Riley Exploration Permian, Inc. (AMEX:REPX) Q4 2022 Earnings Call Transcript

Riley Exploration Permian, Inc. (AMEX:REPX) Q4 2022 Earnings Call Transcript March 9, 2023

Operator: Hello, and thank you for standing by. My name is Regina and I will be your conference operator today. At this time, I would like to welcome everyone to the Riley Exploration Permian Incorporated Fourth Quarter 2022 Earnings Conference Call. I would now like to turn the conference over to Philip Riley, CFO. Please go ahead.

Philip Riley: Thank you, and good morning to everyone. Welcome to our conference call covering the fourth quarter and full year 2022 results. Yesterday, the company published a number of items which can be found on our website under the Investors section, an earnings release, a 10-K, supplemental info and non-GAAP measures and two presentations. One presentation provides an update for fourth quarter and full year results, with the second providing an overview of our company’s story. Participating on the call today are Bobby Riley, Chairman and CEO; Kevin Riley, President, and myself, Philip Riley, CFO and EVP of Strategy. Today’s conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws.

These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. We will also reference certain non-GAAP measures, the reconciliations to the appropriate GAAP measures can be found and our supplemental disclosure on our website. I’ll now turn the call over to Bobby.

Bobby Riley: Thank you, Philip, and thank you again to everyone for joining us on today’s call. Yesterday, after the close of the market, we announced the results of our fourth quarter and full year 2022. I’m pleased to report that 2022 was another outstanding year for Riley Permian with performance continuing to be strong through the fourth quarter. Before we move on to the results, I’d like to take a moment to recognize the outstanding efforts of the entire REPX team. It is through their hard work, dedication and expertise that we are able to achieve the strong operational and financial results that we are reporting today. From our operations team who worked tirelessly to optimize production and reduce cost, to our finance and accounting teams who ensured that we remain financially disciplined and focused on delivering value to our shareholders, every member of the team played a critical role and our success.

Your commitment to excellence and your passion for our business is what makes Riley Permian such a great company and I’m honored to work alongside you. Now let’s turn to the results for the year. We have worked tirelessly throughout the year to optimize our core business and execute on a variety of growth initiatives. Most significantly, we recently announced that we have entered into a purchase and sell agreement to acquire oil and gas assets and Yeso trend of New Mexico. As we continue to work towards closing the acquisition, our team is already hard at work developing plans to integrate these assets into our existing operations, and we are confident that we can achieve a seamless transition that maximizes the potential of these underdeveloped assets.

We look forward to updating our shareholders on our progress as we move towards closing the transaction early in the second quarter. In 2022, Riley Permian delivered strong financial and operating results. To highlight just a few of the full year items, we increased our net oil production by 31% year-over- year to 8.8 MBbl per day and total net equivalent production by 25% year over year to 11.5 MBoe per day. We generated $176 million of adjusted EBITDAX, $170 million of operating cash flow from continuing operations and $56 million of free cash flow. We continue to invest in our business with total cash capital expenditures before acquisitions of $113 million, corresponding to a reinvestment rate of 66% of operating cash flow from continuing operations down from 88% in 2021.

We remain committed to returning value to our shareholders paying $25 million in dividends during the year, corresponding to 44% of free cash flow. We have now paid dividends for 16 consecutive quarters. Overall, we are proud of our financial and operating results in 2022 and believe they reflect the strength of our assets and the dedication of our team. We remain focused on creating long-term value for our shareholders and delivering sustainable growth for years to come. I will now turn the call over to Kevin to discuss operational results and give more details on the acquisition.

Kevin Riley: Thank you, Bobby, and good morning to everyone. I echo Bobby’s sentiment as we are proud of our team’s dedication and resilience, which enabled us to overcome inflationary pressures and shortages of material, equipment and labor to deliver outstanding results. Before we dive into our exciting new initiatives, I want to take a moment to highlight a few of the accomplishments we achieved in executing our plan during 2022. First, we maintained our momentum through the fourth quarter with production growing from 12.7 to 13.3 MBoe per day in the fourth quarter, representing a 4% increase quarter-over-quarter. On a full year basis, we grew our year-over-year average production from 9.2 to 11.5 MBoe per day, which is a 25% increase.

This growth was all achieved organically with the 15 gross, 11.8 net wells brought online during the year. In addition, our lease operating expenses were $8.8 million or $7.16 per BOE for the three months ended December 31 and $32.5 million or $7.73 per BOE for the year ended December 31. This represents a 5% decrease quarter-over-quarter and a 5% increase year-over-year. Regarding our EOR pilot, we continue to inject water in CO2 but are still early in the process of repressurizing the reservoir. Now let’s turn our attention to some of the exciting new initiatives we have planned for 2023 and beyond. On February 28, we announced we have entered into a purchase and sell agreement to acquire the oil and gas assets of Pecos Oil & Gas, LLC in Eddy County, New Mexico.

Photo by Ronan Furuta on Unsplash

These assets are focused on the development of the Yeso trend of the Northwest Shelf. The Yeso ASO trend and Riley Permian’s existing core assets focused on the St. Andrews. There are several similarities in geology, reservoir type and drilling completion and production techniques. Though this asset will boost Riley Permian’s production near-term, we believe this is an underdeveloped asset with extensive development potential allowing for value creation through the drill bid. In addition, acquiring the assets adds a new area to Riley’s operating footprint, diversifying the company’s portfolio and reducing single area concentration risk. Lastly, but no less important on March 2, we announced we have formed a joint venture that’ll own and operate on-site power generation for Yoakum County, Texas assets.

The first phase of the project will provide 10 megawatts of on-site power generation and is expected to be operational by June of 2023. We believe initiatives like this further differentiate us from our peers as it’ll not only provide us with more control over long-term energy cost, power supply and reliability, but also help us reduce carbon emissions by utilizing gas that may otherwise be flared to power operations. At this point, I’ll now turn the call over to Philip to review our financial results.

Philip Riley: Thank you, Kevin. For the quarter, total revenue net of derivative settlement losses was approximately $64 million to $7 million and 10% below the third quarter, driven primarily by 13% lower realized oil prices and partially offset by higher production and lower derivative settlements. Cash costs were approximately $3 million or 15% lower a quarter-over- quarter, despite higher volumes. On a per BOE basis, cash costs were 19% lower a quarter-over-quarter. The combination of these factors in turn drove a 12% decrease quarter-over-quarter and cash flow from operations before changes in working capital from $50 million to $44 million, which you can see visually in the chart on Slide 4 of our fourth quarter results presentation.

For the full year, our cash flow from operations before working capital increased 89% year-over-year from $89 million to $169 million. This is driven by a combination of higher volumes and price. Now I’ll offer some comments and capital allocation, referencing Slide 5, the same deck. First, we grew volumes materially more in 2022 than in 2021 while reinvesting a lower amount of cash flow. Very few companies out there grew more than low double-digits, and we grew by 30%. In 2022, we allocated two- thirds of cash flow to cash CapEx down materially from 88% and 2021. The lower reinvestment allowed us to allocate more to dividends in the balance sheet. Total dividends paid were up 22% versus 2021 and we paid debt down by 14% with a small increase in the fourth quarter for several large surface land positions we acquired.

Operating cash flow growth more than offset CapEx increases for net benefit, increased free cash flow of more than six year-over-year. Okay, let’s talk about forward guidance. In both the earnings release and the results update presentation. You’ll find summary tables of our guidance, including for both the first quarter and the full year. Our New Mexico acquisition is scheduled to close at the beginning of the second quarter, so the first quarter represents standalone legacy production and cash flows. We have a January 1 effective date with the acquisition, so the cash flows between Jan 1 and closing will represent a forecasted downward adjustment to purchase price. And then the acquisition production and cash flow is captured effectively for the second quarter through fourth quarter for 75% of the full year.

We’ve included a column at far right for illustrative pro forma at 100% contribution as if the acquisition hypothetically closed January 1. This offers you an idea of the run rate production metrics, so starting with oil production, you’ll see we’re guiding roughly 10,000 barrels a day for the first quarter flat with fourth quarter. We only brought online one well on the fourth quarter. We have a large amount of activity occurring now, but with wells coming on now and into the second quarter, so we a bigger bump to legacy production in the second quarter than declining modestly in the third or fourth quarters. But for the year, maybe it’s a bit over 10,000 barrels a day average, which would represent 15% year-over-year growth from the 8,800 barrels a day in 2022.

So some good organic growth before accounting for the acquisition. And then looking at the New Mexico acquisition production, we won’t take over the asset until second quarter and with just a modest delay there to get development started, second quarter production could decline just a bit. Then the growth would come in the third and fourth quarters following a mid-year development, hopefully exiting the year at a higher rate, but averaging overall for the year, something closer to the current level of a bit over 4,000 barrels a day. So combining the two legacy and acquisition, the development growth profiles in timing could complement each other well, comparing to 2022, we see full year 2023 total BOE production, but growing by more than 60% or on the illustrative pro forma run rate basis by nearly 80%.

Now, a few words on investing, for the legacy assets, it’s very much weighted to the first half of the year, even the first quarter with roughly 30% of total combined investment for 2023 occurring in the first quarter. This could lead to a modest amount of outspend on a free cash flow basis in the first quarter, but something we encourage you to look beyond for the full year view. This is a function of honoring some rig and other service commitments we’ve made to secure those offerings. For the year, we’ve got a fair amount allocated for gas and power infrastructure, not directly related to the power JV and investment in the EOR pilot, which was delayed from the fourth quarter. We forecast ramping the acquisition CapEx starting in the second and third quarters, and then separate from E&P CapEx were forecasting investing approximately $10 million to $15 million into our power JV, which could flex based on speed of development there.

For the full year, we’re seeing our overall reinvestment rate at least when compared to adjusted EBITDAX decline even further from last year, while still achieving this impressive volume growth. Lastly, a huge thank you to our team for another year of strong performance and for your efforts across the various new ventures and acquisitions we’ve been pursuing. Thank you to our Board and our shareholders for your continued support. I’ll turn it back to Bobby for closing comments.

Bobby Riley: Thank you, Philip. And again, thank you for your support. We remain focused on driving profitable growth and investing in our business for the long-term. Operator, you may now open it up for questions. Thank you all for joining us today.

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Q&A Session

Operator: Our first question will come from the line of Neal Dingmann with Truist Securities. Please go ahead.

Neal Dingmann: Good morning, all. Thanks for the time. My first question is on operations. It might be a little early for this, but just wanted to ask what your thoughts the Pecos assets look quite good to us. I’m just wondering, it looks like you talked to them about in early second quarter close. How quickly would those assets compete against others like you? I know Philip, you talked about sort of potential cadence going forward here for the first half for better part of this year, and I’m just wondering does that include some wells from the new assets immediately competing in there?

Kevin Riley: Yes, this is Kevin, Neal. So we do anticipate starting operations in mid-April. We are currently working with the operator and we will have a transition services agreement with to prepare for those operations to start, and with that we anticipate bringing on new production hopefully by early to mid-summer.

Neal Dingmann: Got it. Okay. That’s what I’d like to hear. And then Philip, just on that same vein just could you maybe hit on inflation costs, which you’re seeing today? Are things mitigating a bit or just €“ I’m sorry, Kevin, for you maybe, what are prices doing there on the upside, on the inflation side?

Kevin Riley: We started to see prices maybe start to come down a little bit. Nothing too material yet, but we do believe that adding this acquisition will give us some economies of scale that we can hopefully start to drive more efficiencies and bring costs down outside of other inflationary costs increases.

Neal Dingmann: Okay, good to hear. And then last I guess, one last one, just Philip, you didn’t say anything €“ I think you did a little bit last quarter call just on the CCUS. I know you are continuing to have some conversation just to €“ if you could give a little color, just anything potential going on, on that side.

Philip Riley: Yes, sure. So we put a comment there in both the earnings released and the presentation that we are working with partners in advancing a project for what we consider a large scaled storage hub in our region. We’re not giving too many details about that. But what I can say is, we’re working with people in the mix, working to do something that’s most efficient with our shareholders’ capital that includes using other people’s money. And frankly, we’re looking up and down the spectrum on both the capture and then the storage part, but obviously our area of core expertise is going to be the storage. So hopefully you can understand we’ve had a few other things going on, on some priorities, but that’s something that’s near and dear to our hearts and we’re working on it and we’re going to keep pushing forward there.

Neal Dingmann: No, just glad to hear it’s progressing along. Thank you all.

Operator: Your next question will come from the line of John White with ROTH MKM Capital. Please go ahead.

John White: Good morning and congratulations on the strong results. I wanted to follow-up on Neal’s question on the CO2 project. Are you at a point in any of the negotiations where you could point as to a potential timeframe for closing a deal with somebody or several parties?

Bobby Riley: Well, John, I appreciate the question. One of the counterparties we’re dealing with is a large slow moving organization that has a very large balance sheet without giving too much away there. And so we’re cognizant of the pace that they move at. The other thing is, the definition of what do you consider closing a scoping project versus an FID or such. So I’m hoping that we can share something with you here at least as far as certain applications and so forth, but we are getting the asset ready. We’ve taken certain moves to further, I guess the positioning. There’s different philosophies on how to sequence those different steps for all the different permits and needs there. We’ve done certain of those, and then I think we’ll be in better position to share more with you kind of mid-year.

John White: I understand the position you’re in and appreciate a little bit of additional detail. Thank you. On the CapEx split between New Mexico and Texas, it looks like you’ve carefully designed the program to do all €“ in first quarter all drilling will be in Yoakum County, and that’s of course to account for the closing date of the New Mexico deal. But I have to think it’s also to give your technical team some time to do further detailed work, subsurface work on the New Mexico assets. Is that correct?

Philip Riley: Yes, that’s a fair way to put it, John. As we said, it compliments each other there. The way those overlap and it’s kind of when I €“ why I went into that extended description of how they tie in there. And let me just give a little bit more color there. So, we’re not giving totally explicit or disaggregated CapEx, but if you look at it, on a legacy basis, we’re actually down year-over-year basically flat to a little bit down. And I challenge you to find many of the companies that are growing or forecasting to grow at the level we are with CapEx being down. Now, some of that is because last year was a little bit higher with more EOR pilot project spend. But either way that’s a bit lower. And then we’ve got a decent amount for the acquisition CapEx there, there’s a couple ways you can back into that, including from the data we gave you in the press release.

But that’s basically reinvesting about half of the EBITDAX we see there from that asset. Like I said, that’ll be more in the middle of the year with the way Kevin described that coming on by summer. But then for the overall year, we see the reinvestment rate declining yet again. Bobby described in his opening remarks and we’ve got there on our slides how our reinvestment rates cash flow went from 88% to 66%. We see that getting down even lower, so I think that’s pretty exciting. There’s been maybe a little bit of confusion. I recognize it’s hard to forecast the coming year before we even gave guidance and with an acquisition. But overall, we see that exciting for those dual components of the legacy CapEx being down and then the really efficient CapEx on the new acquisition.

John White: That’s great additional detail and thank you for it and I’ll respectfully decline to accept your challenge, because I know you know your numbers. Can you refresh me one last time on the completed well cost for the New Mexico asset?

Philip Riley:

John White: I’m sorry, the line’s breaking up.

Philip Riley: Currently the costs are between $5.3 and $5.86, which is mostly driven by the completed cost on that asset.

John White: All right. Thanks very much and I’ll pass it back to the operator.

Operator: Our next question will come from the line of Jeff Robertson with Water Tower Research. Please go ahead.

Jeff Robertson: Thank you. Good morning. On the Yeso assets, can you talk a little bit about any infrastructure issues that you’ll have to deal with as you start? Is Riley’s still on a plan?

Kevin Riley: horizontally, they’ve got 15 wells, so they have put in multiple disposals. They have approximately 70 miles of gathering line. There’s plenty of oil and natural gas infrastructure that’s currently in place. So outside of lane, just small lines that connect to new facilities or new pad sites, we don’t anticipate any large infrastructure CapEx in the foreseeable future.

Jeff Robertson: Kevin is there €“ are there any take €“ I couldn’t hear the first part of your response. Are there any takeaway constraints or anything like that that affects that area €“ or those the assets of that area?

Kevin Riley: No, there are not. I’m sorry about the connection, but we do not have any takeaway constraints at this point in that area.

Jeff Robertson: Okay. Are there

Philip Riley: Jeff, incremental €“ this is Philip. I’m sorry to interrupt. I just add to that, we’re excited. It’s actually a less remote area, this Eddy County area as we surely know than where we are in Yoakum. And so we have quite a few options actually more than one midstream provider, so that provides a little bit of competition and we like what we see out there with lots of different options.

Jeff Robertson: Okay. Philip, do you have some flexibility with the midstream contracts you will inherit to try to maximize €“ to do anything that might be able to maximize economics versus what the prior operators were doing?

Philip Riley: I think we do over the medium term, not immediately out of the gate. Yes is the short answer.

Jeff Robertson: Question on the power project that the first phase is due in, I think in middle of this year in June, the second phase late this year, early next. Can you talk about what impact that might have on either just your operating efficiency in Yoakum County and/or your operating costs?

Philip Riley: Yes. So at a high level, we are doing this first and foremost just to improve operational quality. What you may see from the public point of view may not be quite so visible, but we can assure you that it is meaningful to us behind. Power €“ we’ve got fluctuating power quality, dirty power that affects everything from line pressures to you’ve got something and you’ve got an outage and an ESP, electric submersible pump. If you lose it, it drops, it ends up being a costly workover. So it really ripples throughout the operations there. And we hope that improves just overall oil production, which at the end of the day, more than anything else, every barrel we can produce more makes the biggest impact to our business.

At the same time, the second tenant, I guess would be cost €“ controlling costs. I don’t know that we’re out of the gate is going to drop costs so much as what we see is hopefully controlling the cost increases going forward. Clearly, it’s been a very volatile time for natural gas pricing. And we’re in a lower environment €“ vastly lower environment now than we were last year. But on the margin, we certainly see volatility increasing or continuing. And then prices, we certainly say gas prices could be high again. We have an increasingly intermittent grid, but with gas price often influencing obviously power prices in our region. So on the whole, we’re hoping to kind of control those costs. We’ve got an increasing load with our continued growth out there with some compressors.

We’re going to be starting here in the spring with EOR project that increases the power load. And so overall we saw that as exciting opportunity. And then lastly, it’s very important to us to control the flaring and for the most part that’s out of our control based on midstream capacity. So where we could, we liked to be able to control that, and this is an exciting way to take that otherwise Flare Gas and create something useful with it.

Unidentified Analyst: So the power project will allow you to displace compressors in the field, which let ultimately kind of be positive from a cost standpoint?

Philip Riley: No, to clarify there, the power project will provide electrical power to the compressors that will run on electricity. And so just instead of necessarily pulling it from the grid, you’re pulling it from our onsite power generation. Now we will have backup capacity from the grid that we can pull to from and for overall operational redundancy.

Unidentified Analyst: Having the more reliable source of power, is there a greater premium on that aspect of operations as you move into the EOR project?

Philip Riley: I think that’s fair. Yes, in general, the overall load is increasing and I think that’s a fair way to put it. But for the most part, we have a large field, the pilot is one small part of it in a section and lots of different places that we need and use power.

Unidentified Analyst: Thank you.

Operator: Your next question will come from the line of David Dernick with Dernick Companies. Please go ahead.

Unidentified Analyst: Good morning guys, and congratulations on having quite a productive year and some real interesting projects coming up. I’ve got really three questions. One addresses if you could elaborate on the response you’re seeing so far on the water and CO2 injection? And then secondly, kind a little unrelated what is your €“ how do your hedge positions look like on oil going forward? And then thirdly, on the electric generation, I think that’s a wonderful project. Congratulations on that. I’m wondering if you’ll have any excess capacity to sell back into the grid? That’s it.

Philip Riley: All right. Thank you, David. Yes, sure. We can rip through these. So the first question on the EOR, what we’d say is we’re early in the life of repressurizing the reservoir. As you may be familiar, EOR projects are very long term in nature. It takes a lot to repressurize those. We’re producing from this field or from this section, including adjacent sections. And so you’ve got a little bit of a competition for the de-pressuring and repressing there. But that’s a longer-term deal and we will be sure to update you when we have something different to say there. Let’s see. The second question, I believe involves selling power back to the grid. We do have some flexibility there to take non-dedicated gas and sell back to the grid to the degree we have excess power. So that’s certainly a consideration there and some flexibility that we’re happy about. Let’s see. The third question, remind me there.

Unidentified Analyst: On your hedge positions for oil going forward?

Philip Riley: Hedging. We disclose that both in the appendix of our presentation and in the earnings release. I’d note that there’s a slight difference. We show some in the 10-K as of 12/31, and then some more recently. The short answer on hedging is that we are choosing to increase hedge positions as a result of this acquisition. Both given that we’ve agreed to a purchase price and a financing capital structure. And thus we want to protect some of those cash flows. We will have further hedging. And so, I can tell you just in general with a larger debt load, we’re going to be much more amenable to hedging. That said, we’re pretty happy with some of the trades we’ve made so far in the year. We did a fair amount earlier in January when prices were higher.

Got a lot of nice collars that allow for protection a little bit below where we are, but then quite a bit higher, including some of the $90 range and such. Just to elaborate there David, just a little bit more on the de-leveraging profile that we see with this asset. Coming out of the gates, we may be kind of in the neighborhood, 1.3, 1.4 times levered. But then we hope to pay down quite a bit of debt here in the back half of the year. As we described first quarter we have quite a bit of CapEx, may have a slight outspend second quarter roughly the same but then back half really start to pay that down. And then with that increasing EBITDA, you’re going to see leverage come down. We’re hoping to get it down to about one times by the end of the year.

So that gives us a little bit more flexibility potentially with hedging, but you can expect that we’ll be hedged going forward.

Unidentified Analyst: Great. That answers my questions. Thanks guys.

Operator: We have a follow-up question from the line of John White with ROTH MKM Capital. Please go ahead.

John White: Thank you, operator. I was going to ask about power sales to third parties which was just asked and answered by David. Thank you.

Operator: We also have a follow-up question from the line of Jeff Robertson with Water Tower Research. Please go ahead.

Jeff Robertson: Thanks. Kevin, back up to I think part of what Neal was asking earlier, can you talk about how you think about the flexibility that the New Mexico assets provide in terms of capital allocation and competition for capital between your legacy assets in Texas and now the new operating area?

Kevin Riley: Sure. Happy to. The term competing for capital, I see that and so many competitors press releases and I recognize the concept there. But I think we’re thrilled the fact that while this does compete for capital, in a lot of ways the asset is very similar. We’ve got a whole lot of tier-one wells that we see as good or some even better than our best over in Yoakum. And we’re going to really mix in the allocation there. For the most part, the way we’ve guided both the activity and the spend in the budget we’ve just disclosed. It really doesn’t stray too much in taking away from the legacy. It’s really just added Jeff. And so we’ve got a similar amount of wells and frankly and DNC type of investing over on the legacy kind of Yoakum properties slightly less EOR spend and hence the lower year-over-year effective total spend on the legacy.

Whereas, the new we’re reinvesting roughly half of the asset level EBITDAX. And so, I think it’s a really proportionate amount of allocation there. If you think of the acquisition, kind of cost and such as roughly half of where we are, it’s really proportionate there.

Jeff Robertson: So Philip is the right way to think about it. Then you have more geographic diversity and a new asset that’s still released the way you initially planned capital will generate pretty substantial excess cash flow that you can allocate as you see fit?

Philip Riley: Yes, absolutely. We do appreciate the geographic diversity for certain operational constraints we face from time to time midstream power and such as we described. The differentials are volatile in our industry, in our region. I’d say on those just quick note is those are for the most part of our out of our control, right? And we give guidance there mainly for your benefit, but it’s not something we control. So lower confidence on those. The appearance of lower differentials there, or I guess higher differentials to the index versus last year is really just a function of kind of fixed fees, applying to lower index prices on the gas and the NGL. But the geographic diversity there helps us at least. And we always at least have the ability later in the year, Jeff to throttle up or throttle back one area versus the other if we should run into any constraints.

Jeff Robertson: I guess, in terms of competing that ability to flex capital between the most, between the area that makes the most sense is what’s really important?

Philip Riley: Yes, exactly. That’s what some other big boy companies have and it’s something that I think we’re really going to benefit from now.

Jeff Robertson: Thank you very much.

Philip Riley: Thank you.

Operator: We have no further questions at this time. Ladies and gentlemen that will conclude today’s meeting. Thank you all for joining. You may now disconnect.