Ring Energy Inc (REI) 2021 Q2 法說會逐字稿

Good day, and welcome to the Ring Energy's Second Quarter 2021 Earnings Conference Call. (Operator Instructions) Please note, this event is being recorded. I would now like to turn the conference over to Al Petrie, Investor Relations. Please go ahead.

Thank you, Matt, and good morning, everyone. We appreciate you taking the time to join us today and for your interest in Ring Energy. We'll begin our call with comments from Paul McKinney, Chairman of the Board and CEO, who will provide an overview of key matters for the second quarter. We will then turn the call over to Travis Thomas, our Chief Financial Officer, who will review our detailed financial results. Paul will then discuss our future plans and outlook. Also joining us on the call today and available for the Q&A session are Alex Dyes, Executive Vice President of Engineering and Corporate strategy; Marinos Baghdati, Executive Vice President of Operations; and Steve Brooks, Executive VP of Land, Legal, Human Resources and Marketing.

During the Q&A session, we ask you to limit your questions to one and a follow-up. You're welcome to reenter the queue later with additional questions. 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 those 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 the reports filed with the SEC.

As a reminder, this conference is being recorded. I would now like to turn the call over to Paul McKinney, our Chairman and CEO.

Thank you, Al. I want to welcome everyone to our second quarter 2021 earnings call. We are pleased with the overall results for the second quarter. This makes our 7th consecutive quarter of generating free cash flow that we partially utilized to further pay down debt. Looking at our results in more detail. During the second quarter of 2021, we sold 792,551 barrels of oil equivalent or 8,709 barrels of oil equivalent per day, which was an 11% increase from this year's first quarter sales of 716,422 barrels of oil equivalent or 7,960 Boe per day. Contributing to the higher production was the success of our Northwest Shelf Phase I and Phase II drilling programs.

As a result -- and as we discussed on our last earnings call, our 4-well Phase I program came in on schedule and within budget and collective production results continue to meet or exceed our original expectations. During the second quarter, collectively, the 4-wells produced 101,800 gross barrels of oil equivalent or approximately 280 Boe per day per well. Also during the second quarter, we drilled, completed and placed on production, all 3 Phase II wells. Similar to Phase I, the Phase II wells came in on schedule and within budget and with all 3 wells brought online by June 3. The collective production results from the Phase II wells have also met or exceeded our original estimates, including total production from the 3 wells of 22,700 gross barrels of oil equivalent or approximately 270 barrels of oil equivalent per day per well for the last 28 days of June.

If you recall, on our first quarter conference call, we expected a significant increase in second quarter sales volumes, given the ongoing success of our development programs and the anticipated restoration of natural gas sales disrupted by the severe winter storm in February. While second quarter sales volumes did increase 11% from the first quarter, they were lower than anticipated, primarily due to continuing downtime from these third-party processing facilities in the Central Basin Platform that negatively affected natural gas sales. Additionally, we incurred pipeline capacity constraints during the quarter in the Northwest Shelf that further impacted our natural gas sands.

In late May and early June, we also experienced lightning strike-related damage to several of our facilities that impacted oil sales for the period, with repairs completed and the wells brought back online by mid-July. As you know, natural gas is a minor component of our total sales revenue. Although these reduced natural gas sales impacted our total sales volumes on a Boe basis, they had a relatively minor impact on EBITDA for the quarter. With respect to sales revenue, we benefited from higher crude pricing during the period, which when combined with the 11% increase in crude oil sales, contributed to the overall 21% increase in revenues over the first quarter.

The combined impact from these items as well as our ongoing cost reduction initiatives resulted in second quarter 2021 adjusted EBITDA of $20.6 million and $5.6 million of free cash flow. We utilized a large portion of our free cash flow during the quarter to pay down $5 million of bank debt and ended the period with approximately $51 million of liquidity, a 13% increase from the end of the first quarter. When considering the first half of 2021, we generated $39.6 million in adjusted EBITDA, $8.6 million of free cash flow and reduced the borrowings on our revolver by $12.5 million.

In response to the higher crude oil pricing environment, yesterday, we announced an increase to our original drilling plans. We picked up 2 rigs last week and initiated the drilling of the first 2 wells of a 4-well Phase III drilling program. We have a 100% working interest in all of these wells. Our current plan is to follow-up the Phase III wells with a 1 rig Phase IV program to drill an additional 2 or more wells beginning early in the fourth quarter. The wells in the Northwest Shelf are planned to be 1-mile laterals, while the ones in the Central Basin Platform are planned to be 1.5-mile laterals. We anticipate the payback on invested capital for these wells to be 1 year or less, given the current price environment. Although the anticipated production will not have a meaningful impact on 2021 production volumes, keep in mind that if the current price environment continues, these new volumes will place us in a very strong position as we enter 2022.

With that, I will turn the call over to Travis Thomas to discuss our financials in more detail. I'll then come back and make a few closing remarks. Travis?

Thanks, Paul. For the second quarter of 2021, we generated revenues of $47.8 million and recorded a net loss of $15.9 million or a loss of $0.16 per share. Included in the loss were pretax items, including $22.8 million of non-cash unrealized losses on hedges as a result in the change of -- in oil price and approximately $350,000 of share-based compensation expense. Excluding these items, our adjusted net income was $7.3 million or $0.07 per share. During the second quarter of 2021, we had $17.1 million in cash flow from operations, $11.5 million in capital expenditures. The combined result was positive free cash flow of $5.6 million.

For the 3 months ended June 30, 2021, we had oil sales of 702,408 barrels and gas sales of 540,857 Mcf for a total of 792,551 Boe. Our second quarter of 2021 realized pricing was $65 per barrel of oil and $3.90 per Mcf of natural gas for an average of $6.26 per Boe. The differential between our average oil price received and NYMEX WTI was a negative $0.99 per barrel for the second quarter of '21 compared to our average first quarter differential of a negative $0.37 per barrel. For detailed discussions of our other income statement line items, please refer to our earnings release and 10-Q that was filed yesterday. Of course, I will be happy to answer any questions you may have during today's Q&A session.

As Paul discussed, we are pleased to generate free cash flow once again during the second quarter of 2021 and further paying down debt by $5 million. Moving forward, we will continue to use much of our free cash flow for this purpose with the level of free cash flow and the cadence of debt pay down, primarily driven by the timing of capital spending and market conditions. As of June 30, 2021, we had $300.5 million drawn on our revolving credit facility and liquidity of $51.4 million, including $48.7 million available on the revolver and $2.7 million of cash.

Turning to our outlook for the remainder of this year. We expect second half 2021 sales of 8,700 to 9,200 Boe per day, including 7,700 to 8,100 barrels of oil per day. Assuming the successful completion and timing of the Phase III and Phase IV drilling program, we expect to exit 2021 with sales volumes in excess of the high end of our second half guidance. We expect an average lifting cost for the second half of 2021 of $10.50 to $11 per Boe. Lifting costs include lease operating expenses and gathering, transportation and processing costs.

Turning to our 2021 capital investment program. Including the 6 to 8 Phase III and Phase IV wells we announced yesterday, we expect a total capital spending of $30 million to $35 million for the second half of this year, with all expenditures 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 costs, contractual drilling obligations and non-operated drilling completion and capital workovers. Our second half 2021 capital program has been designed to sustain or minimally grow our production and reserve levels, have sufficient return -- have returns sufficient to generate free cash flow to further reduce debt and allow us to enter 2022 in a stronger position.

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

Thank you, Travis. Over the last 7 quarters, we have generated more than $50 million in free cash flow that has helped us pay down debt and continue our drilling program. The result has been a meaningful strengthening of our balance sheet and market position. Although we may not cash flow every quarter, we will, on an annual basis and remain focused on becoming a peer leader in debt-to-EBITDA metrics. Regarding our ongoing process to sell our Delaware assets, we have seen significant interest from a number of parties and are hopeful that we will have more details to announce once we enter a definitive sales agreement.

Regarding our pursuit of strategic acquisitions. And as I shared with you in detail on the last earnings call, we promised to demonstrate 2 essential things in this regard. First, a potential transaction will need to bring in sufficient production revenue and cash flow to improve our leverage ratio, thereby strengthening our balance sheet. Second, the transaction metrics will need to be accretive to our existing shareholders. So the bottom line is this. We will not acquire assets using equity unless it meets these 2 tests. And over the last several months, we have been screening the opportunities in the marketplace to ensure we meet these criteria.

With that, I would like to turn it over to our operator for questions. Matt, it's all yours.

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

I'll let myself to a couple of questions on the Phase III and the Phase IV drilling. The first one is, can you provide some color on the well lengths and any anticipated well cost inflation? And here, I'm thinking about -- we've been hearing about increased steel costs throughout a host of industries during this earnings cycle.

Yes, Jeff, those are good questions. And I'll tell you what, I'm going to let Marinos take that.

The Northwest Shelf Phase III and Phase IV wells are forecast are going to be 1-mile lateral or planned to be 1-mile laterals and then the CBP wells are planned to be 1.5-mile laterals. In terms of costs, we've seen cost increases, just like the rest of the industry of the range of 10% to 20% on all the quotes we received for the AFEs and the preparation for the drilling program. Primarily, the costs have been in casing and tubulars as well as some other service costs, but the major cost increase has been casing and tubular.

And I'd like to add to that. This is Alex Dyes. We have a presentation we posted along with our earnings this time. And the range of increase in costs are still well within the guidelines that we put in that presentation. So if you want to reference more on what amount -- well cost and amount of 1.5 half well costs, you can see it there.

Great. Yes, I do have the presentation. And my follow-up question is on the 3 and the 4. First of all, should we expect that all the 4 Phase III wells are going to be completed in 2021? Will the fourth quarter Phase IV wells likely be completed in the first quarter of '22 or whenever you want to identify? And finally, bearing in mind the rapid paybacks on these wells that you identified, do you intend to protect these returns with hedges?

I'll take the timing question there. The Phase III wells are expected based on our current frac dates to be online by the end of the third quarter. And the Phase IV wells are expected to be online late in the fourth quarter, contingent on us being able to maintain the frac dates we've secured already. In regards to the hedges, I'll turn it over to Paul.

Yes. I'll take the hedges. Yes. So Jeff, although we currently have -- do not have any additional hedging requirements going into 2022, hedging will always be a significant component of our future plans. And yes, we will be protecting our future cash flows, our ability to pay down debt. But at the same time, in a heavily backward dated environment like this, we also are seeking to employ more of an opportunistic hedging strategy to capture the upside for our shareholders as well. But -- and so we'll share more details as we layer those hedges in going into the new year.

Our next question will come from Neal Dingmann with Truist.

For now, Paul, my first question. Yes, just looking at the prepared remarks that you've mentioned here and then the release, could you talk about kind of building on the last question as well, how you think about balancing the debt repayment and production growth, especially, as Jeff was saying, the -- I love the, of course, the less than 1 year payback? Really, I think, provides some nice optionality to take a look at both. So again, glad you guys added a couple of rigs and just wondering, now that you've done that, just in broader terms, how you think about balancing the debt repayment with a bit of this growth?

Yes, Neal, good question. And so -- and I think you pointed out the core of what this management team is committed to do. When we state that we are committed to becoming peer industry leaders and debt-to-EBITDA metrics, we're truly committed to that. I mean -- and so right now, during the time period when our balance sheet is as heavily levered as it is, we are going to continue to concentrate on reducing that leverage. And so the whole goal of our capital program is to maintain or slightly grow our production so that we can continue that debt pay down. As you know, and as we've discussed in the past, we believe that there's opportunities to divest of certain properties that we don't believe are core to our business to help accelerate that.

We're also trying to employ an acquisition strategy that could also help accelerate that. But as we continue to reduce that leverage ratio, we will divert more of our capital towards drilling to increase our production and provide the growth that we believe our shareholders also are looking for us to do. And so it's a balancing act right now. Until we get the leverage ratio into a stronger position, we'll continue to concentrate on that. But as we get that leverage ratio into a better position, you'll see that we'll start contributing more and more of our capital towards growth. Does that answer the question?

Yes, yes, absolutely. I think that combination makes a lot of sense. And as said, I really like the quick payback, quick cycle times years gives you guys some advantages to do that. And then just in the release, I mean I was reading last night, it sounds like you guys have the confidence and you guys hit on this a little bit earlier as well. On this production, I guess, could you talk about, now that you have these 2 rigs, I think the statement in there was you feel confident, you'd probably end the year. I'm just trying to get maybe a bit more color on this and that you're around the high side of that production guide or something. I'm just wanted to get -- no details, nothing specific for '22, but just how you're thinking about the ramp? Is it more -- would it be a hockey stick there at the end of the year? If these 2 rigs now have come in, how we should think about sort of leading into 2022?

Well, and that is, again, very observant. That is the plan. This year, we have -- early in the year and late last year, as you know, we put in these defensive hedges. And so the cash flows that our production stream can generate is limited to what those hedges allow outside of the production that we can exceed. But with respect to affecting this year's production, we know we can't affect this year's production too much. But the purpose really of this capital program coming in at the end of the year is to take advantage of the strong prices that we didn't anticipate earlier in the year. And the added benefit is it really puts us in a really strong positions as these hedges roll off going into the new year. And so yes, we're looking now towards 2022, and we're looking for ways to optimize our revenue generation and the EBITDA that hits the bottom line.

(Operator Instructions) Our next question will come from Noel Parks with Tuohy Brothers.

Just had a few things I wanted to run by you. So as far as you're getting back on -- out there drilling, that was something that in the last operations update you had suggested might be on the way. And I'm just curious about the decision to go ahead with 2 rigs instead of just running one steadily. Was that largely determined by -- you saw a good price out there for taking on both at the same time? Or I was wondering if you had thoughts around trying to sort of stagger the completion dates of the wells, maybe cluster them a little more tightly while we were in a good commodity price environment?

Well, there's a lot of the things that came into that decision. But I'll tell you what, I'm going to turn this back over to Marinos and he can address some of the logistical issues associated with our rigs.

After the Phase II wells, we wanted to monitor the wells before moving forward, make sure that we're getting the results we wanted to get. And in doing that, the pricing environment changed, and with that, the service availability. We're finding a hard time with not having a continuous program to schedule the frac dates, like you mentioned. And so we had a window of frac dates available in both the CBP and the Northwest Shelf around the same time, and thought that the most efficient way to get those executed was by employing 2 rigs rather than just 1 and taking a little bit longer. So that was the major decision for picking up 2 rigs. In Phase IV, we're going to go back to 1 rig because we think those frac dates we can stagger and plan now for those in the fourth quarter.

Does that answer your question?

It does. And the other thing I was looking at the production guidance for the second half. It did strike me relative to your sort of run rates from first half. It did strike me as a little bit conservative. I was just wondering if there was -- again, anything having to do with frac timing or anything in there that was making you just a little bit cautious in setting expectations for second half.

Well, if you remember in the first call that we had and we discussed the impact of the winter storm we endured in February. We told our shareholders that we thought that we can make up for that deferred production. At that time, we were not aware that the facilities that process our gas in the Central Basin Platform was going to continue to incur the issues that were created as a result of that winter storm. And so that gas production still has not been fully restored. And we've given up trying to predict when they will deliver on that steady and restored production. And so these estimates, I can see why you would believe that they look a little conservative, but we decided we can't continue to predict what other people are going to do. And so we decided to focus on the oil production that we knew that we had a good handle on. And so I hope we're surprised, but we're in the hands of other people.

I'd like to add something to that, that you hit on. In our original budget, with our forecast, our guidance, we had anticipated the last few wells of the 2021 drilling capital program to come online a lot sooner or a little bit sooner than what the current ones are coming on because of the frac dates that you mentioned. So that also impacts the guidance we're giving for the second half of the year a little bit as well.

Great. That definitely fills in the gap in what I was coming up with. And then just curious, among the factors involved in the additional activity and the timing and so forth that we've touched on. I was just wondering, was there much thought given specifically to the shape of the base decline curve with this extra activity? I guess I was thinking about heading into 2022, where you had the first half Phase I and II wells come on. And then originally, it sounded like you weren't going to be really getting a rig out there more until later in the year. So is that also in the mix of your thinking?

Yes, the timing of when we drill our wells will always have a big impact. So far, if you look at the forecast that we have internally for our oil production, we've been remarkably and surprisingly, in my opinion, accurate. So we've been really good in that regard. The biggest misses have so far been associated with the unanticipated downtime to these -- like we mentioned, the lightning strikes, but it's primarily in the gas. The declines of the wells are basically coming in as we have seen in the past. And so I don't know if that really answers your question.

Yes. No, it totally does. And just one other for me is, if I remember right, it seems that you have come a long way with the rod pump conversions. And so I guess, first, I'm assuming that you're sort of wrapping up the -- most of that inventory. And I was just curious if you could talk a little bit more about what other sort of workover or maybe recent completion or other rework that you might have on deck for the rest of the year.

Yes. I will say this. As long as we're drilling wells out here because all of the wells that we're drilling, we initially put in electrical submersible pumps. And so there will always be a CTR component of our going-forward program. We have, as you pointed out, made a lot of progress towards converting many of these electrical submersible pumps to rod pump. But we still do also retain a pretty sizable inventory. So we'll continue that program throughout this year and into next year. We do have ongoing workover opportunities that come along as well as approach the latter part of their life. We're fortunate in the Central Basin Platform. We have multiple horizons and recompletion opportunities and that kind of thing. But for this year and also next year, we will retain a pretty sizable component of our go-forward capital spend associated with the CTR program.

Yes, sir. And to add on to that, the Northwest Shelf currently has 22 of the 76 wells, the horizontal San Andres wells and Northwest Shelf are still on ESP. We expect those to reach a point where they will be converted to rod pump as well. And in CBP of the 114 wells that we have, 63 of those are still on ESP. The total fluid production in CBP is a little higher. So we don't expect all of those wells to be converted to rock pump at some point, but at least half of them will. So we still have a number of wells that are going to be under our CTR program in addition to the new wells that we drill over time.

Yes. And it's kind of interesting as we watch our operating costs, you get the full effect of these CTRs a couple of months after you get them converted over, where you're now starting to really see the reduction in electrical usage. And as you get into the repairs, these rod parts and rod repairs are so much less expensive than electrical submersible pumps. And so as time goes on, you're seeing meaningful impacts in the reduction of our operating costs. And so we've said that in the past, but I'll tell you what, we really enjoy seeing those operating costs come down quarter-over-quarter.

And Noel, this is Alex Dyes again. I will comment that on the slide deck that we attached to our earnings release, Slide 12 addresses a lot of the questions you had. So it shows a little bit of the historical failures and where we're going with the CTRs.

(Operator Instructions) Our next question is a follow-up from Jeffrey Campbell with Alliance Global Partners.

I just wanted to ask a quick M&A question. Bearing in mind your milestones for acquisitions, do you believe you're more likely to consummate an all-stock transaction or one that's a combination of stock and cash? And I ask that as I'm thinking about the potential optionality of the impending assets there.

Yes. And so there's a lot that could be said in that regard, Jeff. In the current environment, I think all of the owners of assets that are in the marketplace trying to sell their assets. We prefer cash, okay? We have seen and we -- an expression of interest from many or several different organizations that would be receptive to stock. But we -- I can't say that there is any one preference or another, potentially do an all-stock deal. Those are going to be more rare. I think a combination of stock and debt. But again, in that combination, that right combination, it will be a deleveraging and leverage ratio improving transaction.

And at the same time, when you look at the share usage, we will -- it will be an accretive deal with respect to the shareholders. Otherwise, we won't do it. And so that's a tall order right now because with the increase in oil prices that we've seen -- we've seen, in our opinion, anyway, a rapid increase in the competitiveness for these oil and gas assets that are hitting the street. And so people are now willing to sell, and there are now people willing to buy and is becoming more and more competitive. And so we're out there competing. We're evaluating. We're screening deals, but we're not losing sight of the 2 promises we've made to our shareholders.

As there are no more questions, this concludes our question-and-answer session. I would like to turn the conference back over to Mr. McKinney for any closing remarks.

Thank you, Matt. And all of you that are on the call, thank you for your time. Thank you for your interest in Ring Energy, and thank you for your trust. If you have any questions, you're more than welcome to follow-up and contact us. And Al Petrie is always available to take those calls and he transfers to send them on to us. So anyway, thanks again, and have a great rest of your day.

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