lot of the value adds that we're going to experience as soon as the end of this year. So that's going to be nice. Now at the same time, there are a number of operators, as you know, on the platform from the private side and they're, of course, private equity-backed, that at some point in time are going to look to move their assets and we're postured and we're in a position, we believe, to take advantage of an opportunity, but at the same time, we've got plenty to say grace over. As David mentioned earlier, over 100,000 gross, somewhere in the neighborhood of 70,000 net and that differential between net and gross is narrowing. So we're going to have plenty to do but given the opportunity, we are postured to take advantage of that.

Our next question comes from Ben Wyatt with Stephens.

This is John Durham, I'm on for Ben Wyatt. But I wanted to ask a quick question on LOE. So LOE for the first half of the year has ranged from about $10.08 to $10.40 per BOE. Just curious, if you guys could maybe break down your LOE on a variable versus fixed cost basis? Just trying to get a better sense of when we could start to see a step change in LOE on a per unit basis?

Okay. Danny, maybe you can address that please.

When we run our models out, John, we obviously, the biggest variable cost we have is - well, there's two things; There's chemical and then our water disposal costs. Those, obviously, really depend on the amount of water we pump as opposed to the amount of oil that we make, electricity falls into that same category. I don't really - I don't have a break out for you. I don't mind looking at that and finding that out for you, as a percentage. But we are very aggressively going out and working to lower our number one cost, which is water disposal. When we started this program out, we had $0.25 a barrel cost that we were paying the land owners and then we have about another $0.08 to $0.10 per barrel on top of that for operational expenses. We've since been able to negotiate most of those contracts down, we have contracts now as low as $0.03 per barrel and on top of that, we've gone out and bought some of our own land in the general area, and we plan on in the future drilling some wells there which will lower that cost of land owner to 0, in some cases, not overall. So that's kind of where we are at on that but I'll tell you what I can do, John, I can look at that as percentages of fixed versus variable. I know my reservoir engineer has that, I just - I don't have it at my fingertips.

Our next questioner is Mike Breard with Hodges Capital.

Yes, I'd like the good results you all are having. You had spoken earlier about drilling on a dayrate basis, instead of footage. How is that working out for you? Are you able to drill any faster?

Yes, as far as that goes, well, actually when you get into the horizontal part of this business, it's very hard to find somebody doing footage. We did start out doing footage, you're right. The first - I'd say the first half, that half dozen wells. After that our rig companies told us that they would no longer be doing footage rates, so we have gone to day work. And we have had substantial savings, that's when we were talking about why we've been able to keep our cost in line, that's obviously one of those things that we've been able to do. Probably, it was a 20% to 30% savings when we went to dayrate.

Have you thought anymore about possibly drilling some horizontal wells in both layers of the Delaware basin, the Cherry and the Brushy?

Yes, we cored several wells out there over the time period that we just bought the property. And our original concept was to drill down the Cherry and then we had some opportunity to drill down the Brushy vertically, and there's some much needed testing and completion work in that. But we went ahead and cored those wells. You can't take over the property, you know there's a transitional period that you go through, whatever you're trying to figure out, what the previous operator did and what does it actually mean. And we went through that same time period and we saw opportunities to increase production by adding perforations, by adding additional pay, by getting chemical programs in place and things of that nature. All those data points, if you will, help you understand the formation. We were able to defy that the Cherry Canyon is broken up into a sizable interval with a lot of opportunities for pay. And some of those pay zones have not been exploited properly in our opinion and/or completely for that matter. And then as we drilled the Brushy Canyon, we discovered the same thing. The core samples came back to us and gave us a lot more confidence and then, of course, we had those samples tested for a number of things, that you would test in order to drill horizontal wells to figure out where you want to put down your horizontal leg, if you will, where you want your landing zone. And in doing so, we got a lot more confident in the Cherry Canyon, as well as the Brushy. And the bottom line is, is that we think we had two opportunities there. Remains to be seen, once we drill it, but we are very high on both those concepts out there and at the proper time, as we continue to say and we will continue to say for now, that we may move in there and take advantage of one of those.

You've been known in the past, that once you figure out how to drill these wells that you accelerate - is it too far-fetched to think if the oil price would've, say, hold around $50, you could add three or 4, even five rigs working by the end of next year?

Mike, this is Tim. I think it's reasonable to think that if we see $50, and we see stabilization. So the confidence is built at that level, it's likely that sometime through mid- to latter part of next year if we're at that point that a third rig would be probably very practical.

Then the fourth would be soon thereafter?

Not necessarily soon thereafter, but we're not opposed. I mean - listen, we have the capabilities of running multiple rigs, no doubt about that. So we have the infrastructure in place, we have the people in place, we're ready to do that, but the real key is, of course, is that commodity. So it will - it dictated a lot by that, but with the acreage, with the footprint that we have and the capabilities that we have, it won't take long to just spring into action if we need to add more along the way. But don't want to get too far ahead of ourselves, we're excited about adding that second rig for now, that's going to do a great job of - really an impactful job over the remainder of this year, as we wrap up this year and particularly, as we go into next year. So bringing a third or fourth rig in, just really remains to be seen where that commodity really ends up at that particular time.

There are no further questioners at this time. I'd like to turn the floor back over to Tim Rochford for closing comments.

Okay. Well, listen operator, we appreciate that and we appreciate all the very good questions. And so we know that everybody has a busy schedule, there are a lot of calls going on and once again, we just thank you for taking the time and particularly, the support that we have from you folks is really appreciated. And our lines are always open, so we look forward to hearing from you along the way. With that, so long and thank you.

Thank you. Ladies and gentlemen, this concludes today's conference. You may disconnect your lines at this time. Thank you all for your participation.