Ring Energy, Inc. (REI) Q4 2017 Earnings Report, Transcript and Summary

Greetings and welcome to the Ring Energy Inc. 2017 Fourth Quarter and 12 Months Financial and Operating Results. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. 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, Doug and welcome all listeners to the fourth quarter and 12 months 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 Chief Executive Officer; 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, asked our 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 am 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 maybe 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 three 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 at $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 three-month period, the net loss includes a pre-tax 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 pre-tax 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 reference was to adjust the value of our deferred tax assets as a result of the lowered corporate tax rate past as part of the Tax Cuts and Jobs Act of 2017. The tax rate decreased from 35% to 21% until 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 three 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, overall 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 costs. Production costs per Boe for the three months ended December 31, 2017, increased to $12.17 as compared to $12.05 in 2016. For the year ended December 31, 2017, production costs 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 [ph]. Most production taxes are based on values of oil and gas sold. So our production tax expense is directly correlated to 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 three 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 amount the three months 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 volume and the increased depletion rate discussed above. Our overall general and administrative expense increased $935,000 for the three months ended December 31, 2017 and increased $2.5 million for the year ended December 31, 2017 as compared to the same period in 2016. On a per Boe basis this equates to a drop from $8.48 in 2016 to $6.51 in 2017 for the three months period and from $9.14 in 2016 to $7.31 in 2017 for the annual period. The increases in totals were primarily the result of compensation related expenses. The decreases in per Boe rates for the three months and annual periods are primarily a result of increased production volume. On a diluted basis, the loss per share for the three months ended December 31, 2017 was $0.08 as reported. Excluding the $4 million pretax unrealized losses on hedges, the additional tax provision of $7 million and $922,000 non-cash 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 zero per share excluding a $619,000 non-cash 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 $3.7 million non-cash 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 non-cash charge for share based compensation in 2016. As of December 31, 2017, we had no amounts drawn on – of the $60 million borrowing base on our credit facility and had cash on hand of approximately $15 million. For the three months ended December 31, 2017, we had positive cash flow 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. I am going to 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 three months ended December 31, 2017, the company on its Central Basin platform asset drilled 19 new horizontal San Andres wells and we are in the process of drilling 20 at the end of the quarter. Of the 19 drilled wells, 16 were 1-mile and 3 were 3.25-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 scenarios 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 was 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. Maybe you remember that some of those wells take a little bit of time in the testing phases to get to the point where we are 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 wells were 1.5-mile laterals and 39 were 1-mile and of course those 3 I mentioned were 3.25 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 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 5,159. 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 the same time period for 2016, that’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 4,636 as compared to 3,513 in 2016 and that’s a 32% increase. Crude reserves as determined by Cawley, Gillespie and Associates and Williamson, you might remember we had some waterflood reserves there coupled with our rest of our reserves, which 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 discounted 10% based on the 47.93 barrel of oil and at SEC pricing by the way and a $3.61 per MCF of gas were $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 proved reserves are classified as proved, developed, producing and 10% proved, developed, non-producing and 45% proved undeveloped. The prude reserves consist of approximately 91% oil, 9% natural gas. Internal engineering is estimated at additional 15.95 million barrels of oil equivalent of probable reserves with a PV-10 approximately $126 million using average prices of the $47.93 again 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 in PV-10. And with that, I am 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 well for the year and with various infrastructure in disposal, wells to be drilled in addition to that, when announced that we are on pace to in following that plan. In addition, we have gone ahead and drilled two 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 system has put into place to gather gas from our horizontal properties, which up to this point we have not been realizing the revenue line. We have laid approximately 14 miles of large diameter pipe that in the 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 lines are going to grow as we continue to add more batteries into. We just finished the project, got it up and running last week, are still doing some work on that and adding in batteries. And then of course as we continue to drill, we will be adding into that system. On our North Gaines properties or what everybody refers to as our Devon area, the properties that we leased from Devon last year. Based on the encouraging results that we saw on 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 are in the very, very early stages of testing that. We are expanding with different types of completion. Early results are very promising. We are seeing nice little test. Things are progressing well. We still have a great deal of work to do there. The initial work that we have done has strictly been with assets, just to see what kind of results we would get out of that, again encouraged by that. And in the next few weeks, we will 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 are 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 will 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 will probably talk about that when we do our operational update for Q2. Other than that, everything is on schedule. Production is looking good and we are anticipating the good quarter. And with that, I am going to turn it over to David Fowler to talk about our leasing and acquisition.

Thank you, Danny. Our land team did 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 net and into December 31, 2017 with a combined total with 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 begin the year with approximately 53,000 gross acres, 32,600 net and ended 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 have increased our net growth of a 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 forward at evaluating new leasing and acquisition opportunities that effectively complements our existing asset. We are excited about what we are seeing in the new leasing acquisition opportunities that lie ahead of us for 2018. We are up to the challenges and are strongly position with plenty of dry powder to build on the success of 2017. And with that I will 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 are going to open it up for any questions that our audience may have. Doug?

Thank you. Ladies and gentlemen, at this time we will be conducting a question-and-answer session. [Operator Instructions] Our first question comes from the line of Neal Dingmann with SunTrust. Please proceed with your question.

Good morning guys.

Good morning Neal.

Tim, a question for you or Kelly just may or may be for David just on the sort of sequence you have obviously a tremendous amount of acreage just even the Brushy Canyon, Delaware side, can you give us an idea Kelly about how you are going to tell where you stay sort of more down south here for the remainder of this year and into next year or is the plan I know you think you have got a well flowing back up further up north kind of what’s the plan to attack that on the platform side?

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 are going to continue expanding on that, obviously the work that we are doing both on the Brushy and the work that we are doing up on the acreage that we acquired from Devon and some of the acreage around that. Those wells and 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 as we are testing these wells and we are getting the information that we need to see and again as Dave commented a while ago, we are seeing what we want to see and we are very excited about what we are seeing. We will 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.

That makes sense. And then just one last one, you all continued your tremendous job of keeping costs contained, I mean we have heard from some of the others that were in more that Midland and Delaware basins that talk here about sort of 10% inflation, thereabout, any comments Danny, you or Kelly can make on what you are seeing in the play are you still kind of assuming that 2.4 or what are you thinking on cost?

Danny?

Yes. Neal, on that we still are not seeing a lot of pressure on our cost going up. I am kind of interested to see how this deal is there – works out. But even if we realize a full – the full 25% or whatever the number ones are 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 sites. But we really feel like we are 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’s an actual number is going to be. But we feel pretty comfortable with that. And we have already just got through the first quarter and we haven’t seen our costs go up yet.

Well, that’s great to hear. Thanks guys.

Thanks Neal.

Our next question comes from the line of Jason Wangler from Imperial Capital. Please proceed with your question.

Hi, good morning guys. I was curious on the Brushy Canyon completion as you went through the optimal date would you be bringing in a new completion crew for that or would you move over to dedicated crew you guys now have in the Central Basin, just curious on how you would kind of balance that?

And Jason on that, right now we are going to use the same crew. We will be moving them over there to work on that, but it will just be a one well and then they will be back right to us on the Central Basin platform. Moving forward with that, that’s a good question. We will certainly have those discussions especially after we see the results from our well and then start putting a full development plan into place. We will 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 the drilling the two rigs. And so as a result of that, we have a few dates in there that we can squeeze and that would accommodate for that, they would not be disruptive at all to the current plan of completions that we have scheduled for this year in regards to our current drilling program.

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

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

Okay, I appreciate it. And I will turn it back.

Thank you. Our next question comes from the line of John Aschenbeck with Seaport Global Securities. Please proceed with your question.

Yes, good morning everyone and thanks for taking my questions. The first question relates to just the general results we have 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 of your type curves and you also now 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?

You are right. I mean, we are seeing better results than the type curve. But 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 are still very comfortable with our type curve. And what I think we want to stick with that as far as the results that we are seeing, I think the shape of the curve, not these are higher, but as far as the shape of the curves and the results that we are seeing, we are 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 great color. It actually leads into my second one here, which is a follow-up on the test you have planned 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 have seen so far, do you believe that the economics on that acreage from a 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 and maybe a little bit more expensive, less expensive what would the moving parts be on the northern acreage?

Yes. John on that part, we are very early in the stage of testing that. I really don’t have – there is no comparable wells to look at in that, so I don’t really have a way to build the type curve at this time and really did a lot of modeling until 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. I think cost wise, I think we are going to be comparable maybe a little bit less than our area to the south, but until I get a few of these wells completed and we actually defined and complete our process as far as how we are going to complete the wells is still a little early for that.

Okay, understood. I appreciate the detail that. That’s it for me. Thanks.

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

Hi, good morning everybody.

Good morning.

Just a follow-up relative to just what kind of data you had both in Northern Gaines and also in Delaware relative to the vertical well control or seismic or any color you could give us compared to where you are 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 moved right in and went ahead and drilled three test wells that basically were just nothing more than we were just their science wells is all they are. We went in and ran some extensive log suites, did some pouring, actually took some full bore cores through the area. And then from that modeling, we have been able to do some work and we saw an old 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 kind of very much the similar program, since we bought those properties in 2015, we have drilled several wells all the way through the Brushy Canyon and do the coring and again extensive log work we have done, identified one maybe two 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 that’s what led us to go ahead and start drilling the first well. And again I would say hopefully, we will have some good results that I will share with you maybe at the end of Q2 on that.

I am asking something that everybody asked, but could you just describe what types of acquisitions and joint ventures and just what you are seeing out there relative to properties to acquire?

David?

Sure David. There is a lot of opportunities that we continue to keep our eyes on that are of interest and we are constantly looking to see which ones are going to be more in our wheelhouse. There is a lot of players, piggy-backed players that are north of us in Yoakum and even going into Crawford County along with some that are of course in Gaines County. And those are – lot of them were early into the play and are trying to determine what methods are going to be the best completion methods for the particular area that they are in. David, the San Andres differs from north to south, east to west and everybody has got to kind of determined what’s going to work best for them in the particular area. So, we are on the sidelines watching. Keep in mind too, David, that the Devon asset that we ended up buying last year, that’s about 6 months over the finish line. So, we are 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 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.

Great, I appreciate all the color on both questions and thanks for the time.

Thank you.

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

Hi, guys. 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 had like 11 horizontal puds booked and I guess relatively similar to last year I was just kind of wondering what’s kind of preventing that from being higher or that is conservatism on your end and if you guys have it off-hand, do you guys have kind of an average EUR for the horizontal that you did?

Well, that’s a good question. I think Danny can address that.

You bet. Jeff part of that as you know, you are right. We ended basically with the same number of the puds as the year before. And the reason for that is because we have our area where we have built out our infrastructure and we are trying not to jump from one area to another area as far as the spreading out too far that is going to cause us to duplicate or triplicate that infrastructure that we are working on. And so what we do is we will drill an area and they 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 we don’t jump over one area and add a whole bunch of puds in another area and that whole bunch of puds we just kind of gradually are increasing the footprint. As far as the EURs, I think they are in line with our type curve where I think we are still looking at 350,000 gross EUR as we move forward.

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

Yes. I am 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 are kind of thinking about production trajectory through the year obviously a ton of wells coming on in the near-term, I was wondering if you guys can kind of give us any line of sight 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 have 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 going into 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 – and then our production for the quarter. I think we are comfortable in saying the same thing again this quarter.

Okay, perfect.

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

Hello, good morning. Just starting with the Brushy Canyon, I apologize if you went through this already, but how long is that 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 are 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 a mile. We are actually starting on lease, finishing on lease. The lateral is probably going to be about 4,500 feet.

Okay, that’s helpful. Thank you. 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 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 out at 15 per quarter. And I think we are right on track.

Okay, okay, alright. You had mentioned just a little while ago Danny about 350,000 barrel gross EUR for the 1-mile lateral, still thinking of around 500,000 gross for the 1.5 milers or was that too [indiscernible]?

You are right on, that’s exactly right.

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

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

Okay. Thank you, Tim. That’s helpful. And that’s all for me today. Thanks.

Thanks, Richard.

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

Very good, Doug. Thank you. We appreciate everybody’s time today. We know that it’s kind of the tail end of a lot of teams reporting, still 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 will look forward to posting that information and talk to you all soon.

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.