Ring Energy, Inc. (REI) Q4 2015 Earnings Report, Transcript and Summary

Greetings and welcome to the Ring Energy 2015 Fourth Quarter and Year End Financial and Operating Results. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. I'd now like to turn the conference over to your host, Mr. Tim Rochford, Chairman of the Board of Directors. Thank you, Mr. Rochford, you may begin.

Thank you, Rob, and welcome all listeners this morning to our fourth quarter and year end 2015 financial and operations conference call. Again, my name is Tim Rochford, Chairman of the Board. Joining me on the call this morning is Kelly Hoffman, our CEO; David Fowler, our President; Randy Broaddrick, our CFO; and Danny Wilson, Executive VP, in-charge of operations. Today, we're going to cover the financial and operations for the fourth quarter and 12 months ended December 31, 2015. We'll also open up and review results and provide some insight as it relates to first quarter of 2016. At the conclusion of the review, we will turn it back over to the operator and open up for any questions that you all may have. At this time, I'd like to ask Randy to give us the review on the financial side. Randy?

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 Monday, March 16, sorry 14. If you do not have a copy of the release, one will be posted on the company Web site at www.ringenergy.com. For the three months ended December 31, 2015, the company had oil and gas revenues of $7.4 million and a net loss of $7.5 million as compared to revenues of $10 million and net income of $2.7 million in the fourth quarter of 2014. For the year ended December 31, 2015, the company had revenues of $31 million and a net loss of $9.1 million as compared to revenues of $38.1 million and net income of $8.4 million for the same period in 2014. The dramatic change in the earnings to a loss was driven primarily by $9.3 million pre-tax write-down of our assets based on the ceiling test calculation. Without going into great detail, ceiling test compares the book value of our assets to the value of our reserves discounted at 10% or PV-10 adjusting both numbers for taxes. Our PV-10 number at year-end 2015 was $240.2 million as compared to $281.7 million at year end 2014. This reduction occurred as a result of significantly lower commodity prices despite more than doubling our reserve volumes. If prices remain at these levels or drop further, we could be required to write-down additional amounts in the first quarter of 2016 and beyond. The next most significant factor in the change of our earnings or loss was the lowered revenue amounts, which were also due to the lower commodity prices. We saw lower revenue totals for both the three months and year end periods as compared to the same periods in 2014, despite significant increases in production volume. For the three months ended December 31, 2015, our oil price received was $38.43 per barrel, a decrease of 42% from 2014. Our gas price received was $2.18 per MCF and 8% decrease from 2014. On a per BOE basis, the fourth quarter 2015 price received was $34.61, a decrease of 47% from the 2014 price. For the year ended December 31, 2015, our oil price received was $44.90 per barrel a decrease of 46% from 2014. And our gas price received was $2.48 per MCF, a 30% decrease from 2014. On a per BOE basis, the price received during the year ended December 31, 2015 was $41.72, a decrease of 49% from the 2014 price. Production cost per BOE for the three months ended December 31, 2015, increased to $13.95 as compared to $11.78 in 2014. For the year ended December 31, 2015, production cost increased to $13.40 per BOE as compared to $10.77 for the same period in 2014. One of the primary reasons for this increase is included in our operations from the Finley acquisition. For the three month period another significant factor relates to ad valorem taxes. While we attempted to accrue amount each quarter to spread the ad valorem taxes over the year, we did not accrue enough due to the Finley acquisition and other factors. While the amount for the year would have been the same, had we accrued the ad valorem taxes evenly over the year, our production cost per BOE for the three months ended December 31, 2015, would have been $12.68 per BOE. 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 deprecation, depletion and amortization or DD&A including accretion of asset retirement obligation per BOE increased for the three months ended December 31, 2015 to $17.94 per BOE as compared to $15.45 per BOE for the same period in 2014. For the year ended 2015, the rate decreased from $25.81 per BOE to $20.98 per BOE. Depletion calculated on oil and gas properties subject to amortization continues -- constitutes the bulk of these amounts. The primary driver in the year-end reduction per BOE is the increase in our reserves do in large part to the Finley acquisition. Regarding total DD&A, the three month period ended December 31, 2015, increased approximately 62% from the comparable period in 2014. For the year ended 2015, the DD&A in total increased approximately 30%. These increases are the result of higher production levels. Our overall, general and administrative expense increased $432,000 for the three months ended in December 31, 2015, and $1.2 million for the year ended December 31, 2015, as compared to the same period in 2014. On a per BOE basis, this equates to a drop from 11.72 that's $11.72 in 2014 to $10.44 in 2015 for the three month period and from $14.68 in 2014 to $10.76 in 2015 for the year. The increase in total for the three month period versus the comparable period in 2014 was a result of a variety of a relatively small changes including compensation related expenses and engineering and geology consulting. For the year ended December 31, 2015 versus the comparable period the increase in total G&A was a result of a variety of factors including higher rent amounts in our new headquarters. The transaction cost related to acquisitions and compensation expenses including cash-based compensation, stock-based compensation and benefits. The decreases and the per BOE rates for both the three month and the year end periods are primarily a result of increased production. On a diluted basis, the loss per share for the three months ended December 31, 2015 was $0.25. This loss is reduced by approximately $0.20 per share excluding the $9.3 million ceiling test and an additional $0.01 per share excluding a $605,000 non-cash charge for share-based compensation for a loss of $0.04 per share excluding both items. This compares to earnings per share of $0.10 as reported or -- in the same period in 2014 or $0.12 per share excluding a $587,000 non-cash charge for share-based compensation. For the year ended December 31, 2015, the net loss per share was $0.32 as reported. This loss is reduced by approximately $0.21 per share excluding the $9.3 million ceiling test write-down and an additional $0.06 per share excluding a $2.6 million non-cash charge for share-based compensation or a loss per share of $0.05 excluding both items. As compared to earnings per share of $0.33 as reported for the year ended 2014 or $0.39 per share excluding a $2.5 million non-cash charge for share-based compensation. As of December 31, 2015, we had drawn down $45.9 million of the $100 million borrowing base on our credit facility. We have not made any additional trials on our credit facility subsequent to year end. However, we anticipate drawing an additional $5 million to $7 million during 2016 based on current economic conditions and projected capital expenditures. We have begun discussions with elite bank on our credit facility regarding our spring re-determination likely to be completed in early May. Given the commodity price environment, we anticipate that our current borrowing base may be reduced. That being said, we do not anticipate any liquidity issues and it will not affect our plans for 2016. For the three months ended December 31, 2015, we had positive cash flow of approximately $2.1 million or $0.07 per diluted share compared to approximately $6.5 million or $0.24 per diluted share for the same period in 2014. For the year ended 2015, we had positive cash flow of approximately $13.4 million or $0.48 per share compared to $27.1 million or $1.04 per diluted share for the same period in 2014. Commodity prices are the biggest factor in these decreases. With that, I will turn it back over to Tim.

Thank you, Randy. Good job. I'd like to now ask Kelly; Kelly if you'd be kind enough to give us an operational update?

Sure. Thank you, Tim. Welcome everyone. Looking back at 2015, we had very little drilling activity and as you remember we completed acquisition of our Delaware assets during that year. Regarding the Central Basin Platform, we drilled eight development wells, recompleted 12 wells that were carried over from 2014 and refrac three wells and upgraded some of our infrastructure. As it relates to the Delaware Basin, we drilled one well, upgraded our infrastructure and of course that included adding new salt water disposal capacity changing our pumps, pumping units and resulted in increased production. In the fourth quarter, our sales as a result of production were 212,728 BOEs, this is a 39% increase over the same period in 2014. Our average daily net production was approximately 2,312 BOEs per day. The average sales price per BOE, we received in the fourth quarter was $34.61 as compared to $65.48 in 2014 and that's a 47% decrease. For the 12 months ended December 31, 2015, our sales as a result of production was 743,363 barrels of oil equivalent, a 50% increase over 2014. Our average net daily production increased to approximately 2037 barrels per day. And the average sales price was $41.72 as compared to $82.18 in 2014 and that's a 49% decrease. I think it's very important to point out something here at this point. And that with little or no drilling, we've been able to continue to see growth just imagine what we would look like once we get back to drilling that's very important thing to remember. With the company the size of ours, those growth numbers as a percentage would be very impactful. Our overall 2015 year end proven reserves are 24.4 million BOE as compared to $10.4 million in 2014. The estimated present value using a 10% discount rate of future net cash flows before income taxes with PV-10, of course, of the company's proven oil and natural gas reserves as of December 31, 2015 was 240.2 million using the average of $48.17 per barrel of oil and $2.50 per MCF of gas that's a 91% oil and 33% undeveloped. In addition to our year-end independent reserve report, our operations team completed their internal study of our current properties. At this time, I'm going to introduce you to Danny Wilson. Turn it over to Danny, he is our Executive Vice President of Operations to provide some more specific information regarding the work in the field that we've done, and then, our new internal study which you want to hear about.

All right. Thank you, Kelly. I wanted to go through a few things that we've done during the last quarter in particular in the last two quarters. We have -- when we took over the Finley properties, we immediately noticed that we had a great deal of upside from an operational standpoint due to the fact that most of the wells in the field if not all of the wells in the field were not being pumped down properly. So we went into a mode of an aggressive optimization program, went in -- that related to salt water disposal system, Bismarck there to increase our flexibility as far as they were able to handle water being able to move it from one side of the field to the other. So we can move it to some under utilized areas. And that allowed us to go in and start-up driving all of the pumping units or the pumping equipment from pumping units to PC pumps in the Cherry Canyon wells that we took over. And it's allowed us to -- in some cases double the amount of fluid that we were moving and subsequently saw a good increase in our oil production. So and in the Central Basin platform, we went into a mode of optimization also. We spent a great deal of [promising] fuel levels, finding wells that weren't being pumped down. We have gone into some areas and put in fiber glass pump -- fiber glass broads in some wells, so it has allowed us to move more fluid. And all of those had allowed us the very minimal amount of drilling to continue to grow our production. If you remember back to our operational report that we did back in the -- back in January. We actually were able to show a 7% growth quarter-over-quarter were just very minimal drilling activity. One of the things, I would like to point out, that Kelly alluded to a little bit about an internal study that we've done. Over the last couple of years, we have spent some time watching some of the other operators in our area in particular the ones that we are doing some horizontal work in the Central Basin platform. And after walking them and seeing the results of some of their wells, we decided to move forward with an internal study to see what our potential would be in that arena. And what we discovered is, we have a tremendous amount of acreage somewhere around 15,000 acres of our 30,000 in the Central Basin platform that appears to be very, very favorable for drilling of horizontal wells. We studied approximately 60 analog wells that have been drilled in and around us over the last three years. The results of those and the history now that we've been able to establish some history from those, we were able to actually see what the wells are going to produce the EURs. We have done a great deal of work talking to drillers and service companies about what the cost would be associated with the drilling of those. It's extremely favorable. We feel like we out of the 2,400 -- 2,500 potential locations that we have in the Central Basin Platform that we have somewhere in the neighborhood -- we can replace about 1,500 of those with horizontal wells, which would give us a little over -- probably 130 to 140 potential horizontal locations with -- an additional 1000 potential vertical locations left behind. The drilling economics on those is extremely favorable on the horizontals, in some cases, 35% to 40% less than the cost of the verticals for the same reserves and in some cases, in some areas at the 50% less or similar reserves. We have also done a similar study of our properties that we took over in the Delaware basin. When we took those over at the time there had been some horizontal work particularly in the Brushy Canyon, which is a zone that we have a very little activity and possible low Cherry Canyon wells that we have. But, we did have some penetrations through that that we were able to evaluate through logging and looking at other operators in the area particularly Devon and [Cornfield] [ph] just to the north of us. And they have drilled several wells which are extremely favorable. Good reserves, look like they are extremely economical. And we have to extrapolate that through the -- through looking at their logs, looking on down through our area in the logs that we have available to us. It looks like we have extremely good potential down through our area also. So we are very, very excited about that. And again, the S&D cost on those are very favorable at a very low price. So, those were some of the things that we have been working on here lately. With that, I will pass it back to Kelly.

Thank you, Danny. Tim?

Thank you, guys. Danny that's great report, very good insight. Let's turn this over to David Fowler, our President. And David you can give us an overview of activities over the last year and what we are seeing now on the development front.

Thank you, Tim. I sure will. Starting with a quick reflection on 2015. If we all experienced in 2015 was really a transition year as of sector adjusted to the new price environment. The widest bid ask spread and the limited number of sale properties on the street kept A&D market considerably quieter really any of us didn't expect it. But, despite the limited deal flow, we were fortunate enough to consummate the Finley acquisition, which was located in the Delaware Basin located in Culbertson and Reeves county. We closed that at the end of June for $75 million. It was a great fit for us since the asset came with a meaningful PDP component and significant upside that Danny just detailed for us. Additionally, the asset was significant in size with just under 20,000 gross acres was largely 100% operated and was mostly held by production. The icing on the cake was the ability to increase production without having to drill new wells, which again, Danny and his operations team has done a great job doing for us. Looking forward to 2016, we are confident and are currently pursuing some bolt-on acquisition opportunities to both our Delaware and Central Basin assets. These opportunities are targeted properties and are not in the public market. We also continue to monitor the A&D and M&A landscape for additional opportunities, just the beginning of the year, we've seen a significant increase in deal flow. So not that we are seeing that bid ask spread begin to narrow and if all process continue to firm-up, which we hope continues. It appears that stars are [indiscernible] market and M&A market for the rest of the year. But, this in mind, we have a strong balance sheet and are sitting in a great position to react quickly and aggressively to acquisition opportunities that fit us. I personally feel that 2016 will be a consolidation year and the merger opportunities will also present themselves to us in a variety of way. We remain patient, but are definitely optimistic that this will be an active acquisition year for us. And with that, Tim, I will turn it back over to you for closing statements.

Okay. Good job, David. And thanks everybody, great job. In summary, in addition to what David just covered, it relates to opportunities on the acquisition side, expansion there. The fact and this was highlighted a couple of times not only with Kelly but with Danny as well. The fact that we have not only maintained production but have provided growth certainly as a testament to the quality of the assets as well as the operational team. And as mentioned earlier, we can all begin to imagine that once we go back to work with the drilling rig the growth is going to be very impactful. That excites us, hopefully it excites everybody else. For now that concludes the company's portion of 2015 or 2015 fourth quarter and 12 month financial and operational review. I'm going to turn it back over to Rob now and he is going to open it up for any questions that we may have. Rob, or you may have, excuse me.

Thank you. [Operator Instructions] Our first question is coming from the line of Neal Dingmann with SunTrust. Please go ahead with your question.

Good morning guys, nice details today. Say, Tim a general question may be for you or Kelly, first, just I'm sure if I didn't ask, what as far as resuming activity, I know you mentioned this in your press release. But how do you and Kelly and the guys and David and all again, if you guys look at it when you think about it, is it more required rate of return, people always ask about what oil price, Tim would you guys need to come back, I'm just wondering in general how do you guys think about what would it take to bring a rig or two back later in the year?

Yes. You bet. That's a good question. And that's something that obviously you can imagine we spend a lot of time on. One thing that Danny didn't mention I know that he was prepared to talk about this and he can a little bit more on the Q&A side as well, but I'll bring it up. We now have, as everyone knows we have no formal CapEx that we presented. Although what we're going to do or what we're planning to do for now is an addition to the one well that was drilled this first quarter. We're going to drill approximately another six wells in the current environment. And to be honest with you those six wells -- if we're utilizing $35 plus or minus in that range, we can take care of that along with additional or immediate work, additional shoring up of infrastructure, leasing activities et cetera, et cetera and we can do that, we can do that again Neal in that $35 plus or minus realized price range. However, once we see the commodity moving into the 40s and particularly as we get up closer to realized price of $45, we can go back to work and get a little more aggressive. And if we see $50, then, we're really kicking on all cylinders. So to your point of your question, internal rate of return, we can see that in the 30s, but we start really hitting on rate of -- return on investment, PV-10 accretion et cetera, et cetera once we get into the 40s, mid 40s and a little bit higher.

And then, Tim a little add-on to that. Now, based on kind of what Danny was saying now on that study, when you do come back or may be a question for Kelly, only the guys, obviously, it sounds interesting on this horizontal locations, I mean San Andres, and then, to have obviously the Brushy Canyon that Devon and other guys have been successful on, when you do come back, how do you think about the plan on vertical versus horizontal potentials?

Yes. Good question. Once again a good follow-up question. I see activity both sides and when you really drill down and see what the economics look like on these horizontals, people are going to start asking right away, well, why aren't you moving out tomorrow? Well, we got to be a little bit more patient than that. But Danny, maybe you could take a moment and just give a little more, maybe little more direction or color on how you would see us as we apply vertical versus horizontal when prices reach that magic number.

You bet. Now, I'd tell you what, the best there is that we can go back to obviously, when we're looking after the -- we looked at the study, our best opportunities moving forward right now are the horizontal San Andres. And then, also the vertical Cherry Canyon wells in the Delaware Basin having extremely good rate of return even at low prices, comparable to the San Andres horizontal and the Brushy Canyon is right there with those. I can see us going back to work in any of those areas or all of them. In addition to that obviously we still like our -- very much like our vertical San Andres wells. And you'll notice for the first time this year, we've incorporated some water flood reserves into our reserve study and that’s because we've identified two areas in particular that have extremely good reservoir quality for the San Andres and lend themselves to the -- the vertical drilling. I can see us moving forward in those particular areas also I'm not saying we go to four rigs, but we can certainly in any of those areas makes sense for us once the process recover just a small amount.

That makes sense. And then just last question I had, does it come in to play, I forget what your status as far as holding leases, I think at one time Kelly you said you had to just drill one or two wells, so what's the status between the two areas right now?

We're doing really well for the most part everything we got on the Delaware is basically HBP. And so, any work that we wouldn't want to do out there might be more elective than it would be required as it relates to Central Basin Platform. We've been able to pick up some very meaningful extensions where we thought we needed to. We've got some leasing efforts going on, it's part of our budget going forward. They're very -- they're not substantial at all, they're small in nature but they're very meaningful from us. A lot of land owners are working with to keep the Canyon down the road to the extent that they do have a lease expiring but for the most part we're in excellent shape. I don't see us losing any meaningful acreage to any kind.

Great guys. Thanks for all the details.

Thank you, Neal.

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

Hey, good morning. I appreciate the update there on the progress made in the Delaware, was hoping to get a little more color on that front in particular how far along you've come in the process of upgrading equipment? And then also, if you’ve seen any other exploitative opportunities beyond facilities and equipment upgrades such as re-completion candidates or other things of that nature? Thanks.

Okay. Danny?

Sure. I wouldn't say probably right now we're about 80% to 85% of the way through our program. We've got a few more things to do. We got to still -- just that very small handful of wells that we need to go ahead and upgrade the production equipment on. We have plans that we need to continue to upgrade our water facility. Right now it looks like we might be able to handle what we even with the new activity we could probably handle the water for a good while to come. We've also taken some steps -- particularly in that area, the Delaware, we own 1300 plus or minus acres of surface out there. We permitted an additional 11 saltwater disposal wells in case we need them. That would take our disposal capacity from somewhere around 60,000 barrels a day up over 200,000 barrels a day if we needed to. Now, I'm not saying, we're going to do all that right now just wanted to let you all know that we've got plenty of room for additional activity there. But the other thing that we've identified John behind pipe is, we have two zones behind pipe only a combination of the two, we've probably got maybe a 100 locations that we can go to existing wells and perforate behind pipes in some shallower zones that were bypassed in the past. So in addition to the small number of -- in addition to the small number of wells that we need to do some more work on, we have roughly 100 or so behind pipe opportunities there too.

Okay. Perfect. That's great. Then Danny what have you -- I was hoping you could give me an update on well costs somewhere those are trending and understand you aren't being too active right now, but where do you see well cost both on the CBP and in the Delaware?

We continue to monitor that. We just finished the one well we did drill in the first quarter in the Central Basin Platform. We brought in under $350,000 in fact a good deal under that. We feel like if we can, once we could resume on program in that area. We'll be in the low 300s somewhere probably between 310, 325 somewhere in that range for that area. In the Delaware Basin, the first well we drilled out there came in under 650,000, which was half of what the previous operator was drilling them for. We feel like we can stay in that low 600s to mid 600 range fairly easily.

Okay. Appreciate that. Then just a quick question for David on M&A, in regard to the potential bolt-ons, you mentioned in the Delaware, curious if any of those deals have rights to the Bone Spring or the Wolfcamp?

No. Most of them have -- we're probably looking at that would probably be primarily the Brushy Canyon, the surface to the base of the Delaware Mountain Group. We've got several players that are pretty active in that Wolf, Bone area. And but, we do have a few of the deep rights but most of those have already been formed out to other company.

Okay. Appreciate the detail there. So the types of transactions as follow up here, types of transaction you're looking at with a similar exploitated characteristics of the previous Delaware transaction?

Yes. They would John.

Okay. Perfect. That's all for me. Appreciate it.

Thanks John.

Our next question is from the line of Jeff Grampp with Northland Capital. Please go ahead with your questions.

Good morning guys. Wanted to maybe go back to the horizontal wells, and then, just kind of get, I guess your thoughts; obviously, guys have been doing horizontals there for a few years. So just kind of wondering from the analysis that you guys have done what was kind of the catalyst that got you guys more confident and looking at those more aggressively that better technology, better completions, lower costs, and then, just kind of building off of that, do you guys have kind of any EUR, F&D type of expectations that you could share here?

Kelly, Danny, I think you guys can…

Yes. Jeff, what was done obviously in and around us for the last couple of years we watched a couple of operators drilling these wells. Some have been more successful than others. And when we first started watching this we were really unsure as to what the success rate was going to be or how profitable the wells were. We were hearing things that, I mean the well was $100, we were hearing some of these guys were only getting 25% rate of return, that kind of made us shy away from that a little bit. But what we've done in that, since then as some of the operators in the areas have drilled some extremely nice wells. And what was noticed is, as they've changed the way they're completing the wells and that gave us the confidence to go ahead with our study. We have one operator in particular immediately offsetting us who has in the last year drilled three extremely nice wells either direct offsets to us. And once we stalled those starting looking into it obviously processing is very advantageous to us right now as far as the drill cost though. We've actually sat down with some of the premier horizontal drillers as far as contractors though in the area. And that cost put together, we've talked to consultants that have drilled some of the wells in the area got those costs. We've talked to some major service companies who are doing the completion. And the combination of all that and the reserves we're starting to see through those improved drilling techniques and completion techniques brought this to the front and made it look like it would be extremely good opportunity for us.

Jeff, this is Kelly. I might add one other item in there, as you might remember this, I think we talked about in the past. But we own some partial interest in a couple of properties out there also where we own 5%, 6%, 8% things of that nature. We're in the pieces that came to us through acquisitions. In one of those cases a horizontal well was brought to us by one of these known operators that offset to us and we participated and had access to all the data points.

Super helpful color guys. And then, just maybe shifting over on -- say on the offside Danny or Kelly on the water flood project. Can you guys just kind of talk about obviously have a lot more opportunities with the horizontals now, but timing of one something like makes sense relative to other development opportunities and kind of may be cost associated with those [indiscernible] you've identified so far?

Jeff, early on we identified some areas in our Central Basin Platform that, we thought had excellent water flood capabilities, water floods in the San Andres are well known mingling on for 50 plus years in that area. There is a lot of history there are successful flood. And we had noticed these two areas in particular where we're having very good well results, the quality of the reservoir was very good and so we decided to go ahead and lineate those and have one of our -- one of the best water flood companies here in town engineering firms in town help us with that and that's the Williamson Petroleum Group and those are the reserves you see this time around in the quarter. The timing was -- again, let me point out one of the thing, the nice thing about the water flood is you not only get primary, but you get the secondary. And in most cases in this area, the secondary is equal to the primary recovery. So a large, large amounts of reserves that are to deal with. The drilling of those, I think we've scheduled maybe one rig as to kind of work through that, it would take us probably two years to finish out the drilling, getting things put into place, that time we would start implementing the flood and probably within you see a quick return on those floods. They don't have a lot of turnaround time. So, I think probably within 2, 2.5 years, we could have those up and running, or at least partially up and running.

Okay. Thanks for color on that. Then last one for me, Tim, I know you kind of gave some color around kind of expected to draw revolver based on where commodities are at now. And appreciate [indiscernible] from a firm guidance, but just kind of production trajectory throughout the year is flat kind of a decent way to think about things with maybe some upside to growth or kind of big picture how should we be thinking about production is going through 2016?

Yes. Very good question, Jeff. And, we spent a lot of time on this as well as you can imagine and what I mentioned earlier referencing the senior credit facility is, we believe that somewhere between 5 and 7, let's give us a plenty of room possibly say $7 million to $10 million would allow to do the things that Danny has talked about here, as it relates to ongoing work both in Delaware as well as the platform and that would include approximately 6 more wells, vertical wells on the platform possibly some -- maybe possibly one well in the Delaware. In addition to that, we've set aside about roughly 2 million plus or minus on leasing activities all in we were looking around $12 million for that. And so for that reason what I'm saying is that in that $35 environment, somewhere between $35 plus or minus realized price, cash flow as well as those resources drawn is about what we could anticipate. Now, if things change in terms of the price debt, as we go forward into the year, we go along in the year here and we see an improvement and an advancement of those prices. And we are feeling comfortable with that. We are going to come out with something more formal and say, hey, look these numbers, here is what we expect we can do and here is how we're going to go about it. But for now, we're just kind of being a little more of an informal stands, but that's about what you can expect. And lastly, with your question as it relates to production profile. I know Danny feels very comfortable. And Danny, if you would like to comment on this go ahead. But, I know Danny feels very comfortable that what we are doing thus far in this quarter is as good or better than last quarter or in the fourth quarter of last year and the next three quarters following, we are going to be fairly close flat, plus or minus. But, I think you will be impressed.

Yes.

All right. Appreciate the time guys. Thanks.

You bet, Jeff. Does that answer all of your questions, Jeff?

Yes, perfect. Thank you.

You bet.

Thank you.

[Operator Instructions] The next question is from the line of Noel Parks with Ladenburg Thalmann. Please go ahead with your question.

Good morning.

Good morning, Noel.

Hi. Just a sort of put come context on what you're thinking about the horizontal drilling. First, I missed something, this is the first time, you've actually sort of come out officially and said, we think this play has horizontal potential. So this is new, right?

That's correct. That's new for us. Although, Noel what's -- a little bit season for us is the fact that we've been looking at this. We kind of had a front row seat if you will watching our neighboring operators. And as Kelly mentioned earlier and Danny, there were number of operators and particularly there are number of operators that had a lot of success more recently meaning the last year, year and a half, then the year or two prior to that. So that really is -- really drawn our attention. But, we have been watching it closely. And as Danny mentioned earlier on the call at a certain point in time, when we realized what was going on very close proximity -- okay, this deserves some more attention. And we have delved into that study. But, Danny feel comfortable here to visit with Noel, if you want to reflect or add anything to that?

No. You are right. I mean, we haven't talked about it in the past. We have been watching it. But, it's definitely been the results we have started seeing. These guys -- there was a learning curve associated with this obviously in the San Anders. And we were able to sit there and watch it. And we feel like now, we can come in and duplicate the efforts of these people now that they are higher up on the learning curve. So, we didn't spend our time and effort, trying to reinvent the wheel, we kind of watched what they have done and we are going to mimic that.

And not to take away from the verticals because Noel, the vertical application there is still our breadwinner. And you will continue to see the lots of activity, I think as mentioned we have still in addition or aside from that 14,000 to 15,000 acres that would represent somewhere around 130 to 140 horizontal locations. We have an additional 1000 plus locations still remaining on the platform on that 10-acre location application. So again, where it makes sense, we're going to drill vertically and where it makes even more sense we're going to drill horizontally.

Great. Now, one of the question that came to mind for me was, I think of the San Andres is having a fair amount of sort of discontinuity and so what sort of lateral lengths do you envision on the horizontals?

That's a great question. I'm glad you asked that. Danny would you give him some more color on that please?

Yes. It looks like to us that anything less than about a mile the economics don't work or not as favorable certainly. The work we've done it looks like our average lateral could be closer to 1.25 maybe 1.3 miles per well and that gives us a great return when we're looking at that.

Okay. And is the well control you can get just from the legacy data that the old penetration, is that enough to guide you as far as sort of lateral placement in various locations?

You know what -- unfortunately we are very close to a lot of oil production in the area. And you are right, we would not need necessarily do seismic, wouldn't have to do a lot of test holes, I think we can be fairly confident just going with the data that's available to us now.

Great, great. And I think somebody else had asked this, sorry if I missed the answer. If you had sort of a feel for EURs and also if you had an idea of sort of what well cost might look like?

EURs are -- or I'll just answer it this way Noel, when we look at the number of wells that horizontal will replace. The reserves are as good or little bit better than we could get out, just say a mile and a half lateral would replace 12 existing well or 12 vertical wells. We can get that volume plus a little bit extra. And so the drilling cost would be a fraction, drilling the 12 wells.

Okay, okay great. And I guess just one more thing, if you look at I'm thinking about original oil in place, do you have a sense of sort of what the incremental recoverability is that you might get from being able to develop horizontal in some of these areas as supposed to going for the verticals?

I don't have a percentage. I can exactly give you, but we do feel like from what we're seeing from the offset operators that it is better than -- it's good to be better than we can do with the vertical.

Okay. Great thanks a lot.

You bet. Well, thank you.

Thank you. There are no additional questions at this time. I would turn the floor back to management for closing remarks.

Okay. Thank you, operator. Listen, we want to thank everyone for taking the time today. We hope that we've answered the questions. We've certainly opened up some areas that are new for us as, it relates particularly to the horizontal application on both the Delaware as well as the platform. We're excited about it. And if you have follow-up questions please feel free to reach out to us. With that operator, we'll sign off and thank everybody once again.

Thank you. This concludes today's conference. Thank you for your participation and you may now disconnect your lines at this time.