Ring Energy, Inc.
Q4 2020 Earnings Call Transcript

Published: 17 Mar 2021

[Operator:]

Good morning, and welcome to the Ring Energy Fourth Quarter 2020 Earnings Conference Call. All participants will be in a listen-only mode. . After today’s presentation, there will be an opportunity to ask questions. . Please note, this event is being recorded. I would now like to turn the conference over to David Fowler with Investor Relations. Please go ahead.

[David Fowler:]

Thank you, Chad, and good morning, everyone. Thank you for taking the time this morning to join us and for your interest in Ring Energy. We will begin our call with comments from Paul McKinney, our Chairman of the Board and CEO, who will provide an overview of key matters during the fourth quarter and full year, including a review of our year-end reserve report. We will then turn the call over to Randy Broaddrick, our CFO, who will review our financial results. Paul will then return with a review of strategy and plans for 2021. Also joining us this morning on the call is Alex Dyes, our Executive Vice President of Engineering and Corporate strategy; and Marinos Baghdati, our Executive Vice President of Operations; and Steve Brooks, our Executive Vice President of Land, Legal, Human Resources and Marketing; all of whom will be available for our Q&A session.

[Paul McKinney:]

Thank you, David, and welcome, everyone, to our year-end 2020 call. Let's start with a review of the key highlights of our fourth quarter. We exceeded the high end of our guidance with sales volumes of 9,307 barrels of oil equivalent per day, of which 86% was oil. Contributing to our production outperformance was a continuation of our highly successful workover and reactivation efforts. We also performed 8 CTRs in the fourth quarter, including 4 in the Northwest Shelf and 4 in the Central Basin Platform. Our ongoing CTR program converts wells from electrical submersible pumps to rod pumps, which reduces future overall operating costs and lessens costly workovers. During the fourth quarter, we generated $25 million of adjusted EBITDA that contributed $13 million of free cash flow during the period, marking our fifth consecutive quarter of free cash flow. We utilized our free cash flow and the cash on hand to pay down $47 million of bank debt and ended the period with $41 million of liquidity, increasing our liquidity by more than 25% than what we had at the end of the third quarter. Finally, with the funds from equity rays and supported by rising oil price environment, in early December, we initiated a targeted Northwest Shelf drilling program that focuses on our highest rate of return inventory. All 4 of the wells drilled in our winter drilling campaign have been completed and are on production. As we noted in our release, the first well we drilled, the Badger 709 B 6XH, is currently producing over 400 barrels of oil a day and is still cleaning up. We are pleased to see initial production results from these 4 wells have exceeded our expectations.

[Randy Broaddrick:]

Thank you, Paul. It was discovered after our 10-K was published yesterday that a typo occurred in the conversion of our 10-K for filing. The typo is that the earnings or loss per share for 2020 was presented without the parentheses denoting it as a loss. We will be filing a 10-K/A as soon as practical to correct this typo. For the fourth quarter of 2020, we generated revenues of $31.4 million and recorded a net loss of $160.3 million or a $1.83 loss per diluted share. Included in the loss were pretax items including $129.6 million for a ceiling test impairment due to the reduction in the value of reserves from lower oil and gas pricing, $15.2 million for unrealized losses on hedges as a result of the changes in oil price and $2.8 million for share-based compensation expense. Without these items, after the effect of income taxes on the adjusted items and adjusting for a valuation allowance of $50.6 million, our net income would have been approximately $6.5 million or a $0.07 gain per diluted share.

[Paul McKinney:]

Thank you, Randy. On our third quarter earnings call, I discussed in detail Ring's competitive strengths as well as the challenges we face and how we were addressing them. A lot has changed over the past 4 months since we last spoke, mostly for the better. However, I want to talk a little about the severe winter storm that affected most of the energy industry here in Texas and, more specifically, how it affected our production. We incurred a considerable hit on our production in February, down more than 60% for the majority of the storm. We had an unusual amount of downtime that took us 2 weeks or more to restore. Our first quarter production will be less than what we were originally predicting as a result of this downtime. However, we have restored our production, and with the performance of our new wells and the continued improvements we are seeing in our other initiatives, we will still generate free cash flow for a sixth straight quarter, we will still pay down debt, and we are not going to change our full year guidance.

[Operator:]

And the first question will come from Jeffrey Campbell with Alliance Global Partners.

[Jeffrey Campbell:]

My first question is regarding the Delaware Basin asset sale. I was wondering if you see 2021 as a more supportive sales environment than last year generally, and if anything might be different in how the sale is conducted or valued this year.

[Paul McKinney:]

Yes. Good question. Yes, 2021 is a better year. If you recall, we entered the pandemic -- we actually signed a purchase and sale agreement in April of 2020, which probably was right in that peak of the downturn. And so yes, we believe that the prices are better this year. We have also made investments out there to stabilize production, and also we've done a better job of looking at and actually separating out our facilities that are associated with our production and in those portions of our facilities that could be used for commercial saltwater disposal. And so we think that we can get really good value for our assets, and so we're looking forward to doing so this year.

[Jeffrey Campbell:]

Okay. Great. I appreciate that. And digging into the M&A a little bit without asking for any secret sauce, so wondered if you could give us some broad gating items with regard to M&A, both on the sort of assets that you desire and any financing variables.

[Paul McKinney:]

Yes. Very good. I'll address the financing first because that's the obvious thing. Yes, we've got a challenging balance sheet, okay? And so with the debt load that we have, we would like to use equity where we can. We would like to emerge from any kind of a transaction with -- making further progress. We're strengthen our balance sheet, and we think that we can do that. We believe now that prices have come back up to a more reasonable level, there are more sellers out there, if you want to call them that. There are more sellers willing to sell at these prices, whereas at the -- if you look back at -- in November, December of last year when prices were still pretty low, really, nobody wanted to sell their assets at $40 oil. Now getting back to the portion of your question associated with what type of assets, well, we really like the area that we're in. We really like the economics of the projects that we have in our own inventory. And so yes, ideally, we would like to spread our very effective operating team over more wells and more barrels of production in the areas that we operate. So the synergies is an obvious thing. And so -- however, I'm not going to tell you that we would only buy assets in and around where we currently operate. But I will say that if we do venture outside of the Central Basin platform, the Southern Shelf, it'll be because the attributes of the acquisition bring with them similar attributes of shallow declines, high margins, undeveloped opportunity, have low breakeven costs and short payouts and that type of thing. And probably primarily oil as well.

[Operator:]

And the next question comes from Dun McIntosh with Johnson Rice.

[Dun McIntosh:]

Appreciate the color on the winter storm. So I was wondering if we could dig in a little more kind of on the '21 program and how you kind of see that playing out. What's the 10 to 12 completions and the timing of those over the course of the year? And I would assume that the 4 wells drilled in January -- or December and January, that's baked into this 10 to 12. Is that right?

[Paul McKinney:]

That is correct. Yes, 2 wells were drilled in December, and -- but they were completed in 2021.

[Dun McIntosh:]

Okay. And then over the remainder of the year, so I guess that leaves about, call it, 6 to 8 or so for the remainder of the year. Should that be pretty weighted kind of second, third, fourth quarter? Or is -- or should you kind of knock those out and then reevaluate the program as you get towards the end of the year?

[Paul McKinney:]

Well, we're being forced to kind of reevaluate things on a daily basis with the product prices being what they are at higher levels today than anybody was predicting just a couple of months ago. We were originally thinking that we were going to pick up a drilling rig to start our next campaign sometime in the summer. But because of the prices being what they are, we're actually thinking about accelerating our drilling program a little bit. So don't be surprised if we start drilling in the second quarter.

[Dun McIntosh:]

Okay. And then I guess just to clarify and then I'll listen, but when you talked about adding that second rig in the summer, would that be included in the $40 million to $48 million of CapEx that you're talking about for the year?

[Paul McKinney:]

Yes, it would.

[Operator:]

And the next question will come from Noel Parks with Touhy Brothers.

[Noel Parks:]

Just a couple of things. The well that you gave results for in the release, the Badger 709 B 6XH, was that one of the 1.5 miles length laterals? Or is that one of the regular length laterals?

[Paul McKinney:]

It's a 1.5 miles lateral.

[Noel Parks:]

Okay. Great. And for the -- a couple of years into the Eastern Shelf acquisition and everything. I'm just curious, what's sort of the longest production history you have now at this Eastern Shelf, not the Northwest Shelf? Longest production history you have with the wells there so far? And just how much does the -- would the lateral length help the economics of the well? I think the curves you've had in past presentations have been out of a 1-mile lateral assumption.

[Paul McKinney:]

You want to take that, Alex? This is Alex Dyes, our Executive Vice President of Engineering and Corporate strategy.

[Alex Dyes:]

Sure. So in our presentation before the -- it's just normalized to a 1-mile lateral. So you would just move it -- multiply it up to get to the 1.5 miles. And what was the first part of that question? I didn't quite catch that.

[Noel Parks:]

Just asking about production history now and just where -- maybe where your type curves might be headed?

[Alex Dyes:]

Sure. So a lot of the first production history, I mean, the original operator there drilled wells in 2016, and other operators within the area had started drilling in '15, so there's quite a bit of production history for those wells. And as far as the 1.5-miles well, it's beneficial to get an extra 0.5 mile because you already have the location set up and you get that extra completion from that. So maybe, Marinos, you want to elaborate a little bit more?

[Marinos Baghdati:]

Yes. The incremental cost of the 1.5-miles lateral are 25% compared to the 1-mile lateral. So with that and the increased EUR that we get, it's beneficial to drill the 1.5-miles laterals when we can.

[Paul McKinney:]

Yes. Based on all of my observations, the 1.5-miles wells have demonstrated, not only with this team but also with some of the other operators in the area, to be beneficial. So everybody tries to -- as long as they have the equity position, to drill the 1.5 miles, it's been beneficial. So you see it not so much as in IPs, but you do see it considerably in terms of the EURs and the ultimate economics of the wells.

[Operator:]

The next question will be from Richard Tullis with Capital One.

[Richard Tullis:]

Just one quick question, Paul, for clarification. So you're not currently running a rig but would possibly pick one up in the second quarter to continue with the drilling program and then drop that rig, depending on pricing after you get to the 6 to 8 wells for the year and then consider what you would do for the rest of the year. Is that the proper way to look at it?

[Paul McKinney:]

That is the proper way to look at it.

[Operator:]

And the next question will come from , Private Investor.

[Unidentified Analyst:]

A question on the focus on the balance sheet and the debt reduction, and I understand the sensitivity of that and am all for it. From the standpoint of an internal target that you're saying to yourself, "I need to get down to this level to be comfortable where the usage of cash flow going forward from that level is to maximize growth," once you reach that balance in the balance sheet, that gives you great comfort. Just curious if you've identified that number.

[Paul McKinney:]

Well, I've said in the past, Mike, that I'd prefer to be at or below 1x debt-to-EBITDA. I will say, though, if prices continue to remain strong or if some of the pundits out there who have some pretty optimistic forecasts for oil prices going off in the future, if we actually come close to some of those forecasts, as we get to 2.5x debt-to-EBITDA or below, I'm going to be tempted to pour on the capital to take advantage of those higher prices. And I think that would be the right thing to do for our shareholders because we have the inventory to really deliver some significant growth.

[Unidentified Analyst:]

Yes. I'm in total agreement with that. And one last question. When we talk about the new wells are coming on stream, the easy math for people that aren't in the business, each new well on an annualized basis would produce between $5 million and $7 million of gross revenues. Is that a fair number?

[Paul McKinney:]

I'd have to go back and check that number.

[Alex Dyes:]

So this is Alex. Yes, it also depends on prices. And then your LOE in different areas have different LOEs. So it's not easy -- a very easy answer. So I would say we'd probably take that offline.

[Unidentified Analyst:]

Okay. It was just a curiosity question because it appeared to be, again, as a nonoil guy, you take so many days times barrels produced times the current market value and you kind of get to a number. And it would appear that you'd be looking at $30 million or $40 million in additional revenues when you start talking about 8 wells, and it was just an interesting number.

[Paul McKinney:]

Michael, we'll get back with you on that.

[Operator:]

And the next question is a follow-up from Jeffrey Campbell with Alliance Global Partners.

[Jeffrey Campbell:]

Great. Thanks for letting me back in. I was just wondering, do you have a forecast for how many more of the ESP-derived pump conversions are on tap for '21? And is this a fairly ratable program over the next several years?

[Paul McKinney:]

Yes. I'll tell you what, I'm going to turn that question over to our Executive Vice President of Operations, Marinos Baghdati.

[Marinos Baghdati:]

Yes, sir. We currently have 92 wells that are on ESP, excluding the new wells. We anticipate, based on our failure frequencies and the forecast that we have, that we'll have 36 conversions to rod pump by the end of this year. There's 20 to 30 wells that will -- probably won't be converted to rod pump throughout their life because of their high water volumes. So after 2022, with an additional 30 to 35 rod pump conversions in 2022, we'll be at a point where all the wells that need to be converted to rod pump are done. And at that point, it'll just be the new wells that we drill, once they get to that point, that they'll be converted.

[Operator:]

Ladies and gentlemen, this concludes our question-and-answer session. I would like to turn the conference back over to Paul McKinney for any closing remarks.

[Paul McKinney:]

Very good. Thank you, Chad, and thank all of you for your interest in Ring. We are really excited about what the future holds for Ring Energy and our shareholders. We are actively working every single day trying to put the best dollars that we have to the best uses. And we think that 2021 is really going to end up with a really good year, and we look forward to 2021 and beyond. So -- and I'd like to, again, thank you one last time, and we will talk again on the next call.

[Operator:]

And thank you, sir. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.