Ring Energy Inc (REI) 2017 Q4 法說會逐字稿

Greetings, and welcome to the Ring Energy, Inc. 2017 Fourth Quarter and 12 Month Financial and Operating Results. (Operator Instructions) As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Tim Rochford, Chairman of the Board of Directors. Thank you, Mr. Rochford. You may begin.

Great, thank you. Thank you, Doug. And welcome all listeners to the fourth quarter and 12 month 2017 financial and operations conference call for Ring Energy. Again, my name is Tim Rochford, Chairman of the Board. Joining me on the call this morning is: Kelly Hoffman, our CEO; we have David Fowler, our President; Randy Broaddrick, our CFO; and Danny Wilson, Executive VP and Chief Operating Officer. Today, we will cover the financials and operations for the fourth quarter and 12 months ended December 31, 2017. We will review the results and provide some insight as to the current progress thus far in the first quarter of '18. At the conclusion of our overview, we will open up the call for questions that you may have.

At this time, I'm going to ask Randy Broaddrick to review the financials. 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 Thursday, March 15. If you do not have a copy of the release, one will be posted on the company website at www.ringenergy.com.

For the 3 months ended December 31, 2017, the company had oil and gas revenues of $23.3 million and a net loss of $4.5 million, as compared to revenues of $9.8 million and a net loss of $477,000 in the fourth quarter of 2016. For the year ended December 31, 2017, the company had revenues of $66.7 million and net income of $1.8 million as compared to revenues of $30.9 million and a net loss of $37.6 million for the same period in 2016. For the 3 month period, the net loss includes a pretax unrealized loss on hedges of $4 million and an additional tax provision of just under $7 million. Without either of these items, net income would have been approximately $4.7 million.

For the year ended December 31, 2017, the net income includes a pretax unrealized loss on hedges of $4 million and the same additional tax provision of just under $7 million. Without these items, net income would have been approximately $11 million. For 2016, the net loss included a ceiling test write-down of $56.5 million. As explanation, the additional tax provision referenced was to adjust the value of our deferred tax asset as a result of the lowered corporate tax rate passed as part of the Tax Cuts and Jobs Act of 2017. The tax rate decreased from 35% to 21%, and so we had to calculate the value of the tax asset based on the new lower tax rate. The difference in the values had to be written off.

For the 3 months ended December 31, 2017, our oil price received was $53.16 per barrel, an increase of 16% from 2016, and our gas price received was $3.35 per Mcf, a 21% increase from 2016. On a per BOE basis, the fourth quarter 2017 price received was $50.70, an increase of 22% from the 2016 price. For the year ended December 31, 2017, our oil price received was $48.97 per barrel, an increase of 25% from 2016, and our gas price received was $3.23 per Mcf, a 29% increase from 2016.

On a per BOE basis, the price received during the year ended December 31, 2017, was $46.36, an increase of 32% from the 2016 price. Production cost per BOE for the 3 months ended December 31, 2017, increased to $12.17 as compared to $12.05 in 2016. For the year ended December 31, 2017, production cost decreased to $11.11 per BOE as compared to $11.24 for the same period in 2016. 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 asset retirement obligation per BOE increased for the 3 months ended December 31, 2017, to $16.01 per BOE as compared to $12.98 per BOE for the same period in 2016. For the year ended, the rate increased from $13.63 to $14.66. Depletion calculated on our oil and gas properties subject to amortization constitutes the bulk of these amounts. As to total amounts, the 3-month period ended December 31, 2017, increased approximately 136% from the comparable period in 2016. For the year, the total DD&A increased approximately 76%. These increases are the result of a combination of significantly higher production volumes and the increased depletion rate discussed above.

Our overall general and administrative expense increased $935,000 for the 3 months ended December 31, 2017, and increased $2.5 million for the same -- for the year ended December 31, 2017, as compared to the same periods in 2016. On a per BOE basis, this equates to a drop from $8.48 in 2016 to $6.51 in 2017 for the 3-month periods, and from $9.14 in 2016 to $7.31 in 2017 for the annual periods. The increases in totals were primarily the result of compensation-related expenses. The decreases in the per BOE rates for the 3 months and annual periods are primarily a result of increased production volumes.

On a diluted basis, the loss per share for the 3 months ended December 31, 2017, was $0.08 as reported. Excluding the $4 million pretax unrealized loss on hedges, the additional tax provision of $7 million, and a $922,000 noncash charge for share-based compensation, the loss becomes net income of $0.10 per share. This is compared to a loss per share of $0.01 as reported, or a very small loss equating to 0 per share, excluding a $619,000 noncash charge for share-based compensation in 2016.

For the year ended December 31, 2017, net income per diluted share was $0.03 as reported. Excluding the $4 million pretax unrealized loss on hedges, the additional tax provision of $7 million and a $3.7 million noncash charge for share-based compensation, this becomes net income of $0.25 per share. This is compared to a loss per share of $0.97 as reported or income of $0.02 per share, excluding both a $56.5 million ceiling test write-down and a $2.3 million noncash charge for share-based compensation in 2016.

As of December 31, 2017, we had no amounts drawn on the $60 million borrowing base on our credit facility and had cash on hand of approximately $15 million.

For the 3 months ended December 31, 2017, we had positive cash flows of approximately $14.6 million or $0.26 per diluted share, compared to approximately $5 million or $0.12 per diluted share for the same period in 2016. For the year ended December 31, 2017, we had a positive cash flow of approximately $40.9 million or $0.77 per share, compared to $13.1 million or $0.34 per diluted share for the same period in 2016.

With that, I will turn it back to Tim.

Okay. Thank you, Randy, good job. Can I ask Kelly Hoffman, our CEO, to give us a recap on the fourth quarter and 12-month activities for the year.

Thank you, Tim. Thanks, everyone, for joining us today. In the 3 months ended December 31, 2017, the company on its Central Basin Platform asset drilled 19 new horizontal San Andres wells and we're in the process of drilling 20 at the end of the quarter. Of the 19 drilled wells, 16 were 1 mile and 3 were 3/4 mile, and that was simply due to lease boundary issues. In the fourth quarter, the company completed, tested and filed initial potentials on 13 new wells. Of those San Andres wells, 8 wells were drilled in the third quarter and 5 that were drilled in the fourth quarter. The average IP on those 13 wells completed in the fourth quarter 2017 is approximately 458 barrels of oil equivalent. In addition, the company has 20 new San Andres wells at that time, which are currently in various stages of completion and testing. Many of you remember that some of those wells take a little bit of time in the testing phases to get to the point where we're ready to file the initial potentials. And for the 12 months ended December 31, 2017, the company drilled 47 new horizontal wells on its Central Basin Platform asset, and 5 of the wells were 1.5 mile laterals and 39 were 1 mile, and of course, those 3 I mentioned were 3/4 mile. And of the 47 wells drilled, 27 were completed, tested and had IPs filed, and the average IP on the 27 wells, completed wells in 2017 was 584 barrels of oil equivalent a day.

Net production for the fourth quarter of 2017 was approximately 422,000 BOEs, and that's barrels of oil equivalent, as compared to net production of 240,000 BOEs for the same period in 2016, and that's a 76% increase. Net production of 376,000 for the third quarter of 2017, which was approximately 12% increase. And in December 2017, average net daily production was 5,352 barrels of oil equivalent as compared to net daily production of 2,725 BOEs in December 2016. And net daily production of 4,345 BOEs in September of 2017. The average price received per BOE in the fourth quarter of 2017 was $51.59. For the 12 months ended December 2017, net production was approximately 1,402,000 barrels of oil equivalent as compared to 865,500 barrels of oil equivalent for the 12 months ended at the same time period for 2016, and it's an approximate 62% increase. Our average net daily production increased to approximately 3,841 barrels of oil per day. The average sales price was $46.36 as compared to $35.13 in 2016, and that's a 32% increase.

Proved reserves, as determined by Cawley, Gillespie and Associates and Williamson, you might remember, we had some waterflood reserves there, coupled with our -- the rest of our reserves, which went to -- built for us in that scenario, and they totaled 31,949,990 barrels of oil equivalent, that's a 15% increase over the 27,741,575 barrels of oil equivalent for the previous year. Future net revenues before income taxes discount at 10%, based on a $47.93 barrel of oil, and that's SEC pricing, by the way, and a $3.61 per Mcf of gas or $382 million -- $382.1 million at year-end 2017, and this compared to $217 million, using average prices of $39.17 per barrel of oil, and $2.43 for the gas for the year-end of 2016. Approximately 45% of the proved reserves are classified as proved developed producing and 10% proved developed nonproducing and 45% proved undeveloped. The proved reserves consist of approximately 91% oil, 9% natural gas. Internal engineering has estimated an additional 15.95 million barrels of oil equivalent of probable reserves, with a PV-10 of approximately 126 million, using average prices of the $47.93 [staying] with the SEC pricing and $3.61 for the gas. The estimated combined totals for proved and probable reserves 2P are 47.899 million barrels of oil equivalent and 508.16 million PV-10.

And with that, I'm going to turn it over to Danny for an operational update.

Sure. Thank you, Kelly. Earlier this quarter, we announced our CapEx for 2018, which included the drilling of 60 wells -- 60 horizontal San Andres wells for the year, and with various infrastructure and disposal wells to be drilled in addition to that. I want to announce that we are on pace to, in following that plan. In addition, we have gone ahead and drilled 2 disposals for this quarter. And in addition to that, we have finished the build-out of a very extensive gas gathering system on our Central Basin Platform asset. This gas -- this system is put into place to gather gas from our horizontal properties, which up to this point, we have not been realizing the revenue on. We have laid approximately 14 miles of large-diameter pipe, put in a compressor station and now are selling upwards of 2.5 million cubic feet a day, which prior to the installation of that system, we were selling just a little over 0.5 million a day. We anticipate those volumes are going to grow as we continue to add more batteries into it. We just finished the project, got it up and running last week. We're still doing some work on that and adding in batteries, and in the course as we continue to drill, we'll be adding into that system.

On our North Gaines properties, or what everybody refers to our Devon area, the properties that we leased from Devon last year. Based on the encouraging results that we saw in our first 3 test wells up in that area, we went ahead and, in this quarter, have drilled our first horizontal San Andres well. We're in the very, very early stages of testing that. We're experimenting with different types of completion. Early results are very promising. We're seeing nice oil cuts, things are progressing well. We still have a great deal of work to do there. The initial work that we've done has strictly been with acids, just to see what kind of results we would get out of that. Again, very encouraged by that, and in the next few weeks, we'll be moving a frac crew in to do some work -- additional work on that. Hope to have some results to visit with you about when we get to our operational update in April.

In addition, we have -- we're actually in the process of drilling our first Brushy Canyon horizontal well over in our Delaware properties. We should TD that well later this -- if not over the weekend, early next week. It'll be a little while before we get a frac crew out there. We probably will have the results of that well at the end of Q2. We'll probably -- we'll talk about that when we do our operational update for Q2. Other than that, everything is on schedule. Production is looking good and we're anticipating a good quarter.

And with that, I'm going to turn it over to David Fowler, to talk about our leasing and acquisition.

Thank you, Danny. Our land team did a great job in 2017 increasing our total acreage position in the Permian Basin. We began 2017 with just over 74,000 gross acres, 53,000 acres net, and ended December 31, 2017, with a combined total for the Central Basin Platform and the Delaware Basin of 123,000 gross, and about 90,000 net, an increase of approximately 40%. If you focus on just the platform, we began the year with approximately 53,000 gross acres, 32,600 net, and ended the year with 102,000 gross acres, 70,600 net. And that's an increase of approximately 48% on the gross acreage add, and a 54% add on the net acreage basis. So as a result, over the course of the last year, 2017, we've increased our net growth on the platform by approximately 6%. The land staff continues to not only add, but fill in areas where we have identified horizontal potential, while simultaneously looking for and evaluating new leasing and acquisition opportunities that effectively complement our existing asset. We're excited about what we're seeing and the new leasing and acquisition opportunities that lie ahead of us for 2018. We're up to the challenges and are strongly positioned with plenty of dry powder to build on its success in 2017.

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

Okay, thank you, David -- thank you, guys. Good job. Well, this concludes the company's portion of the 2017 fourth quarter and 12-month financial and operational review. I want to turn it back over to Doug now, our operator, and we're going to open up for any questions that our audience may have. Doug?

(Operator Instructions) Our first question comes from the line of Neal Dingmann with SunTrust.

Tim, I got a question for you, or Kelly just, or maybe even for David, just on the sort of sequence. You have, obviously a tremendous amount of acreage just -- even the Brushy Canyon Delaware aside, can you give us an idea, Kelly, of how you were going to tie -- will you stay, sort of more down south here for the remainder of this year and into next year? Or is the plan -- I know, I think you've got a well, a few flowing back up, further up north, kind of what's the plan to attack that on the platform side?

Yes, good question. Kelly, go ahead and take that.

Yes, Neal. We have an ongoing program, of course, on what you were referring to as the down south area, and we're going to continue expanding on that. Obviously, the work that we're doing, both in the Brushy and the work that we're doing up on the acreage that we acquired from Devon and some of the acreage around that, those wells in that concept have already taken off. And that's by moving in and drilling this first well on each of those locations. What our plan is, is as we are testing these wells and we're getting the information that we need to see, and again, as Danny commented a while ago, we are seeing what we want to see, and we're very excited about what we're seeing. We'll start expanding on some of that appropriately, I guess, you would say, but not to disrupt the plan that we have right now for growth that's happening right on the southern acreage.

Yes, makes sense. And then, just one last one. You all continue to do a tremendous job of keeping cost contained. I mean, we've heard from some of the others over in -- more of the Midland and Delaware Basins that are talking about sort of 10% inflation thereabouts. Any comments, Danny, you or Kelly can make on what you're seeing on -- in the play, are you still kind of assuming a 2.4? Or what are you thinking on cost?

Danny?

Neal, yes, I think, Neal, on that, we still are not seeing a lot of pressure on our cost going up. I'm kind of interested to see how the steel tariff works out. But even if we realize a full, the full 25% or whatever, the number winds up being on that, it only affects our cost about 2% on our overall costs. We haven't seen any pressure -- upward pressure on our drilling rig costs, and very little on our completion side. So we really feel like we're probably going to be able to stay -- we might see maybe as much as 5% inflation this year on our cost, you might say 3% to 7%, I don't know what the actual number's going to be, but we feel pretty comfortable with that. And I mean, we're already this far through the first quarter, and we haven't seen our cost go up yet.

Our next question comes from the line of Jason Wangler from Imperial Capital.

I was curious on the Brushy Canyon completion as you went through the [optimum] phase. Would you be bringing in a new completion crew for that, or would you move over the dedicated crews you guys now have in the Central Basin? Just curious on how you kind of balance that?

Yes, good question.

Yes, and Jason, on that. We -- right now, we're going to use the same crew. We'll be moving them over there to work on that, but it'll just be a 1 well and then they'll be back, back with us on the Central Basin Platform. Moving forward with that, that's a good question, we'll certainly have those discussions, especially after we see the results from our well and then start putting our, a full development plan into place. We'll approach that. But our initial thought is that we would just move our crew over for a well and then come back.

Jason, something I want to add to that is that the frac crew runs very rapidly as compared to drilling of tube with 2 rigs, and so as a result of that, we have a few dates in there that we can squeeze in that would accommodate for that, that would not be disruptive at all to the current plan of completions that we have scheduled for this year on our -- in regards to our current drilling program.

Okay, that's good color. And then just on the reserves, just kind of looking through the numbers, there were some revisions that were taken out, and obviously, some nice discoveries that you brought in. I assume that's just the shift from vertical to horizontal, the inventory and then in the 5-year rule I guess, but was just curious if that's -- if I'm thinking about that right, as you guys kind of really shift the program to basically entirely, the horizontal focus?

Danny?

That's exactly right. You are spot on, on that.

Our next question comes from the line of John Aschenbeck with Seaport Global Securities.

My first question relates to just the general results you've seen so far from your horizontal San Andres tests. Just looking at the numbers, it seems like the average peak rates from the tests so far have come in higher than the underlying assumptions in your type curve, and you also know have a fairly large sample size, over 30 wells in total. So I guess my question is twofold here. First, I was curious how the longer-term performance of those wells is tracking relative to your type curve? And then secondly, if the longer-term results are indeed tracking above expectations like your peak results have, at what point would you look to address those type curve expectations higher?

Good (inaudible) question, Danny?

You're right. I mean, we are seeing better results than the type curve. However, right now, we don't have any plans to change that. Obviously, the type curve was built on wells from a very large sample area that actually extend out beyond our current footprint. So I think we're still very comfortable with our type curve. And I think we want to stick with that. As far as the results we're seeing, I think the shape of the curve, [indiscernible] fees are higher, but as far as the shape of the curves and the results that we're seeing, we're still very happy with that. And at least, at this time, we don't have any plans to adjust the model.

Okay, great. That's a great color. It actually leads into my second one here, which is a follow-up on the (inaudible) plant, on the northern acreage from Devon. And I believe you mentioned that the drilling process there has already started. So just curious, based on the initial results you've seen so far, do you believe that economics on that acreage, from the returns perspective, can ultimately be on par with your acreage further south? And if there were any changes, whether it be the wells being a little bit bigger or smaller, or maybe a little bit more expensive, less expensive, what would be, moving parts be on the northern acreage?

John, on that part, we are very early in the stage of testing that. I really don't have -- there's no comparable wells to look at, and that's -- so I don't really have a way to build a type curve at this time, and really do a lot of modeling, and so we get probably a couple of wells under our belt. But it is a different area. The completions will be different, the drilling will be different. The -- I think, cost-wise, I think we're going to be comparable maybe a little bit less than our area to the south that until we get a few of these wells completed and we actually define and complete our process as far as how we're going to complete the wells, it's still a little early for that.

Our next question comes from the line of David Beard with Coker Palmer.

Just a follow-up relative to just what kind of data you had, both in Northern Gaines and also in Delaware, relative to vertical well control or seismic, or any color you can give us compared to where you're drilling now, just to give us a sense of what data you used to give you the confidence to put some wells down?

Sure. David, on that, we -- last year, obviously, we bought these properties in May. We've moved right in and went ahead and drilled 3 test wells that basically were just nothing more than we were just -- they're science wells, that's all they are, we went in and ran extensive log suites. Did some pouring actually took some full bore cores through the area. And then from that modeling, we've been able to do some work and we saw an oil column that we were pleased with, and that's what led us into going ahead and starting a drilling, at least an initial test phase well. And then, on the Brushy Canyon, it's kind of very much the similar program. Ever since we bought those properties in 2015, we have drilled several wells all the way through the Brushy Canyon, and through coring and again, extensive log work we've done, identified 1, maybe 2 potential horizontal targets in the Brushy Canyon, and we did a lot of work with Schlumberger, we used some of their world experts to come in and evaluate the property, and they were very encouraging to us about what we thought we had. And that's what's led us to go ahead and start drilling from the first well, and again, I'd say I hope that we'll have some good results to share with you, maybe at the end of Q2 on that.

I'm asking something everybody asked. But could you just describe what types of acquisitions and joint ventures and just to what you're seeing out there, relative to properties to acquire?

Yes, David?

Sure, David. The -- there's a lot of opportunities that we continue to keep our eyes on that are of interest, and we're constantly looking to see which ones are going to be more in our wheelhouse. There's a lot of players, piggy-backed players that are north of us in Yoakum, and even going into Cochran County, along with some that are of course in James County, and those are -- a lot of them are early into the play, and are trying to determine what methods are going to be the best completion methods for that particular area that they're in. You know, David, the San Andres differs from North to Southeast to West. And everybody has got to kind of determine what's going to work best for them in their particular area. So we are on the sidelines watching. But keep in mind too, David, that the Devon assets that we ended up buying last year, took us about 6 months over the finish line, so we're constantly evaluating, looking and processing information, and so it's more about timing, a lot of times. But we don't want to add acreage just to be adding acreage. Our philosophy is to really high grade and look at the assets and make sure that they are complementary to what we currently have.

Our next question comes from the line of Jeff Grampp with Northland Capital.

A couple of reserve questions to start off, to go on Jason's questions from earlier on. On the horizontal front, I think, in the 10-K, you said you guys have like 11 horizontal PUDs booked, and I guess, relatively similar to last year, was just kind of wondering what's kind of preventing that from being higher, or is that just conservatism on your end? And if you guys have it offhand, do you guys have kind of an average EUR for the horizontals that you did book?

Yes, Jeff, that's a good question. I think Danny can address that.

You bet. Jeff, as far as that goes, you're right. We ended basically with the same number of PUDs as the year before. And the reason for that is because we have our area where we've built our infrastructure, and we're trying not to get jumped from one area to another area as far as the spreading out too far that's going to cause us to duplicate or triplicate the infrastructure that we're working on. And so what we do is, we'll drill an area and just continue to step out, basically increasing the footprint from the inside out, and that allows us to just be able to tack on to the infrastructure as we move forward. And of course, that keeps -- we don't jump over one area and add a whole bunch of PUDs, another area and add just a whole bunch of PUDs, we just kind of gradually are increasing the footprint. As far as the EURs, I think they're in line with our type curve. We're, I think we're still looking at a 350,000 gross EUR as we move forward.

And Danny, you are making reference to 1 mile on that 350,000?

Yes, I'm sorry, yes. That is for 1 mile.

Okay, perfect. I appreciate those comments, and for a follow-up, to the extent you guys are comfortable putting anything out, as we're kind of thinking about production trajectory throughout the year, obviously, a ton of wells coming on here in the near term, I was just wondering if you guys can kind of give us any line of sights on, maybe near-term expectations for production, or maybe what you guys have averaged early in the year here?

I think it's -- Jeff, to respond to that, as you know, we've never given formal guidance, but I think that's a fair question, and I think Danny can address how things are going thus far this quarter and kind of as we wrap up the quarter and go into the second quarter.

As we went into the last quarter, we had that same question. And we told everybody, we were probably looking at low double-digit growth in both exit rate and in our reserves, or excuse me, and in our production for the quarter. I think we're very comfortable in saying the same thing again this quarter.

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

Just starting with the Brushy Canyon, I apologize if you went through this already, but how long is the lateral for that well, Danny? And what's the AFE on it?

The AFE is $2.6 million on this particular well, and that's because we're doing a little extra work. Time flies on it. And they are a little deeper than our normal San Andres well. As far as the length, I think, it's just a hair under 1 mile. We're actually starting on lease, finishing on lease. The lateral's probably going to be about 4,500 feet.

Okay, that's helpful. And where on your 20,000 acres roughly, is that well being drilled?

It's going to be down in the Southwest quadrant of our acreage.

Okay, okay. I know you talked a little bit about the production for the first quarter. Can you give us an indication of how many wells have been completed and on-track to complete by the end of the quarter?

Let's say, we announced, of course that we were going to do 60 wells, which works to about 15 per quarter. And I think we are right on track for that.

Okay, okay. All right, you'd mentioned, just a little while ago, Danny, about 350,000 barrels gross EUR for the 1 mile lateral. Still thinking of around 500,000 gross for the 1.5 mile? Or was that 2, I can't recall.

You're right. You're right on, that's exactly right.

Okay, okay. And then just lastly, what drove the increase in the 4Q production actuals versus the prerelease number in January? Was it mainly just looking at production versus sales?

Yes, yes.

So Richard, this is Tim. Let me just jump in here and say, we're always anxious because we know the Street's anxious to hear as we conclude a quarter, we're always anxious to get out information related to the operations. And of course, we're at that early stage, we're making a lot of approximates and estimations. And so there, we estimated, obviously, a little low, and we'd rather to be conservative, and that's exactly what happened.

There are no further questions in the queue. I'd like to hand the call back to management for closing comments.

Very good, Doug. Thank you. Listen, we appreciate everybody's time today. We know that it's at the kind of the tail end of a lot of the teams reporting, but it's still a busy day. So thank you, and as always, we look forward to our remainder of this quarter and on to the rest of the year, and we'll look forward to posting that information and talk to you all soon. Thank you.

Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation. You may disconnect your lines at this time, and have a wonderful day.