Ring Energy Inc (REI) 2015 Q4 法說會逐字稿

Greetings, and welcome to the Ring Energy 2015 fourth-quarter and year-end financial and operating results. (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, Chairman of the Board of Directors. Thank you, Mr. Rochford. You may now 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 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'll turn it back over to the operator and open it 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. (technical difficulty) 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, 2015, the Company had oil and gas revenue at $7.4 million and a net loss of $7.5 million, as compared to revenue 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 that were lost was driven primarily by a $9.3 million pretax write-down of our assets based on the ceiling test calculation. Without going into great detail, the 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 period in 2014, despite significant increases in production volumes.

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, an 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 costs 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 (inaudible) operations from the Finley acquisition.

For the three-month period, another significant factor relates to ad valorem taxes. While we attempted to accrue amounts 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 incurred the ad valorem taxes evenly over the year, our production costs 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 is directly correlated to the commodity prices received. Our production taxes as a percentage of revenue remained relatively flat and should continue to be.

Our total depreciation, depletion and amortization, or DD&A, including the accretion of asset retirement obligations, 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 to -- constitutes the bulk of these amounts. The primary driver in the year-end reduction per BOE is the increase in our reserves due 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 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 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 a variety of 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 the result of a variety of factors including higher rent amount in our new headquarters, transaction costs related to acquisitions, and compensation expenses including cash-based compensation, stock-based compensation and benefits.

The decreases in the per-BOE rates for both the three-month and year-end periods are primarily the 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 per 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 for 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 those 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 withdrawals 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 the lead bank on our credit facility regarding our spring redetermination 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 8 development wells. We completed 12 wells that were carried over from 2014, and re-fracked 3 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 saltwater disposable capacity to change out pumps, pumping units and resulted in increased production.

In the fourth quarter, our sales as a result of [oil] production were 212,728 BOEs, which 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, on sales as a result of production were 743,363 barrels of oil equivalent, a [50%] increase over 2014.

Our average net daily production increased to approximately [3,037] 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 a very important thing to remember. With a 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 of 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 a $48.17 per barrel of oil and $2.50 per MCF of gas. That's 91% oil and 33% undeveloped.

In addition to our year-end independent reserve report, our operations team completed an internal study of our current property.

At this time, I'm going to introduce you to Danny Wilson and turn it over to Danny. He's our Executive Vice President of Operations -- to provide more specific information regarding the work in the field that we've done and then our new internal study, which you'll 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 and the last two quarters. We have -- when we took over the Finley property, 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 and upgraded the saltwater disposal system. Did some work there to increase our flexibility as far as the way were able to handle water, being able to move it from one side of the field to the other so we could move it to some underutilized areas.

And that allowed us to go in and start upgrading 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 this 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.

And in the central basin platform, we went into a mode of optimization also. We spent a great deal of time (inaudible) fluid levels, finding wells that weren't being pumped down. We've gone in in some areas and put in fiberglass rods in some wells, so it's allowed us to move more fluid.

And all of those have allowed us with very minimal amount of drilling to continue to grow our production. And if you'll remember, back to our operational report that we did back in January, we actually were able to show a 7% growth quarter over quarter with just very minimal drilling activity.

One of the things I'd like to point out that Kelly alluded to 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 watching 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 in the history now that we've been able to establish some history from those, we are able to actually see what the wells are going to produce, the EURs.

We've done a great deal of work talking to drillers and service companies about what the cost would be associated with the drilling of those will. 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 of -- 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. And then an additional 1,000 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, up to 50% less for similar reserves.

We've 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 very little activity in. It falls below our 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 Concho's just to the north of it. And they have drilled several wells which are extremely favorable. Good reserves, look like they're extremely economical. And we have extrapolated that through looking at their logs, looking on down through our area and the logs that we have available to us. It looks like we have an extremely good potential down through our area also. So we're very excited about that. And, again, the F&D costs on those are very favorable at a very low price.

So those are some of the things that we've been working on here lately. With that, I'll pass it back to Kelly.

Thank you, Danny. Tim?

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

Thank you, Tim. I sure will. Starting with a clear-cut reflection on 2015, as we all experienced, 2015 was really a transition year as the sector adjusted to the new price environment. The wide bid/ask spread and the limited number of sale properties on the street kept the A&D market considerably quieter really than any of us had expected.

But despite the limited deal flow, we were fortunate enough to consummate the Finley acquisition, which was located in the Delaware Basin, located in Culberson and Reeves County, and 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 target properties and are not in the public market.

We also continue to monitor the A&D and M&A landscape for additional opportunities. Since the beginning of the year, we've seen a significant increase in deal flow. So now that we're seeing that bid/ask spread begin to narrow, and if oil prices continue to firm up which we hope this continues, it appears the stars are aligning for an active A&D market and M&A market for the rest of the year.

So with 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 that merger opportunities will also present themselves to us in a variety of ways. We remain patient but are definitely optimistic that this will be an active acquisition year for us.

And with that, Tim, I'll turn it back over to you for closing statements.

Okay. Good job, David. And thanks, everybody. Great job. You know, in summary, in addition to what David just covered as it relates to opportunities on the acquisition side, the 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 is 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 that growth is going to be very impactive. That excites us; hopefully it excites everybody else.

For now, that concludes the Company's portion of the 2015 -- our 2015 fourth- quarter and 12-month financial and operational review. I'm going to turn it back over to Rob now and he's going to open it up for any questions that we may have. Rob? Or you may have -- excuse me.

(Operator Instructions) Neal Dingmann, SunTrust.

Nice details today. Tim, general question maybe for you or Kelly first. I'm sure if I didn't ask, somebody else would. 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 the 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 -- or what would it take to bring a rig or two back later in the year?

You bet. And that's a good question. And it's something that obviously you can imagine that we spent 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, what we're planning to do for now, is in addition to the one well that was drilled this first quarter, we're going to drill approximately another 6 wells in the current environment. And to be honest with you, those 6 wells -- we are realizing $35 plus or minus, in that range.

We can take care of that along with additional remedial work, additional shoring up of infrastructure, leasing activities, et cetera, et cetera. And 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 a realized price of $45, we can go back to work and get a little more aggressive. And if we see $50, then we are 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 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, let me add to onto that now based on kind of what Danny was saying in that study. When you do come back -- or maybe a question for Kelly or any of the guys -- obviously, it sounds interesting on this horizontal location in Andrews. And then to have obviously to 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?

Good question, once again. 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 are you moving out tomorrow? Well, you have got to be a little more patient than that.

But Danny, maybe you could take a moment and just give a little more directional color on how you would see us as we apply vertical versus horizontal when prices reach that magic number.

You bet. Now, I'll tell you what the best areas that we can go back to obviously, when we are looking after -- after we looked at the study, our best opportunities moving forward right now are the horizontals at Andrews. And then also the vertical Cherry Canyon wells in the Delaware basin have an extremely good rate of return, even at low prices, comparable to the St. Andrews 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 St. Andrews wells. And you know what? You'll notice for the first time this year we have 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 St. Andrews and lend themselves to the [whole] vertical drilling.

I can see us moving forward in those particular areas also. I'm not saying we would go to 4 rigs, but we could certainly -- any of those areas makes sense for us once prices recover just a small amount.

No, that makes sense. And then just last question I had, does it come into play -- I forget what your status as far as holding leases. I think at one time, Kel, you said you had to just drill one or two wells. What's the status between the two areas right now?

We're doing really well. For the most part, everything we've got out in the Delaware is basically HCP. And so any work that we would want to do out there might be more elective that would be required. As it relates to central basin platform, we've been able to pick up some very meaningful extensions where we felt we needed to. We've got some leasing efforts going on as part of our budget going forward. They're very -- they're not substantial at all. They are small in nature but they're very meaningful from us.

A lot of landowners are working with us to kick the can down the road to the extent that they do have a lease expiring. But for the most part we are in excellent, excellent shape. I don't see us losing any meaningful acreage of any kind.

Great, guys. Thanks for all the details.

Thank you, Neal.

John Aschenbeck, Seaport Global.

Appreciate the update there on the progress made in the Delaware. I was hoping to get a little more color on that front; in particular, how far along you have come in the process of upgrading equipment. And then also if you have seen any other exploitative opportunities beyond facilities and equipment upgrades such as recompletion candidates or other things of that nature. Thanks.

Danny?

Sure. I would 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've got still just a very small handful of wells that we need to go ahead and upgrade the production equipment on. We have plans, if we need to, 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. And in particular in that area, the Delaware, we own 1,300 plus or minus acres of service out there. We have 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 to over 200,000 barrels a day if we needed to. Now, I'm not saying we're going to do all that right now. I 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. Probably a combination of the two, we have probably got maybe 100 locations that we can go to existing wells and perforate behind pipe in some shallower zones that were bypassed in the past.

So, you know, 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. And then Danny, while I have you, I was hoping you could give me an update on well costs and where those are trending. I understand you aren't being too active right now, but where do you see well costs both on the CVP and in the Delaware?

You know, 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 resume a program in that area, we'll be in the low $300s; somewhere probably between $310,000, $325,000. Somewhere in the range for that area.

In the Central basin -- excuse me -- 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 $600s range fairly easily.

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

No, most of them have -- we're probably looking at that will probably be primarily the Brushy Canyon up. So, you know, the surface to the base of the Delaware Mountain Group. We've got several players that are pretty active in that Wolf Bone area. But we do have a few of the deep rights, but most of those have already been farmed out to other companies.

Okay. Appreciate the detail there. So, the types of transactions to follow up here. The types of transactions you're looking at, would they have similar exploitative characteristics of the previous Delaware transaction?

Yes, they would, John.

Okay, perfect. That's all for me. Appreciate it.

Thanks, John.

Jeff Grampp, Northland Capital.

I wanted to maybe go back to the horizontal wells and just kind of get 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 catalysts that got you guys more confident? And looking at those more aggressively, is that better technology, better completion, lower costs?

And then just kind of building off of that, do you guys have any EUR, F&D type of expectations that you could share here?

Kelly, Danny, I think you guys can --

Yes. Jeff, what we've done obviously -- in and around us for the last couple of years, we've watched a couple of operators drilling these wells. Some have been more successful than others.

And, you know, 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, when oil was $100, we were hearing some of these guys were only getting a 25% rate of return. That kind of made us shy away from that a little bit.

But what we've done since then is some of the operators in the areas have drilled some extremely nice wells. And what we've noticed is they have changed the way they are completing the wells. And that gave us the confidence to go ahead with our study.

We have one operator in particular immediately offsetting those who has in the last year drilled three extremely nice wells. These are direct offsets to us.

And once we saw those and started looking into it, obviously, pricing is very advantageous to us right now. As far as the drill costs go, we've actually sat down with some of the premier horizontal drillers, as far as contractors go in the area, and gotten costs put together. We have talked to consultants that have drilled some of the wells in the area. We've got those costs. We've talked to some major service companies who are doing the completions.

And the combination of all of that and the reserves we're starting to see through those improved drilling techniques and completions technique brought this to the front, and made it look like it would be an extremely good opportunity for us.

Jeff, this is Kelly. I might add one other item in there. You might remember this; I think we have talked about it 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 that were remnant pieces of interest through acquisitions.

In one of those cases, a horizontal well was brought to us by one of these known operators that tossed that to us. And we participated and had access to all the data points.

Super-helpful color, guys. And then just maybe shifting over -- staying on the ops side, Danny or Kelly, on the water flood project, can you guys just talk about -- obviously, you have a lot more opportunities with the horizontals now. But timing of when something like that makes sense relative to the other development opportunities and kind of maybe costs associated with those two areas 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 St. Andrews are well-known. They've been going on 50-plus years in that area. There's a lot of history there of successful floods. And we had noticed these two areas in particular were having very good well results. The quality of the reservoir was very good.

And so we decided to go ahead and delineate 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 Trillium group. And those are the reserves you see this time around in the quarter.

You know, the timing-wise, again, let me point out one other thing. The nice thing about the water flood as you not only get primary but you get the secondary and in most cases this area the secondary is equal to the primary recovery. So large, large amounts of reserves there to deal with.

You know, the drilling of those, I think we've scheduled maybe one rig just to kind of work through that. It would take us probably two years to finish out the drilling, getting things put in place. At that time we would start implementing a flood. And probably within -- you see a quick return on that on those floods. They don't have a lot of turnaround time.

So, you know, I think probably within two, 2.5 years we could have those up and running, or least partially up and running.

Okay, Thanks for the color on that. And then last one for me, Tim, I knew you kind of gave some color around kind of expected draws on our revolver based on where commodities are at now. And appreciate you want to stay away 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 going through 2016?

Very good question, Jeff. And, you know, we have 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 million and $7 million -- let's give us plenty of room possibly, say, $7 million to $10 million would allow us to do the things that Danny has talked about here as it relates to ongoing work both in the Delaware as well as the platform. And that would include approximately 6 more wells, vertical wells on the platform. Possibly some maybe one well in the Delaware.

In addition to that, we have set aside about roughly $2 million plus or minus on leasing activities. All in, we're looking around $12 million for that. And so for that reason, what I'm saying is that in that [$35 million] environment, somewhere between $35 million plus or minus realized price, cash flow, as well as those resources drawn is about what we can anticipate.

Now, if things change in terms of the price deck, as we go forward into the year, as we go long in the year here, and we see an improvement, an advancement of those prices, and we're feeling comfortable with that, well, we're going to come out with something more formal and say, hey look, at these numbers here's what we expect we can do and here's how we're going to go about it. But for now, we're just going to be in a little bit more of an informal stance, 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'd 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 maybe 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'll be impressed. (multiple speakers)

All right. Appreciate the time, guys. Thanks.

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

Yes, perfect. Thank you.

(Operator Instructions) Noel Parks, Ladenburg Thalmann.

Just to sort of put some context on what you're thinking about the horizontal drilling -- I don't know if I missed something, but this is the first time you've actually sort of come out officially and said, we think that 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 seasoned for us is the fact that we've been looking at this, we have kind of had a front-row seat, if you will, watching our neighboring operators.

And as Kelly mentioned earlier and Danny, there are a number of operators -- and, particularly, there are number of operators that have had a lot of success more recently, meaning the last year, year and a half, than the year or two prior to that. So that really has drawn our attention.

But we've 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, we thought, 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're right. I mean, we haven't talked about it in the past. We have been watching it, but it has definitely been the results we have started seeing. You know, these guys -- there was a learning curve associated with this obviously in the St. Andrews. And we were able to sit there and watch it go on. 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've kind of watched what they've done, and we're going to mimic that.

And not to take away from the verticals -- because, Noel, the vertical application there is still our breadwinner. And you'll continue to see lots of activity. I think, as mentioned, we have still in addition -- or aside from that 14,000 or 15,000 acres that would represent somewhere around 130 to 140 horizontal locations, we have an additional 1,000-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 questions that came to mind for me was I think of the St. Andrews as having a fair amount of discontinuity. And so what sort of lateral length do you envision on the horizontal?

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

Yes. You know, it looks like to us that anything less than about a mile, the economics don't work; are 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, the old penetration, is that enough to guide you as far as sort of lateral placement in various locations?

You know what, Neal (sic - Noel), unfortunately, we are very close to a lot of oil production in the area. And you're 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 -- 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 costs might look like.

The EURs are -- and I'll just answer it this way, Neal (sic - Noel), when we look at the number of wells that the horizontal will replace, the reserves are as good or a little bit better than we could get out of -- let's say a 1.5-mile lateral would replace 12 existing wells or 12 vertical wells. We can get that volume plus a little bit extra. And the drilling costs would be a fraction of drilling this well (inaudible).

Okay, great. And I guess just one more thing. If you look at -- I'm thinking about original oil in play. 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 opposed to going to the vertical?

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 a good bit better than we can do with verticals.

Okay. Great. Thanks a lot.

You bet, Noel. Thank you.

If 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 are excited about it.

And if you have follow-up questions, please feel free to reach out to us. But 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.