Ring Energy, Inc. (REI) Q4 2016 Earnings Report, Transcript and Summary

Greetings and welcome to the Ring Energy Incorporated 2016 Fourth Quarter and 12 Months Financial and Operating Results Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to your host Mr. Tim Rochford. Thank you, Mr. Rochford, You may begin.

Thank you, operator, and welcome all listeners to our fourth quarter and 12 months 2016 financial and operations conference call. Again, my name is Tim Rochford, I am Chairman of the Board. Also joining me on the call this morning is our CEO, Kelly Hoffman; our President, David Fowler; our Chief Financial Officer, Randy Broaddrick; and Executive VP and In-charge Charge of Operations, Danny Wilson. So today, we' will cover the financials and operations for the fourth quarter and 12 months ended December 31, 2016. We will review our results and provide some insights as it relates to current progress thus far in the first quarter of 2017. At the conclusion of our 2016 review, we will open up the call to any questions that you may have, and we know that you are going to be anxious to hit to that point, so we'll move right along. I am going to ask Randy Broaddrick, our CFO to review the financials. And we get started.

Thank you, Tim. 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 release issued Wednesday, March 15th. 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 December 31, 2016, the Company had oil and gas revenue of $9.8 million and a net loss of $477,000, as compared to revenues of $7.4 million and a net loss of $7.5 million in the fourth quarter of 2015. For the year ended December 31, 2016, the Company had revenue of 30.9 million and a net loss of 37.6, as compared to revenues of 31 million and a net loss of 9.1 million for the same period in 2015. For the three months period, the reduction in loss was primarily the result of not having a write-down of our assets based on the ceiling test calculation in the fourth quarter of 2016, while having a pretax of 9.3 million in the fourth quarter of 2015. Unfortunately, the fourth quarter of 2016 did absorb a true up of our tax provision for the year, without which we would have shown a gain of 884,000 or $0.02 per share. For the year ended December 31st, the dramatic change in our loss was primarily the result of ceiling test write-down of $56.5 million for 2016 versus $9.3 million in 2015. At current commodity prices, we do not anticipate any additional ceiling test write-down; however, if prices were to decline again additional write-downs are possible. For the three months ended December 31, 2016, our oil price received was $45.99 per barrel, an increase of 20% from 2015. And our gas price was $2.76 per MCF, a 27% increase from 2015. On a per BOE basis, the fourth quarter of 2015 price received was $41.59, an increase of 20% from the 2015 price. For the year-ended December 31, 2016, our oil price received was $39.28 per barrel, a decrease of 13% from 2015, and our gas price received was $2.50 per MCF, a 1% increase from 2015. On a per BOE basis, the price received during the year-ended December 31, 2016 was $35.13, a decrease of 16% from the 2015 price. Production costs per BOE for the three months ended December 31, 2016 decreased to $12.05, as compared to $13.95 in 2015. For the year-ended December 31, 2016 production costs decreased to $11.24 per BOE, as compared to $13.40 for the same period in 2015. Going forward, we anticipate our production cost per BOE to be around the $12 range plus or minus. Most production taxes are based on values of oil and gas sold. So, our production tax expense is 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 depreciation, depletion and amortization or DD&A including accretion of our asset retirement obligation per BOE decreased for the three months ended December 31, 2016 to $12.98 per BOE as compared to $17.94 per BOE for the same period in 2015. For the year-ended December 31, 2016, the rate decreased from $20.98 per BOE to $13.63 per BOE for 2015. Depletion calculated on our oil and gas properties subject to amortization constitutes the bulk of these amounts. The primary cause behind these decreases was the ceiling test write-down, which reduced the cash flow that we have to deplete overtime. As to total amount the three months period ended December 31, 2016, DD&A decreased approximately 20% from the comparable period in 20145. For the year-ended December 31, 2016 the total DD&A increased approximately 23%. Our overall general and administrative expense decreased $216,000 for the three months ended December 31, 2016, and remained relatively even with an increase of only $32,000 for the year-end December 31, 2016, as compared to the same period in 205. On a per BOE basis, this equates to a drop of up from $10.44 in 2015 to $8.48 in 2016 for the three months period and from $10.76 from 2015 to $9.14 from 2016 for the annual period. These decreases in per BOE rates about the three months and annual period are primarily result of increased production volumes. On a diluted basis, the loss per share for the three months ended December 31, 2016, was $0.01 excluding a $619,000 of non-cash charge for share-based compensation. This loss is reduced by approximately $0.01 per share for a very small loss that per share is zero, as compared to loss per share of $0.25, as reported or $0.04 per share excluding both a ceiling test write-down of $9.3 million and a $605,000 non-cash charge for share-based compensation in 2015. For the year-ended December 31, 2016, loss per share was $0.97 as reported. This loss is reduced by approximately $0.95 per share excluding the $56.5 million ceiling test write-down, and an additional $0.04 per share excluding a $2.3 million of non-cash charge for share-based compensation. For a gain per share of $0.02 excluding both the items, this compares to a loss per share of $0.32 as reported, or a $0.05 loss per share excluding both a $9.3 million ceiling test write-down, and a $2.6 million non-cash charge for share-based compensation in 2015. As of December 31, 2016, we had no amounts drawn on the $60 million borrowing base on our credit facility and had cash on hand of $71.1 million. We have planned an active capital expenditures budget for 2017. Based on the current economic conditions and our projected capital expenditures, we do not anticipate drawn on our credit facility during 2017, outside of any acquisition opportunities that may arise. For the three months ended December 31, 2016, we had positive cash flow of approximately $5 million or $0.12 per diluted share compared to approximately $2.1 million or $0.07 per share for the same period in 2015. For the year-ended December 31, 2016, we had positive cash flow of approximately 13.1 million or $0.34 per share compared to 13.4 million or $0.49 per diluted share for the same period in 2015. With that, I will turn it back to Tim.

All right, Randy. Thank you for overall review, we appreciate that. I'm going to ask now our CEO, Kelly Hoffman to take over and give us an overview on the operations for last year.

Thank you, Tim. Now, I want to thank everyone for joining us on the call today. During the fourth quarter, we completed three horizontal wells and one saltwater disposal well, and all three horizontal and saltwater disposals were drilled in the third quarter and completed in the fourth quarter. Additionally, we drilled and completed two new Cherry Canyon wells on our Delaware Basin property and we completed five existing vertical Cherry Canyon wells on the same properties. We also continue to upgrading on our gas gathering systems and the infrastructure both in the Central Basin platform and the Delaware. And for the year ending December 31, 2016, we drilled three new verticals San Andres wells, drilled three new horizontal San Andres wells and refrac two existing verticals San Andres wells and drilled one new saltwater disposal well on the Central Basin Platform properties. Also we drilled five vertical Cherry Canyon wells and we completed five existing Cherry Canyon wells on the Delaware Basin Properties and two of the Cherry Canyon wells that we drilled were drilled to the base sort of Brushy Canyon and all that provide some very valuable data and core samples as we continue to map out and develop a potential a horizontal drilling program for the second half of 2017. Net production for the fourth quarter of 2016 was approximately 240,000 BOEs, barrel of oil equivalents, as compared to net production of 218,000 barrel of oil equivalents for the same period in 2015, at an increase of 10% with the net production in the third quarter of 209,000 barrels of oil equivalent for that same time period, in the fourth quarter was a 15% increased or the fourth quarter over the third. December 2016 average daily production was approximately 2,725 barrels of oil equivalents compared to net daily average of 2,335 barrels of oil equivalent for December 2015, and the average price per barrel of oil equivalent in the fourth quarter of 2016 was $41.59. For the 12-months ending December 2016, net production was approximately 865,500 barrels oil equivalent, as compared to 742,070 barrels for the 12-months ending 2015 at an increase of 16% year-over-year. Our average net daily production increased to approximately $2,400 barrels of oil per day and the average sales price was $35.13 as compared to the 2015 numbers with $41.72 average and that's a 16% decrease in price. Lastly, we completed two public stock offerings, one in April and one in December. We announced our 2017 CapEx budget for 70 million, which includes among other things drilling 22 horizontal wells on the Central Basin Platform, and you are going to hear a bit more about that here in a moment from Danny. At this time, I'm going to introduce you to Danny Wilson, who is our Executive Vice President and Head of Operations for an update on operations. Danny?

Thank you, Kelly. Just want to recap just a little bit on the three wells that we did bring online in the fourth quarter. As you remember, we’ve had a couple of phone calls about this but our Augustus #1H and the Tiberius #1H were the first two wells we brought online in early October. It took about 45 days for those wells to reach their initial potential the 24-hour test. The Augustus came in at 602 BOE per day. The Tiberius came in at 448 BOE per day. The third well our Caesar #1H came on couple of weeks after the first two and it reached its IP early December and that well IP that roughly 506 BOE per day. I know in the past we’ve talk a little bit about, I know I talked about IP is just a one-day total. We’ve also gone back and look at the 30 day IPs. We’ve told everybody in the past that we believe those are should be or somewhere around 300 BOE per day on a 30-day rolling average to match the existing wells in the area and the type curve and just update everybody on the Augustus, our 30-day IP number was 499 BOE per day, the Caesar was 305 and the Tiberius was 375 on those. You see there is quite a bit of variation in that. When we go back and look at wells compared to type curves that we have projected out. One of the wells is significantly going to outperform the type curve. It looks like best price in the gas as well. The other two are going to be -- one is going to be right on the type curve, one is going to be slightly under so far, I will say this. They all have very different decline curves, and so we’re not exactly -- sure exactly what the EURs going to be, but we’re very happy with the results. And on average, we feel like we're more than meeting the type curves that we provided to everybody and talked about. As far as moving forward, we have talked about in the past that we were going to have 22 well programs starting this year. We did begin that program in mid-January. We started bringing wells online late-February, and we're starting to see the results of those. We will be talking more about those when we do our operational update in early April. We’re also in the process of the drilling the two wells we’ve outlined that we will drill eight for vertical wells in the Delaware Basin. We’re in the process of drilling the first two of those. And again, we’ll be giving updates on that in our April call. As far as our infrastructure goes, we’ve been very active on that front. In the fourth quarter last year, we present our oil pipeline that we build out. We've built our own pipeline non-gathering system for our horizontal program. We deposit that oil directly into Centurion pipeline and that is all going very well. We are in the process now extending that system to collect the oil from the new wells that we’ve been drilling. We’ve substantially increased our footprint from the first three wells as you remember those were all in fairly close proximity to each other. We stepped out several miles to the East, and we have also stepped off a good number miles to the South and Southwest. So, we are in the process of extending our oil system to account for those new wells; and in addition, we have fairly significant amount of activity that will be going onto the North of the existing wells in the near future, and we’ll building that part of the system now also. We’re doing the same thing with the water and the gas system. In particular on the water, we've added several more disposals this quarter and are bringing those online to meet the demand of these new wells that we’re bringing on. We are also then very actively renegotiating our rate with the existing owners now with our disposal. We have a land of our disposal wells, yet each of those land owners of certain royalty rates due to disposal to that water. We have gone back and with some of our existing owners and we’ve renegotiated the suspension of savings on our -- on that on those wells; and in the future, we’ve also been talking new land owners and have been negotiating some very, very low rate on those which should help us substantially on our LOE as we move forward. As I mentioned, we are taking the first steps into our program for this year. Everything is going well. We have no real issues today, and we are planning to discontinue the process on through. And with, I'll turn it back to Kelly.

Thank you, Danny. I'm going to pass it on here to -- to introduce now that David Fowler, our Vice President of the Company.

Thanks, Danny, good job, you as well Kel. Good overview guys. David, if you would be kind enough to give us kind of the glimpse as to how things are looking particularly on the platform and of course Delaware as well.

We’ll do it. Thank you, Tim. You know, Dan, we’re back and reflect on 2016. It was a really a year of contrast as we began the year with oil prices that slipped down to the mid 20s, which was lower as we have seen since 2002. Fortunately, prices slowly improved throughout the year ending in the low 50s to all of our release that is prices recovered. M&A activity is skyrocketed as we read about it, a $1 billion deal about every other day some of which we can reflect to remember what happened about just days apart. Our leasing activity in Q1 and Q2 came particularly to a standstill and commodity prices fell and we closely monitored our outspent. The last half of the year ago though was a complete turnaround. Our land department keeps in the high geared and was able to move -- was able to more than double our platform acreage footprint from approximately 25,000 growth acres as of Q4, 2015 to 53,582 growth acres, and our net acres position increased 2.5 times from approximately 13,000 net acres to 32,633 net. More significantly, the vast majority acreage we had on our platform was in our perspective horizontal San Andres target area. In Q4 alone, we added over 14,600 gross acres 9,700 net to our existing horizontal footprint. To put this in perspective of the 53,582 gross acres we have in the platform, approximately 43,854 acres or about 80% is perspective for horizontal San Andres. On a net basis, we started 2016 with approximately 8,000 net acres. By the end of Q3, we doubled that 16,000, and in Q4 we grew our net horizontal acreage to 26,222 acres, which was more than tripled from what we started out at the beginning of the year. Based on six horizontal San Andres wells per section, we get the potential of 413 gross horizontal rotation, 227 net. This gives us numerous years of horizontal drilling locations. If we can add another acre, obviously that’s not our intent as we're pleasantly pursuing leasehold in our target areas on a platform. On our Delaware Basin asset of approximately 20,000 gross net acres were equally focused and optimistic about our ability to increase our Delaware leasehold position in 2017 as well. In summary, we will continue to expand our position on the platform and in the Delaware Basin by continuing our aggressive lease acquisition program. We continue to monitor review all M&A activity and opportunity, but keep our eyes on the pulse of the horizontal San Andres development North of its on the shale, South platform and also in Southeastern Mexico, due to our strong financial position that we mentioned early were ready drilling and able to react quickly and aggressively to acquisition opportunity in our target area. And with that, I’ll turn it back to Tim for closing remarks.

Okay, David. Well, we've all just heard some really good and exciting stuff going on. Certainly, we are well postured. We are sitting on a great horizontal footprint that continues to grow. We've got a great balance sheet, strong cash position. We have a credit facilities and our credit facility is in the same place and undrawn. So, lots of things, a lots of things ahead of us. And I know, we are all anxious to turn this over to the operator. So, operator, let me give it back to you. We are going to open it up for any questions that any of our listeners may have, please.

Thank you. At this time, we will be conducting a question-and-answer session. [Operator Instruction] Our first question comes from the line of Jeff Grampp of Northland Capital Markets. Please proceed with your question.

I guess first I wanted to I guess get whatever details I can squeeze out of you with the early results you've seen on the horizontal wells for 2017. It sounds like you guys are pretty encouraged with what you've seen albeit still early days, but can you guys maybe just talk generally about what you've seen and flow that so far? I mean, are these kind of flowing back similar to the first three wells or any kind of comparing contrast commentary you guys can provide I guess will be helpful?

You bet, Jeff. Listen, we are going to let Danny respond to that, but please note this Jeff and all listeners that within a few weeks, literally within about three weeks, we are going to be able report in totality the complete operational update for the first quarter which will give a lot of detail, a lot of information that we are not able to talk about this morning for obvious reasons. But I think as mentioned in the press release and mentioned earlier in the call today that we are feeling very good and very strong about what we are seeing thus far. But Danny, you'll shed a little light on that. I know that Jeff and other would like to hear that.

Yes, a little color on that. We are very pleased with the early results we are seeing. There are still in the build up phase or what I think is the pump down phase where we're seeing the water volumes come down, the oil volumes increase. But we are very happy with the results that we are seeing today.

Okay, perfect. And just I guess trying to get a better handle on how we should think about production trajectory throughout the year and it kind of sounds like, I guess for first quarter just based on how this new horizontals flow back, shouldn’t really expect things to meaningfully change relative to kind of I guess where you guys exited 2016. But I guess just trying to get better handle on, on how we should expect the production trajectory, if you guys can give maybe any color on completion cadence throughout the year or anything there that would be helpful?

Yes, that’s a good question. Danny, go ahead and fill up that, if you will please

We, right now Jeff, as far as the completion rate goes, it looks like, we’re probably going to be bringing on two to four wells per month and those are going to-- as you count on about a three well average across the board, that’s about the same rate we're drilling. The math is taking about that 12 days per well into 12 days per well, so we’re getting about three a month in so far. And the frac rates -- the frac dates are, they’re not -- I wish they were smooth as the drilling. We kind of get rigs of two and three at a time. So, you may see a little gap and then I’ll said, we’ll do two or three and bring those on and then there might be a one and then four. So, it just kind of depends on the dates that we can schedule. We have some pretty advantageous frac rates from the vendor that we’re using and so we’re trying to work with them on the schedule that sometime just a matter, because when they get to it. So, but again count on about three per month.

Okay. Perfect, that’s very helpful. And last one for me just kind of clarification, very helpful on those 30-day rates on the wells and just wanted to clarify that. Are those all on an eight date basis or those NRI barrels and then comparing that to that 300 target, I just want to make sure, I’m understanding on apples-to-apples basis?

Yes. Those are gross numbers. So and I believe the 300 was a net number that we gave you. So, we are looking at about 400 BOE per day on a growth.

Our next question comes from the line of Neal Dingmann of SunTrust. Please proceed with your question.

Hi, guys, quick, first question. All right, Dan, I was curious, you’ve mentioned some of the wells are come on. It looks like the slope is a little bit different. I’m just kind of curious, what do you think that is, I mean, how much variability is there and yet, are you still kind of thinking that at least the EUR [indiscernible] kind of flat now that call it over a year or two years and beyond now kind of be similar in that regards?

I think so Neal. There is going to be some variation in those, of course, so we’re going to have some that do better and some that don’t do as well. There is some difference in the reservoir rock in some of the areas. Some of them have more, the outside of first three or more, what we could call, I guess transition or ROZ these zones or the names were here kicked around where those have to be deepwater before they actually come online and actually peak. We’ve got other areas in some of these that we’ve drilled recently are unconventional reservoir. We’re seen those come on a lot quicker. And so, it’s going to be a mix and it’s just going to kind of depend on the area that we’re in at the time. So, I know that really answered your question, a lot of variability in these, some come on quick, some have to do water for 45-day, some 30, some 60, but I think once we get farther into the program these even out as we get more and more wells online.

Neal, this is Kelly. I can add to that the numbers that we gave early on in the curves that were built off of the wells that were studied to around this had very results too, and we took those averages and used some and that's how we can up with our EUR which we still believe is very much intact, right.

And then secondly, you mentioned this Tim for you or Kelly in the press release talking about, not, likely not doing Delaware this year, but certainly, I think it sounds you’re getting to more and more encouraged. If you look at that plan on a go forward, I don't say either '18 or '19. Is it well come down just pure economic decision or what would cause you to -- I'm not asking for a gain or what the plan might be, but again, if you've got two quality basins like that between the Platform and the Delaware. How you decide kind of allocate between the two?

Neal, you're right, we do have two quality assets and we had a conversation with some of the other day, and they tell us a more about Delaware. In the absence really, if we didn’t have the program that we’ve initiated here with the part of program then on to the development program we announced earlier in the year, we didn’t have that going in the Platform would be all over the Delaware. I mean there is no question, economics there, make a whole lot of sense, it’s a matter of where those dollars are deployed. I can share with you and as Danny pointed out and as we released information earlier in the year, we’re going to drill at least eight vertical wells there. And even though we have formally put this on our CapEx or added to our CapEx in all likelihood based on the results that we’re seeing on the platform thus far the encouraging results that we’re seeing and based on what we’ve seen from the wells that we’ve drill through the Brushy at the Delaware. At midyear, we’ll probably revise that CapEx to do a couple of things. One would be to mostly likely include or excuse me add to the 22 that initially announced of the horizontal side, and then also to include a Brushy Cannon on the horizontal and the Delaware side. So, it’s a great question, I wish we could give a definitive response in that. But I think as we get into this further into this year and particularly as we throw or layout that the first test in the Brushy we’ll see how things go.

Our next question comes from the Sam Burwell of Canaccord Genuity. Please proceed with your question.

Thanks, guys. I wanted to start off on the well cost assumption because lot of your bigger peers have talked a lot about the impact of service cost inflation. What their expectations are through the year? Are you guys still confident that you can drill the horizontal wells for the same amount that you’ve guided to previously?

Kel?

Yes. We are -- we have had a lot of discussion internally and then we've been talking to lot of guys out in the field of course. And then at year end, we make some very strategic first test with the equipment where we loaded up on some casing both surface and launching casing that we knew we would be utilizing the first six months. And we secured those pricing at the lower market levels that’s going to something that’s going to help pull our cost down. There is no question, Sam, and I think we’ve had this discussion and we expect to see like everyone else is seeing some increases this year. I think for the most part there is going to be significant cost in 2017, might be more of a 10% plus in 2018, this year we’ll see some services go up to 10% plus. But I think that we have some other mechanism that can mitigate for the most part and we expect to that. So, I think overall we’ll stay in budget without question.

Got it. Good stuff. And then next question would be on LOE, I mean it seems like you guys have kind of kept it low teens just about 10, uptake a little bit in Q4. But now that you’ve got the growth come in the lines, do you expect LOE to go down meaningfully since you're spreading out at least fix cost portion over a lot more barrels especially in the second half of the year?

Danny?

Yes. Sam, that you're right about Q4, and we were looking at those numbers, and the reason the LOE kind of popped up there was of course, it takes about 45 days to pump these wells down to a point to you got chemical water disposals and obviously the barrels, the oil is not kicking albeit yet. So, that's a reason why the number is down, a little bit worse in the fourth quarter. I do think overtime that we will be able to keep that LOE in the low-teens and probably working downwards, especially like to say, we've gone out and renegotiated somewhere saltwater disposal rate, which is our number one cost out there, and I think we will start to see in those savings kick-in if not this quarter in next quarter. So, it is that $12 number and probably maybe hidden down a little bit from that will be a good estimate for you all.

Our next question comes from the line of Richard Tullis of Capital One Securities. Please proceed with your question.

Maybe this is question for David to start with on the Delaware Basin side where you've expressed some optimism that you would be able to add some acreage there in 2017 in addition to the on the Central Basin side. David, do you envision being able to acquire some deeper rights either on your existing acreage or new acreage where you can potentially drill below the Brushy Canyon?

Richard, no. Probably, we're going to stay focused on the Delaware Mountain Group that's from the surface down to approximately 6,000 feet. Most of the deeper rights around us have already been leased out are already owned it's by Shell, ConocoPhillips, Chevron, Citation is out there. BHP is out there a big way as well, Anadarko. So, for that -- for most part, no, we will be staying focused on the shallower rights.

Okay, that's helpful, David. And I'm sorry if I missed this, have you started or Kelly have you started drilling the sixth vertical Central Basin Platform wells yet?

It's actually Danny. I was going to say. I'll tell you what we've done Richard as we have gone back in those wells, those were all going to be commitment wells that we were anticipating that we have to drill the wholesome leases. For the most part, we have been able to go back and incorporate those into our horizontal program to mitigate the number of vertical wells that we would have to drill. I'm not saying we are not going to have to do staple, but the sixth is probably more like two now. And so, I think we did everything we could to get right return on the horizontals to see if we could work those into the horizontal program.

Okay, that's helpful. And just lastly, Danny, are you able to talk a little bit more about the extended production for those first three horizontal wells I know you gave that 30-day rate. Do you have enough data at this point to talk about further decline of the 30-day rates for any of those wells?

Well, obviously yes they have declined a little bit from there. I think everybody has been able to see January production, which has been posted. I can't really thought beyond that right now. But I will say, the January numbers were somewhat affected by -- we had some pretty severe weather in there that we had freezing temperatures for three days in a row without getting above freezing and that costs us a little bit. We also had some issues with on core out there on the electrical side that maybe had caused us three days. All I'm saying is January number are not bad but they are probably a little not indicative of what was thing moving forward. I would say for the most part Richard when we look across the Board the wells are still following the type curve. So, we’re pretty pleased with how they are reacting.

Our next question comes from the line of Norman Hale of Stifel. Please proceed with your question.

The three horizontal wells you guys have mentioned here. Are you able to project the anticipated payback period for those three wells?

That’s a good question. Danny?

Right now, they look like they're probably going to be in the probably one year range somewhere in that and maybe and some of the goodwill I think the part will be little less than that. Some of the already in the year to year and a half range would be the probably longer end.

What price you continue to?

Well, I am thinking that's acted about a $45 realized price.

Okay. That’s a very attractive payback period. That’s great. Next question, as far as acquiring additional properties, is it getting as far as the prices or the terms that you guys are negotiating is getting a little more difficult that the prices are starting to creep up a bit due to the fact that these areas seem to be pretty less as far as the hydrocarbon?

Good question. Kelly, you can process that one.

Yes, I mean what we’re looking at right now is a lot of competition, no doubt about it. Private equity got in here first after us. We already have and establish footprint that was substantial, but they didn’t get here in a big way. I think you're going to see that competition well as much as it can over the next 12 month to 24 month and did expand it can, a lot of pieces is being picked up right now it’s a pretty healthy prices, but we were fortunate enough to get a very large footprint where we want it to be with what we saw like was a best quality lock and best area that the horizontal wells down. But I can tell you this the competition is stiff, we abstract obviously all the people and it's going to continue to be -- people are really starting to discover this in San Andres as a real formation, it’s a real formation of horizontal development and it really make a lot of money and the cost to well and then you’ve got really, really larger wide margin that you can take advantage off. And so, there is a lot of scramming going around. Do I think that we can expand our footprint? We really can, we still have some tricks in the bag left up to us. And I think, we’ll continue to take advantage of those where we can, but there is stiff competition.

As we expected I think wherever you get it the good property, it's going take a honeybees finding honey. There is going to be a lot of them hanging around. As far as your drilling program going forward to, if things go well, do you guys anticipate that you could potentially be leasing some additional rigs?

Well, that’s a very good question. Let me take that, this is Tim. There is no question, I think David touched on this quite nicely earlier in his comments that we have an inventory now. I mean in place that would yield something north or around numbers 240 horizontal wells with a mile lateral. So, if you just want to work from that base, I can share with you those were based on year-end numbers. And we’ve been very active since then we’ll again address that as we come out with that operational report within a few weeks. But, just looking at footprint alone, you can see you can add another -- I guess, Danny was saying we really feel that we cannot have about three wells per month. So, if that's the case and that's on the 36, well run, if you added a second rig maybe not get up to 72, you could stay busy for three plus years, if we accelerate one or two another rig. I think real question is, we certainly have the infrastructure that needs and to improve from we're accepted there to go forward to handle that and then that's a different levels whether it's from staffing, from actual infrastructure in the field et cetera. But that's something that we've already talked about but you won't see it happen in the early part of this year or even mid part of this year but as we finish up this year we will be looking and we will be thinking and considering the next step and that next step would and that will be probably see an acceleration at some point given a commodity space.

Our next question comes from the line of Orby Morris, a Private Investor. Please proceed with your question.

I was surprised by one of your earlier comments and that cause me to rethink my question. Are you approaching San Andres in residual oil zone as a separate entities formations?

Danny, why don’t you just a give little color on that? That is a good question and is asked often, so that's a good one.

I know, there is a lot of questions about that. To answer your question is, they are the one in the same the San Andres, the residual oil zone are the same. They are all in the San Andres. You do have various where you have conventional rock, which is the areas where you typically see the normal production for vertical wells and that's just it got the normal processes, it got free oil that will come out immediately out of the well. They are lead zones is a little bit deeper typically and it's an areas where the -- I don’t get into a big long geology lesson here, but the oil is in placed long ago before the water slip through that area. It came slipping through and swapped out somebody's oil, but what's left is what's considered ROZ, the residual oil zone. And to recover that oil, you have to lower the reservoir pressure to a point where the gas comes out of formation, out of the oil and it pushes the oil out. And so that's why some of those take a little longer, and we had a mix of that acreage. We have conventional rock that we have a fair amount of inventory in and then we have the ROZ zone. So, that's -- when people keep asking about what are type curves in this. Well, there is still little bit different based on where we're add out there. And let's not to say that we don’t have ROZ oil below some of the conventional rock, there may be a time at some point where there maybe multiple horizontals like down one recovered the conventional oil and another for the ROZ in the right areas.

So, like a fantastic opportunity. And one last question, I believe I noticed that in Gaines County, one of your vertical wells is going deeper maybe down into the Clearfork. And so because you provide some color as to your interest in deeper formations.

Yes, that one and in particular the ones you are talking about are actually saltwater disposal wells and we're going down to that and for disposal. We're using it for science purposes. We're stopping the logging and coring the San Andres as we go through, but then we're taking to mount down to the Clearfork for disposal.

Our next question comes from the line of Jason Wangler of Wunderlich Securities. Please proceed with your questions.

I was just curious as you look at the 22-well program this year. Could you maybe just give us an idea of kind of geographically, what you’re kind of focused on and also if you’re seeing any third-party activity around those similar areas to help define the acreage better on the horizontal side?

Yes. That’s a great question, Jason. Go ahead, Danny.

Jason, we are expanding the footprint like as mentioned the past couple of wells. The first three, the pilot program were within very close proximity. Now, we are continuing to drill in that area, but that in the meantime, we’re also stepping out, we’ve going to couple of miles, like I mentioned before maybe to the Southwest. We’ve actually going about five miles to the Southwest on a couple of wells. So, you’re going to see footprint expanding, we have future plans to move north. If you look at our presentation, you kind of see what footprint is out there. We’re going to kind of working along the edge as Robertson Riley field, moving north. And then that’s kind of the plan for now. So, you will expand quite a bit during the year.

Our next question comes from the line of John Aschenbeck of Seaport Global. Please go ahead with your questions.

A lot of my questions have been addressed already, but did have a couple of questions regarding the April ops update. First, wondering, how many new wells we should expect results from? And then I apologies if I miss this, but was also wondering, if what the April ops update you were potentially planning to address any potential acceleration plans there? Thanks.

Good question. Danny, go ahead and take that if you would. I’m sorry. I didn’t get the full name, if you would please repeat that.

Yes, John Aschenbeck with Seaport.

Yes. Okay John. Thank you.

John, we definitely -- okay, April production that day, we will, you probably, I’d say, well I’ll let you kind of the work from that. We actually saw bring wells online in February, we’ve been bringing on about more in every other week or so. So I think you probably looking, we’ll probably be able to some color on about three to four more wells and we’ll give you update on the drilling at that time also.

John, this is Kelly. We will have more drill, we just won’t have results that we can share at that point is depending on whether on their lifecycle. But we are available to pretty openly and give a little bit of color on at least three of them. I am thinking and then we may have as many as six drills.

Yes, if you look in this way, John. We started -- we've moved that rig in on the first of those 22 wells early in January. And as, Danny said, kind of figure three, sometimes just going to maybe not quite make it there. But yes, if you had an ideal quarter, if you were right at the beginning of the quarter. If you potentially you can do the math, but have nine. But we’re certainly going to be in that seven, eight, nine range drill as far as completion as Kelly and Danny pointed out. I don’t think that way, but think about maybe a third, three or four those that may have completion results or we’ll have completion results by then.

Got it. Understood. And then my follow-up question here is on M&A. You've made quite a better progress so far. David, you touched on this in your prepared remarks a little bit. So, I was just curious again I apologize, if I miss this, but I was curious with remaining opportunity set looks like you essentially tripled your horizontal footprint now for 26,000 net acres? I'm not sure if there is the potential to double that again, but we should wondering what you think your ultimate acreage footprint could look like on platform?

You know what John, we have tripled it and there is still lots of opportunity out there that we look and we evaluate and we see every day. But David, if you can shed a little or add a little color on that go ahead.

John, we got -- we are constantly on the hunt and not only we’ve been working to fill in on our net position, we feel like we can continue to increase our net position on platform. But we are constantly looking for new opportunities and we are really, really optimistic about some opportunities that we’re chasing. And without saying much, we’re constantly seeing opportunities to come our way. And one advantage I'll state this as in terms of the where the primary public company on the platform, there are opportunities to come our way that may not go to other folks that are just out leasing. They know our activity level and it's been the number of permits. So, it's really advantage for us.

Got it. And following-up there on the gross net comment, you’ve got based on your remarks in the press release, 43,000 net acres perspective or growth acres rather than perspective for horizontal drilling, 26 net you’ve got about 17,000 delta where, how much do you think that you can feel on from that small ballpark estimate?

We’re going to be able to, this is Kelly, John. We’re going to be able to fill in the gaps on some of the net, not question about it. It’s a work in progress. As I mentioned earlier, there is a lot of competition out there. So, you got a lot of guys that are in there competing with us for those nets right now and hoping that what they can do is swapping to us or trading to us, or maybe get a little piece of action. We’ll be in watch from a number of angles. Plus, we’re a very disciplined group of operators, and in that we have a good series of capital. We manage these processes. It is a very cost effectively as opposed to some of the other folks that we run into out there. These costs are considerably higher than ours. And so, I think we’re look at from that angle from a lot of different ways and so, as a result, I do believe we will be able to continue to increase our net position. And I think, we can grow our gross position to the question.

Our next question comes from the line of David Beard of [indiscernible]. Please proceed with your question.

I think a little bit bigger picture question because the lot of the details have been answered. I want to get a little color over your thoughts, if you look out in 2018 and oil was 50 or below. What level of outspending would you tolerate or except or like when you look at trying to not to with spending plan under that technical scenario? Thanks.

Yes, David, we’ve have conversations within the team about that as recent as last week as a matter of fact. And there is no doubt that as we wrap up 2017 as mentioned earlier with the question from one of the earlier gentlemen as related to potential or possible acceleration that remains to be seeing. So, also in configuration of that, you're looking at formulas that will calculate out the cash flows and whether or not you're had shortfalls et cetera. But let's think about one thing for a moment, we are fortunate enough coming into the start of this program that we had a surplus capital at year end of $70 million. We announced the $70 million CapEx at least a preliminary CapEx in the absence of any significant acquisition or any acceleration from what we reported in early January. The likelihood is that we're going to expand upon this CapEx, again as mentioned early in the call, we will visit that about mid-year and make that determination. But given that that would expand optionally, that $70 million is going to go over to a higher number, if we have acquisition opportunities that allow us to extend that footprint that the caller just before John asked about. That could impact change that configuration of that spent and the outspent. The nice thing is we are having the surplus capital along with the cash flow that's accumulating, we kind of figured, if nothing else happen, if we were to state on line where we are at today, current prices that we're seeing somewhere in the neighborhood of the mid-40s on a realized price with the one rig drilling out and possibly adding, an additional handful of wells at the in the last quarter on the horizontal side of this, that we probably see somewhere around a $25 million short-fall. But you add that with the surplus capital we have, we've still end up at year-end with the surplus cash position given the absence of an acquisition or given the absence of acceleration. Now, as you are turning to the next year, well, that's close to all of ours is clear times, but not that clear. So, we're just going to have the play that by year. If you look at this management team and you look at the history that we've been in this business, we're very cautious and we're very careful. We are very sensitive about outspending cash flow. So, if we can manage it and go beyond the cash flow that is provided to the operations, but manage it through either credit facility or other opportunities, whatever we do it's always accretive. So, I don’t think that gives you a direct question you were looking for an answer for that question, but hopefully it gives you a better picture of what we're thinking anyway.

Our next question comes from the line of Michael Zinsser of Formula Group [ph]. Please proceed with your question.

On the acreage acquisition I had a question on have you been able to add any acreage in Q1 and will you give us an update on your debt position on the ops update? And as a follow-on to that question. Are there any larger opportunities in the play either consolidation from larger acreage owners, the majors in the area or larger deals that you could potentially could look at that would be interesting to you in 2017?

Okay. All right, Michael. Let me take that. The answer is, yes, we will address that in the operational update, and yes we have been successful, we have been busy expanding that footprint for obvious reasons, we can't go into the detail now but we will address that in that operational update. The second part of your question, are there larger opportunities that are on the horizon? The potential is there, yes. And that's all we can say for now. Yes, the potential is definitely there that could allow us to expand a much larger footprint that we have now through opportunities that at least we are pursuing and that's that all we can say for now.

And just last one on acreage how cost worthy guys that you sort of drill just circle around these sweet spot or do you have crack the code to understand what part of the acreage you are looking at in perspective for horizontal drilling and/or yield type curve type economics? And what want to make you feel like you've kind of got the science figured out in terms of delineating acreage at this point?

Danny?

That is as I think we are probably about 75% to 80% there and then locking the key. We feel very comfortable with the acreage that we have is good acreage. We’re looking forward for a new opportunity, we feel like, we do have a very good model put together what we’re looking for in those prospects.

There are no further questions over the audio portion of the conference. I’d now like to turn the conference back over to management for closing remarks.

Okay. Thank you operator and thank you everyone. We know this is a busy time and so for you to take the time to be on our call we appreciate it. We appreciate the ongoing support. I think you all see that we have a lot for look forward to in just few weeks when that report comes out. So, until then thank you. Have a good day.

This concludes today’s conference. Thank you for your participation. You may disconnect your lines at this time. Have a wonderful rest of your day.