Riley Exploration Permian, Inc. (AMEX:REPX) Q3 2024 Earnings Call Transcript

Riley Exploration Permian, Inc. (AMEX:REPX) Q3 2024 Earnings Call Transcript November 9, 2024

Operator: Good morning. My name is John, and I’ll be your conference operator today. At this time, I’d like to welcome everyone to the Riley Exploration Permian, Inc.’s Third Quarter 2024 Earnings Conference Call. All lines have been placed in mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. I would now like to turn the call over to Philip Riley, Chief Financial Officer. You may begin your conference.

Philip Riley : Good morning. Welcome to our conference call covering the third quarter 2024 results. I’m Philip Riley, CFO. Joining me today are Bobby Riley, Chairman and CEO; and John Suter, COO. Yesterday, we published a variety of materials, which can be found on our website under the Investors section. These materials in today’s conference call contain 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’ll also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in our supplemental disclosure on our website. I’ll now turn the call over to Bobby.

Bobby Riley : Thank you, Philip. Good morning, and welcome to our Q3 2024 earnings call. Today, we highlight several updates for Riley since Q2, including that our team met or exceeded key metrics on our planned guidance, resulting in significant free cash flow. This has allowed us to continue paying down debt and distributing dividends back to our shareholders. Today, we’re paying our 15th consecutive dividend as a public company with a recent increase to $0.38 per share, up 6% from previous quarter. Since 2021, we’ve returned $98 million to public shareholders, achieving an annual dividend growth rate of 11%. Additionally, we paid down $35 million in debt this quarter, underscoring our commitment to delivering consistent and growing shareholder returns while maintaining prudent financial management.

I’m happy to report that our 2024 drilling and completion campaign is delivering excellent results. We are successfully driving down cost while generally seeing production outperform relative to forecast and prior year results in both West Texas and New Mexico. This reinforces the effectiveness of our operational strategies and strengthens our ability to generate value. This success also underscores the quality of our acquisitions and highlights new opportunities to invest in infrastructure that will support future growth. Just as we did early on in our Texas, our champions asset, we plan to take advantage of these opportunities beginning in Q4 and the future to build out infrastructure that will enhance transportation and processing, providing reliable, continuous takeaway, ensuring we are well positioned to maximize efficiency and long-term value in both regions.

We believe Riley’s oil-focused assets to be among the most productive and capital efficient in North America as we demonstrate in new slides in our investor presentation. Using data and analysis from Enverus, a top data provider for our industry, one can see how our assets compare favorably to core Midland Basin and Delaware Basin wells outperforming both on longer-term cumulative production per lateral foot metrics and forecasted breakeven prices. Since the fall of 2022, we’ve been operating a CO2 pilot in a small footprint area that consisted of 6 vertical wells and 3 horizontal wells. The data gathered from this pilot showed that we were successful in mobilizing hydrocarbons, both oil and NGLs with CO2. This provides valuable insights for potential EOR applications, which we believe will be best suited for post primary production later in the reservoir’s life.

We will continue to evaluate anthropogenic CO2 sources that will be crucial in the economic outcome. We made significant progress with our power joint venture, RPC Power, across both projects. In Yoakum County, we completed the final installation of power units supporting our operations and are actively transferring load to these units. For our larger merchant project, we advanced with siting, permitting and equipment orders, positioning us well for continued development. Now I will turn the call over to John Suter, our COO, to discuss operational results for the quarter, followed by Philip Riley, our CFO, who will discuss financial results and guidance.

John Suter : Thank you, Bobby, and good morning. Once again, Riley demonstrated excellence in operations through safe operating practices. The team achieved a total recordable incident rate of zero for Q3 and year-to-date. We achieved 91% safe days in the quarter, a metric requiring no recordable incidents, vehicle accidents or spills over 10 barrels. Thanks to our team for their continued focus on these efforts. In Q3 of 2024, we drilled 12, completed 3 and turned in line 6 gross operated wells. The additional wells turned in line are carried over from Q2 completion activity. The 9 DUCs generated in Q3 will provide our completions for the remainder of 2024 and give us a healthy start to our 2025 program. As Bobby mentioned, our 2024 drilling and completion campaign continues to drive down costs through efficiencies and economies of scale from pad drilling and continuous drilling operations.

This has been achieved through optimization of drilling practices, pad drilling, geosteering efficiencies and zipper fracs. We’ve increased both our feet per day and lateral feet per day by 33% and 20% in 2024 year-to-date relative to 2023, respectively. We’ve also set records for drilling in Yoakum County for fastest 1-mile lateral at 3.97 days spud to TD and fastest 1.5-mile lateral at 4.78 days spud to TD. Net production grew from 1.34 million to 1.42 million barrels of oil quarter-over-quarter, an increase of 6%, while equivalent production is up 11% from 1.94 million to 2.16 million barrels of oil equivalent. Our average daily net production was 23.42 MBoe per day for this quarter. We continue to make steady progress in increasing the offtake of associated gas.

Much of this is driven by enhancements from our midstream provider alongside us. These efforts allowed us to send 42% more of our gas produced to sales compared to the previous quarter. The team successfully implemented our New Mexico plans in the third quarter, including completing our first 2 Red Lake wells with 9 more planned to be drilled this year. We purposefully backloaded our Red Lake development to avoid costly rig moves between states. Initial production of these completed wells meets or exceeds expectations for the area. The additional wells will provide valuable opportunities to test completion methodologies and well spacing to continue to improve results on future wells in the asset. Lease operating expenses were $8.60 per BOE within 1% of last quarter and down 7% versus the same quarter last year.

With the inclusion of vertical production in our New Mexico asset, absolute LOE has increased slightly, offset though by an increase in total equivalent production. We’re continuing to look at options to drive down LOE costs, particularly on our vertical wells. This includes, but is not limited to leveraging software and other technology to help manage, optimize and even automate artificial lift changes. In the fourth quarter of this year, we will begin construction of a gathering and compression system in our New Mexico asset to better control our gas takeaway and allow for optionality in the future. This infrastructure accounts for roughly $12 million of capital spend within the fourth quarter and will allow gathering and compression of our 2025 drilling program wells as well as much of our existing gas production.

As for power, we supported approximately 50% of our electrical load in Texas with self-generated power in the third quarter. We’ll continue to transition to a larger majority of self-generated power as we bring on more production within the generation footprint. I’ll now turn the call over to Philip to discuss Q3 financial results and guidance.

Philip Riley : Thank you, John. Third quarter 2024 operating cash flow was $72.1 million or $60.5 million before changes in working capital, with the latter increasing by 5% quarter-over-quarter. The increase was driven by higher oil production volumes, lower total unit costs, improved hedge settlements and lower income tax payments, partially offset by a 12% decline in average realized prices, including higher gas sales volumes and negative realized prices. We reinvested 50% of operating cash flow before working capital changes into upstream CapEx on an accrual basis and 38% on a cash CapEx basis. Hence, we converted 62% of that cash flow to $38 million of free cash flow. That repeats approximately the record levels set last quarter despite the significantly lower prices this quarter.

Year-to-date, we’ve converted 56% of operating cash flow before working capital changes to $99 million of free cash flow or $133 million of free cash flow for the last 12 months. So we’re reinvesting less than half our after-tax cash flow and still growing production volumes, but more importantly, growing our free cash flow. We believe this combination of lower spending with higher volumes and free cash flow is a useful indicator of asset quality and capital efficiency. The $99 million of free cash flow this year is 2.7 times the amount — the same metric, I mean, through the first 9 months of 2023. And the $133 million of last 12 months free cash flow corresponds with approximately 21% yield on our equity value as of the close yesterday even after the 8% 1-day increase in the stock price.

Generating significant free cash flow while still investing for growth has been a key objective for our team and our company this year, and we’re proud to be delivering on the objective. Operating income this quarter was impacted by the impairment related to the EOR project discontinuation, most of which was non-cash. On a go-forward basis, we’ll save approximately $3 million per year on avoided CO2 cost, which I’ll note was previously capitalized, not in OpEx, but it will increase free cash flow going forward. Net income was down by 24% or $8 million quarter-over-quarter as gains on commodity hedges, about $23 million unrealized and $1 million realized, absorbed some of the reduction from the impairment. Adjusted net income, which excludes the impact of the impairment and the hedging gains, was down by 5% quarter-over-quarter.

We reduced the value of debt by $35 million this quarter to $300 million. Debt to total enterprise value at quarter end was 34% with 1.07 times debt-to-LTM adjusted EBITDAX. The credit facility utilization is now 35%, down from 65% a year ago, and total debt has been reduced by $100 million over the past year. We’ll look to pursue a normal course extension on the credit facility by early in the new year. The book value of shareholders’ equity increased to $507 million or $24 per share based on 21.5 million shares outstanding. Dividends in the third quarter accounted for $8 million or 22% of free cash flow. A final allocation of capital in the third quarter was $1.5 million contributed to the Power JV. Moving on to guidance. At the beginning of the year, we announced our annual plan, which called for 10% year-over-year oil volume growth while cutting capital spending by 10%.

Our current full year guidance range based on 3 quarters of actuals plus 1 quarter of guidance for the fourth quarter calls for increasing full year 2024 oil production by 14% to 15% over full year 2023 production. Our guidance range for fourth quarter ’24 exit rate is up by 14% to 19% over fourth quarter 2023 levels. Approximately 85% of annual oil volume growth can be attributed to organic development funded by CapEx with 15% attributed to the bolt-on acquisition earlier in the year, which is not in our original plan. Adjusting to exclude for the acquisition, for illustrative purposes, we’d still be at 12% to 13% annual oil growth, so still beating our original goal. Fourth quarter OpEx and overhead cost guidance ranges were both reduced from prior quarter levels, primarily owing to improvements experienced in the third quarter and to a lesser extent, to the benefit of the increased gas sales volumes, which has the effect of increasing the denominator on unit cost metrics.

Our fourth quarter CapEx range implies a year-over-year reduction of 20% using the low end or 12% using the high end of spending. Our full year CapEx range did increase from last quarter on account of the gas compression project that John discussed, which will have longer-term benefits. Adjusting to exclude for that new compression project, for illustrative purposes, as we didn’t contemplate it earlier in the year, then we’d be looking at a huge 21% to 29% annual CapEx reduction from last year, yet still achieving organic growth. Back to you, Bobby, for closing. Thank you.

Bobby Riley : Thank you, Philip. Once again, we appreciate your time and interest in our company. We’re pleased with our recent performance. And while we believe these quarterly results are strong, we remind investors that we are primarily focused on long-term results and value creation. We remain confident that our strategic focus and operational excellence will continue to drive growth and profitability for our shareholders over the long term. Operator, you may now turn the call over for questions.

Q&A Session

Operator: Thank you. Ladies and gentlemen, we’ll now be conducting the question-and-answer session. [Operator Instructions] Your first question comes from the line of Neal Dingmann with Truist Securities. Please go ahead.

Neal Dingmann : Hi, guys. My first question on the capital efficiency and your upcoming D&C plan specifically. You all seem to continue to do more with less as certainly notable by your Slide 5. I’m just wondering when looking at next year, is the plan still to maintain around the similar growth? And how would a $60 versus $80 environment affect your plans?

Philip Riley : Right. Good morning. Thanks, Neal. Yeah. So we’re not providing guidance now for the 2025, if you saw. We haven’t historically done that. Now we typically do it in the — early in the same year. We can offer a few things. So we’ve got a multiyear track record of growth through development, and simply turning the calendar shouldn’t materially alter our strategy. This year, we aim for 10% growth, and it looks like we may achieve even more than that on account of the incremental gains we made each quarter. 2025 might look similar. We might keep making those small gains each quarter. Similar to this time last year, the macro backdrop is pretty volatile. We’ve got fairly loose crude supply and demand balances, large amount of OPEC spare capacity, large non-OPEC growth areas in places like Guyana, you got weakness in China.

So we’re watching that. Of course, we’ve got the optimism here domestically with some more growth outlook post election, but we’re all still processing that as the team and with the Board. On the price volatility, I think that would probably affect us maybe less than some companies. We’re hedged ballpark 40% on total oil production next year, maybe 65%, 70% on PDP. And of that, swaps is about 30%, maybe in the $73, $74, so above the current strip, that gives us some cushion. And then you’ve got about 70% in collars at $63 to kind of mid-70s pricing. So that gives us some protection and mitigates some of that volatility. And I don’t think that we’ll be one to make big changes, certainly at the $80 level. If things are at $60, then maybe we have a little bit less growth.

But as you started with the question, we’re able to do more with less. We’ve got some capital-efficient assets. So I think we might do a tiny bit less there with quite a low price, but don’t see a problem in keeping production flat there.

Neal Dingmann : No, that’s what I thought. And then just secondly, on the — I can’t to help ask on the power focused JV specifically, maybe could you describe any potential upside next several quarters and maybe more specifically sort of significant data points we should be looking for in the next few quarters?

Philip Riley : Yeah, it’s a fair question, and we’re looking for the right way to do this. We recognize most of you are upstream analysts, and this is a bit of a new foray. So we’ve got 2 phases here. The first phase is effectively a behind-the-meter project to power our own operations. That’s installed. As Bobby noted, the load is being transferred over more and more. That’s going to be an easier business to forecast, and we’ll give some guidance soon on that. But that we hope is like a mid-teens type of capital return, and we’ve invested a little over $30 million in that to date. And then we’ve got the second project, which is the sale to ERCOT, and we’re making great progress or RPC is making great progress there. That’s the larger one with generation of power and the services, the backup ancillary services.

And so they’re making great progress with permitting and obtaining surface acreage, executing interconnection agreements and so forth. We’re actually not showing material equity contributions this quarter to the JV. Some of those items have contingent payments after the certain milestones are hit. And then we also have some line of sight on some project financing and some construction financing options, which could provide another funding option. And so I just want to encourage you, we are making quite a bit of progress there quickly. We’ve got projects scheduled to come on midyear on that second phase, midyear next year. We’re currently seeing a higher potential return there. That’s a tougher business to forecast, though, with how power prices trade.

They trade every 15 minutes in the day ahead market, and you’ve got wide volatility. We see potential to make money even at lower prices. We’ve got a favorable setup with low gas prices out in the Permian, and that’s part of the thesis there is that this allows for an implicit hedge on our kind of lower gas price there, and we’re happy with selling power at those lowest prices, and we can also enjoy the upside on the gas if that should ever materialize. But we appreciate your patience. We’ll be providing more information soon.

Neal Dingmann : Absolutely. Thanks, Phillip.

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

John White : Good morning. Congratulations on a very fine quarter.

John Suter : Thank you, John.

John White : In your 4Q guidance, you’ve got a line item infrastructure in the range of $14 million to $21 million. I believe your COO touched on this in his comments, but I was wondering if you could provide some more detail.

John Suter : Sure. Yeah. Just as Bobby mentioned earlier, we found value in making key infrastructure investments and champions that delivered — has been delivering long-term value in that development. Our Red Lake asset has the same opportunity. So a reasonably large compressor station installation and associated gathering system on the west side of Pecos River will help us deliver our 2025 development program volumes along with much of the existing gas to sales in a much more reliable manner than would likely not be possible on the existing low-pressure network that’s mostly full. So this station will give us more future optionality to various gas processors in the future, if needed, different gas markets as we spend significant development drilling dollars in the next 5 to 7 years, we want to make sure and have the optimal situation there.

John White : Thanks for the detail. I appreciate it. And I’ll pass the call back to the operator.

Operator: Your next question comes from the line of Jeff Robertson with Water Tower Research. Please go ahead.

JeffRobertson : Thank you. John, just to follow up on the compression system at Red Lake. Is that — am I right in thinking that, that system will allow for more continuous operation or both with obviously benefiting gas takeaway, but also there’d be a benefit on oil production?

John Suter : Yes, absolutely. We’ll be able to compress some of these new wells to the high-pressure system that, again, we believe is much more reliable from a downtime situation. Certainly, it’s going to let us get access to that capacity, which in turn, if we produce more gas that allows us to produce more oil. So we think it will be kind of a key item in our 2025 development program on the Red Lake side.

Jeff Robertson : Will it be a net positive, too, from an operating cost standpoint?

John Suter : Yeah, it should be. There’ll be where we might have been paying fees for some of that, we’ll do the installation, but then we’ll get a discount on likely on some of those fees that we would normally pay somebody else.

Jeff Robertson : And then back in at champions on the — with the power, I think you said you’re 50% self-generated in the fourth — in the third quarter. Will you be 100% at some point in the near future or close to 100%?

John Suter : I think it’s going to be a little bit slower than that. There’ll be a gradual build as the whole field is not tied to that — all of that network yet. But as we bring on new drilling programs, kind of expand the footprint of our grid, we’ll certainly get there in the next couple of years, I would imagine. But for now, we’ll just be adding on each drilling program wells as we go.

Jeff Robertson : And am I right in thinking that the economic benefit of that is, number one, lower power costs but also more reliable power that supports maybe less unscheduled downtime and allows you to produce more oil than you might if you had to rely on the existing grid?

John Suter : Yes. I would say it’s less of a power savings from an operational perspective. But what it does do is provides us great benefit in — you’re right, like you mentioned, consistency with less downtime. I think in the time past, we had issues with brownouts being at kind of the end of the electric system grid there. So this gives us a lot more control over the situation, lets us produce our wells more of the time and control our downtime on those ESPs, which is not good. And so I think that, that can save a lot of money just in future workovers of whenever something drops and stays down for a while. So we’re excited about it. The unit costs should go down over time as we add more and more power to the installation. So we’re excited about it.

Jeff Robertson : And lastly, Philip, I know you said that the CO2 costs were being capitalized at the pilot. But will discontinuing the pilot have any other impacts on the portion of operating costs that were being expensed related to that pilot?

Philip Riley : No, it really won’t on the expense. It’s that avoided CO2 contract cost, which is roughly $3 million a year. Implicitly, we could see some production return, which — and potentially a little bit less power usage there with less compressors being run, less water flowing through there and such. So maybe some mild stuff, but not significant on the OpEx.

Jeff Robertson : Thank you.

Operator: Your next question comes from the line of Noel Parks with Tuohy Brothers. Please go ahead.

Noel Parks : Hi, good morning. Just sort of piggybacking on some of the discussion about the power JV. If you could just sort of walk me through. So if we sort of head to the opposite scenario of much stronger nat gas prices, which is a high-quality problem to have, how would that sort of ripple through the couple of different projects you have on the power side in terms of economics and advantages you — that low gas provides that would then shift?

Philip Riley : Yeah. That’s a fair question, Noel. So first and foremost, in a higher gas price scenario, we all have to remember if we’re talking higher Henry Hub and NYMEX or are we truly talking higher West Texas, Waha, Plains Pool and such, which often have a significant negative basis differential like they did this quarter. So we are still a long way from, say, $3, $4, $5 realized gas out there post basis differential. But on our baseload project, we are taking that gas in kind. So instead of selling it to the market, we’re taking it in kind — or sorry, RPC, the JV is taking that in kind. So that acts as a feedstock. We have a certain price there that it would be a material discount to that market price effectively. And then over on the merchant deal, it’s going to be bought and sold at a market clearing price.

And what we take comfort there — in there is the strong historical correlation between the marginal price of gas in setting power prices. There can be some disconnects, of course, in the middle of a sunny California weather type day if it’s 65 and sunny and windy, you’re going to have lower power prices. But what we’re seeing is the retirements of the traditional coal and even larger nat gas is outpacing that renewable addition and especially in the face of all the surge of power demand from general Texas economy growth, oilfield growth out in West Texas, oilfield town growth and then, of course, all of this technology boom and such and the talk of AI data centers and such. So the dynamics are still good for us, and we’re excited about the prospect.

Noel Parks : It’s really interesting. And earlier in the call, you were talking about just the success you’ve seen with the efficiencies. And you mentioned pad drilling, geosteering, zipper fracs. And I was just wondering, the results from those, anything — I don’t imagine necessarily anything you’ve seen that’s been an out and out surprise. But I just wonder if there’s any implications for maybe localizing the success you had with some of the techniques that might be applicable to a wider part of the inventory.

John Suter : Yeah, great question. And I think you’re absolutely right. So what we are doing is really, we have great rock to start with. We’ve been seeing that. But now that we’ve been able to get the same level of production results just with cheaper costs, again, our New Mexico asset, especially is well set up for pad drilling. We’re testing the spacing on a lot of things there now. But I think it’s really more of just continued improvement, the way I see it. I mean, again, with the zipper fracs, we’re getting better sand placement. Certainly, we’ve had some unexpected improvement on some wells, but we tend to just have really good type curve results that we’re pleased with. And again, we’ve just put ourselves in a great position with the asset quality we have and are just performing and executing well. But I wouldn’t say there’s any transformative ideas. It’s just basic blocking and tackling using all the industry methods at our disposal. It’s working well.

Noel Parks : Great. Thanks a lot.

Operator: As there are no further questions at this time, that concludes our Q&A session and today’s conference call. Thank you all for participating. You may now disconnect. Have a pleasant day, everyone.