Ring Energy Inc (REI) 2020 Q4 法說會逐字稿

Good morning, and welcome to the Ring Energy Fourth Quarter 2020 Earnings Conference Call. (Operator Instructions) 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.

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. (Operator Instructions)

During the course of this conference call, the company will be making forward-looking statements. Investors are cautioned that forward-looking statements are not guarantees of future performance, and that actual results or developments may differ materially from those projected in the forward-looking statements. Ring Energy disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in yesterday's press release and in the reports filed with the Securities and Exchange Commission. As a reminder, this conference call is being recorded.

I would like now to turn the call over to Paul McKinney, our Chairman and CEO.

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.

Now let's take a look at the full year 2020. Our average sales were 8,790 barrels of oil equivalent per day, of which 87% was oil. We performed 29 CTRs, including 17 in the Northwest Shelf and 12 in the Central Basin Platform. Our continuing targeted CTR workover and reactivation programs, combined with our ongoing cost optimization initiatives, contributed to a lifting cost of $10.52 per BOE, an 8% decrease year-over-year. We generated $86 million of adjusted EBITDA that contributed to $40 million of free cash flow, which we used to help pay down $75 million of bank debt during 2020.

Turning to our year-end 2020 reserves and based on SEC reserve prices -- yes, SEC average prices of $36.04 per BOE or barrels of oil and $1.99 per MMBtu of natural gas, we reported year-end 2020 proved reserves of 76.5 million barrels of oil equivalent, which was down modestly from our 81.1 million barrels of oil equivalent we had at the year-end 2019. For comparison, SEC average prices in 2019 were $52.19 per barrel of crude oil and $2.58 per MMBtu of natural gas.

During 2020, we recorded net upward revisions of 1.3 million barrels of oil equivalent primarily related to additions, improved well performance and technical revisions that were offset by reductions of 2.7 million barrels of oil equivalent due to lower commodity prices and 3.2 million barrels of oil equivalent of production. Our SEC proved reserves were comprised of 87% crude oil and 13% natural gas, with 57.5% of total proved reserves classified as proved developed, and the remaining 42.5% as proved undeveloped. Our reserve life ratio based on year-end 2020 SEC proved reserves and 2020 production was 23.8 years. The PV10 of our year-end 2020 SEC proved reserves, taken from our standard measure of future cash flows, was $556 million, which was down 40% from the $923 million at the end of 2019 primarily due to lower prices.

With these operational financial results, we are carrying forward a strong momentum into 2021 where we believe we will have even a better year. With that, I will now turn the call over to Randy to discuss our financials in more detail.

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.

For the full year 2020, we generated revenues of $113 million and reported a net loss of $253.4 million or a loss per diluted share of $3.48. Included in the loss were pretax items including $277.5 million for ceiling test impairment, $5.4 million for share-based compensation expense and $1.2 million for unrealized losses on hedges as a result of the changes in oil price. Without these items, after the effect of income taxes on the adjusted items and adjusting for the $50.6 million valuation allowance, our net income would have been approximately $20.7 million or a gain of $0.28 per diluted share.

During the fourth quarter of 2020, we had $20.5 million in cash flow from operations and $7.8 million in capital expenditures for post-CapEx positive cash flow, or free cash flow, of $12.7 million. For the full year 2020, we had $69.7 million in cash flow from operations, $30 million in capital expenditures, which resulted in free cash flow of $39.7 million.

For the 3 months ended December 31, 2020, we had oil sales of 734,548 barrels and gas sales of 730,337 Mcf for a total of 856,271 BOE. Our received prices were $40.48 per barrel of oil, $2.21 per Mcf of gas, for an average of $36.61 per BOE. The differential between our oil price received and a weighted average NYMEX WTI averaged approximately $2 per barrel for the fourth quarter of 2020. For the full year 2020, we had oil sales of 2,801,528 barrels and gas sales of 2,494,502 Mcf for a total of 3,217,278 BOE. Our received prices were $38.95 per barrel of oil, $1.57 per Mcf of gas for an average of $35.13 per BOE. The differential between our oil price received and a weighted average NYMEX WTI averaged approximately $2 per barrel for the -- yes, per barrel for the full year 2020.

For detailed discussions of our various income statement line items, please refer to our earnings release and 10-K that was filed yesterday. I'm happy to answer any questions on them during our Q&.

A. As Paul discussed, we were pleased to generate free cash flow once again during the fourth quarter of 2020, our fifth consecutive quarterly period. During 2020, we paid down $75 million on our credit facility, and we will continue to use much of our free cash flow for that purpose. Paul will discuss in more detail in his closing comments, but with the recently initiated targeted drilling program, we are in a stronger position to pay down debt even faster given the high rates of return afforded by our deep inventory of drilling prospects. As we previously announced, in December, we completed our fall bank redetermination, and our borrowing base was set at $350 million. As of December 31, we had $313 million drawn on our credit facility, which resulted in liquidity of $40.6 million, including $37 million available on the revolver and $3.6 million of cash and cash equivalents.

Finally, we are affirming the full year 2021 outlook we provided on February 22, including year-over-year average sales growth between 2% and 8%, which equates to 9,000 to 9,500 BOE per day with approximately 85% to 87% oil. For full year 2021, we anticipate an average -- sorry, yes, 2021, we anticipate an average lifting cost of $0.10 to $10.50 per BOE, which reflects a decrease compared to full year 2020 lifting cost of $10.52 per BOE.

Turning to our 2021 capital investment program, we plan to drill 6 to 8 wells and complete 8 to 10 wells during the full year 2021. We are targeting total capital spending of $44 million to $48 million, with all expenditures to be funded by cash on hand and cash from operations. In addition to company-directed drilling and completion activities, our capital spending outlook includes targeted well reactivations, workovers, infrastructure upgrades and continuing our successful CTR program in the Northwest Shelf and Central Basin Platform areas. Also included is anticipated spending for leasing, contractual drilling obligations and nonoperated drilling, completion and capital workovers.

Our 2021 capital program has been designed to sustain or minimally grow our production and reserve levels and have returns sufficient to generate free cash flow to further reduce debt. Our existing commodity hedges were implemented when prices were lower last year to ensure the necessary cash flow to adhere to these plans.

So with that, I will turn it back to Paul.

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.

The next thing I want to discuss is our new strategic vision. We are committed to key principles that we are squarely focused on: ensuring health, safety and environmental excellence and a strong commitment to our employees and the communities in which we work and operate; continuing to generate free cash flow to improve and build a sustainable financial foundation; pursuing rigorous capital discipline focused on our highest-returning opportunities; improving margins and driving value by continuously targeting additional operating cost reductions and capital efficiencies; and strengthening our balance sheet by steadily paying down debt, divesting of noncore assets and becoming a peer leader in debt-to-EBITDA metrics. These key principles will continue to guide us, and we are committed to them by pursuing the following 5 strategic objectives: first, we will attract and retain the best people, knowing that our future success can only be achieved through our employees. Second, we will pursue operational excellence with a sense of urgency. This objective is a foundation that will define our culture and future success.

So what does that mean exactly? We will execute our operations in a safe and environmentally responsible manner, apply advanced technologies and continuously seek ways to reduce our operating cash cost on a per-barrel basis. We plan to deliver low-cost, consistent and efficient execution of our drilling campaigns, our work programs and other operations, all with a high sense of urgency.

An example of this is our highly successful CTR program, which reduces operating expenses and lessens costly workovers. The impact from this program can be seen in the decrease in our lifting cost per BOE from $11.42 in 2019 to $10.52 in 2020. Our confidence in this aspect of our culture is reflected in our forecast of continuing to lower cost this year from anywhere from $0.10 to $10.50 per BOE.

And yet another example is we relocated our headquarters to the Woodlands and downsized the Midland office, closed our Andrews field office, are in the process of closing the Tulsa office, reducing leasing expenses and resulting in meaningful annual cost savings. But the biggest impact of this change is not the cost savings, it is the consolidation of the executive and management teams, allowing for improved communication, strategizing, execution and continuing to build our culture.

Moving on to the third strategic objective is to prioritize our work programs and invest in only the highest risk-adjusted rate of return projects in our inventory. This will allow us to profitably grow our production and reserve levels and generate the excess free cash flow we need to pay down debt. We have already discussed our CTR program and our Northwest Shelf drilling program, but both of these demonstrate our commitment to generate as much free cash flow as we can from every dollar we spend. As you know, we drilled 4 Northwest Shelf San Andres horizontal oil wells in December and January, including 3 1.5-mile horizontal wells and 1 1-mile horizontal well. All wells are now completed and producing at various stages of cleanup. Early production results have been at or above expectations, and we look forward to completing the full program over the next few months.

Moving on to the fourth strategic objective, which is the -- which is to focus on generating free cash flow and strengthening our balance sheet by reducing debt. We intend to do this through the use of excess cash from operations and potentially through the proceeds from the sale of noncore assets. Last month, we announced our plan to launch a sales process to divest of our Delaware Basin assets during the second quarter of this year, we are still committed to that plan. Remaining focused and disciplined in this regard will lead to meaningful returns for our shareholders and also provides additional financial flexibility to manage commodity price cycles in the future.

And moving on to our fifth and final strategic objective is to pursue strategic acquisitions that maintain or reduce our breakeven cost. We will focus on accretive acquisitions, mergers and dispositions that not only improve our breakeven cost but improve our margins, lower our operating costs and are accretive on a cash flow basis. Our financial strategies associated with these efforts will focus on delivering competitive risk- and debt-adjusted per share returns for our shareholders.

I want to end my prepared comments by, once again, thanking the entire team of Ring employees for their continued hard work and dedication. The past year has clearly been the most challenging in modern times on a global scale, and especially for the oil and gas industry. While I have only been in the company for a little over 5 months, I have quickly come to appreciate the collective determination and dedication of Ring's employees at all levels of the organization. As important, I appreciate the way they have so quickly embraced our new strategic vision, which is evident in our operational and financial results as a direct result of their actions. I look forward to continuing to work closely with our team as we strive to take the company to new heights and further increase shareholder value.

And so with that, I would like to turn it over to our operator to moderate the Q&A session of this call.

(Operator Instructions) And the first question will come from Jeffrey Campbell with Alliance Global Partners.

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.

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.

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.

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.

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

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?

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

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?

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.

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?

Yes, it would.

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

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?

It's a 1.5 miles lateral.

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.

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

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.

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

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?

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.

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

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?

That is the proper way to look at it.

And the next question will come from [Michael Bloomfield], private investor.

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.

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.

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?

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

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.

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.

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

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

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?

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

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.

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.

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