Riley Exploration Permian, Inc. (AMEX:REPX) Q2 2024 Earnings Call Transcript

Riley Exploration Permian, Inc. (AMEX:REPX) Q2 2024 Earnings Call Transcript August 8, 2024

Operator: Hello and thank you for standing by. My name is Virgina and I’ll be your conference operator today. At this time, I’d like to welcome everyone to Riley Exploration Permian, Inc. Second Quarter 2024 Earnings Conference Call. [Operator Instructions] I would now like to turn the conference over to Philip Riley, CFO. Please go ahead.

Philip Riley: Good morning. Welcome to our conference call covering second quarter 2024 results. I’m Philip Riley, CFO. Joining me today is 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 security laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or applied 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 Q2 2024 earnings call. Today we will highlight several updates and key changes since Q1 2024, including meeting or exceeding key metrics on planned guidance resulting in improving capital efficiency and significant free cash flow, closing an asset acquisition in Eddy County, New Mexico for $18.1 million, which added producing properties and development locations within our existing operating footprint, expanding the scope of our power joint venture with plans to generate and sell electricity and ancillary services to ERCOT, as well as increasing our ownership in the joint venture to 50%, raising $25 million of net proceeds through the issuance of 1.015 million shares of common stock, which was used to primarily fund the acquisition and the power JV investment.

We continue to execute our annual plan with overall positive results. It’s still early in the year to report on medium-term to longer-term results for the 2024 vintage wells, but thus far we are generally seeing outperformance on this year’s production results relative to forecast and as compared to prior year results. We continue to experience favorable efficiencies and cost savings on our drilling and completion activity. Well cost savings represent our largest driver of free cash flow improvement this year. Free cash flow generation was a primary objective for us this year as both a measure of performance and of shareholder return. We generated $38 million of free cash flow in the second quarter and $62 million year-to-date. Over the last 12 months we generated $126 million which facilitated debt reduction of $75 million or 18% year over year, dividends of over $28 million with a balance contributing to new investments and an acquisition.

Today we’re paying our 22nd consecutive quarterly dividend, our 14th consecutive dividend as a public company with $91 million return to public shareholders since 2021. Additionally, we welcome two new additions to our executive team in the second quarter. Jeff Gutman joined us as Chief Accounting Officer with 35 years of public and private company experience as the principal financial officer all within the industry. And John Suter joined us as Chief Operating Officer bringing 38 years of experience in various executive management roles across public and private companies within the industry. These additions will enhance our leadership team and strengthen our ability to deliver on strategic growth initiatives, improve operational efficiency, return capital to shareholders and reduce debt.

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. I’d first like to say Riley strives for excellence and operations through safe operating practices and continual performance improvement that is evidenced by our results shared here today. The team successfully implemented our plan in the second quarter including the closing and integration of the bolt-on acquisition in Eddy County, New Mexico. The results of the quarter reflect performance from both our legacy assets and from newly acquired assets. The bolt-on acquisition closed in early May and contributed for two months during the second quarter. Total equivalent production was 21.3 MVOE per day, a quarter-over-quarter increase of 5%. Oil production was 14.75 M barrels per day, a quarter-over-quarter increase of 4%.

Lease operating expenses were $8.50 per BOE, about $0.50 lower than during the first quarter and from the average of the prior four quarters. Since closing our bigger New Mexico acquisition in late spring of 2023, we embarked on a work over campaign for many of the vertical wells that we inherited with that package as well as efforts to optimize artificial lift. We’re seeing the benefits of that effort with overall vertical production volumes up 40% to 50% from levels at closing from last year. That work over activity drove some of the higher LOE over the past year which may be lessening at this point. As for power, we supported approximately 50% of our electrical load in Texas with self-generated power in the second quarter. We’ll continue to transition to a larger majority of our self-generated power following the balance of our units coming online in the third quarter.

And then finally, I’d like to highlight our team’s performance and development activity. As Bobby mentioned, well cost savings represent our largest driver of free cash flow improvement this year. With $100 million plus capital budget, that leads to some very meaningful savings. We believe well costs are on average down by more than 20% year-over-year or down by more than 25% as compared to 2022. Drilling efficiencies and completion redesigns account for just over half of these gains with better market pricing representing the balance. Drilling times are down by 20% year-over-year or 40% as compared to 2022. We’re generally completing wells now in pairs or more using a zipper frack design which we believe leads to both cost savings and better production.

As you can see, we are vigilant about capturing cost savings as we gain technical improvements in our drilling and completion programs. As we further integrate, last year’s foothold New Mexico acquisition and this year’s bolt-on, we are focused on taking best practices from our legacy Texas asset and incorporating them for production optimization and cost improvement in New Mexico. With that, I’ll turn the call over to Philip. Thank you.

Philip Riley: Thank you, John. Second quarter operating cash flow was $51.6 million or $57.6 million before changes in working capital declining very modestly by 1% quarter-over-quarter. Second quarter adjusted EBITDAX was $73 million higher by 3 million dollars quarter-over-quarter with the EBITDAX margin improving from 67% to 70% from the first to second quarter. Year-to-date total oil and gas hedge negative settlements improved by 77% or $6 million versus the six months of 2023 despite higher oil prices representing another driver of cash flow improvement year-over-year. Natural gas and NGL realized prices turned slightly negative for the quarter driven by weaker market fundamentals both domestically generally and more specifically in the West Texas region leading to wider differentials relative to the Henry Hub Index.

Midstream counterparty fees are then allocated to this pre-fee revenue which is how we arrive at slightly negative revenue. While disappointing, here are a few ways we think about this and how we’re working to manage the exposure. First, on an absolute basis the negative $1 million of combined gas and NGL revenue in the second quarter is dwarfed by $106 million of oil revenue which is up $9 million dollars quarter-over-quarter. Second, the negative gas revenue was more than offset by $1.2 million of positive gas hedge settlements during the quarter. And third, big picture, this is one of the reasons we’re pursuing the natural gas power generation project. Low or negative cost feedstock gas can lead to very attractive power economics which can ultimately work as an additional hedge for us.

Moving on, reinvestment rate of operating cash flow into upstream CapEx was 37% on an accrual basis and 34% on a cash CapEx basis. Hence, we converted 66% of operating cash flow to $38 million of free cash flow in the second quarter. That’s a single quarter record for us and is very exciting. Year to date we’ve converted 53% of operating cash flow to $62 million of free cash flow or $126 million the last 12 months, reinforcing this excellent capital efficiency. In the second quarter, we allocated 20% of free cash flow to dividends and 52% to debt pay down with the balance allocated to partially fund the power JV and the asset acquisition. Beyond free cash flow, we’ve benefited from $25 million of net proceeds from the equity raise. So, the use of funds for the quarter included $4 million to build cash, $20 million to reduce debt, $7.5 million for the dividend, $18 million for the acquisition, $10 million in contributions to the power joint venture.

The credit facility utilization is now at 43%, down from 66% a year ago, representing a significant increase in liquidity. We’ve paid down our senior notes by $25 million or 12.5% since issuance. Debt to TEV at quarter end was 39%, 1.2 times debt to LTM adjusted EBITDAX. We will continue to pay down debt, not because we believe we’re over levered, but rather because we prefer the flexibility and optionality that the extra liquidity affords. Looking ahead, we updated guidance and the written materials provided. I’ll offer just a few comments to provide a recap from the prior guidance. At the beginning of the year, we announced our annual plan, which called for 10% year-over-year oil volume growth while cutting spending by 10%. The current midpoint guidance calls for increasing oil production by 13% while reducing spending by more than 20% year-over-year.

Admittedly, volumes benefit modestly from the small acquisition, which wasn’t in the original plan. That will contribute to two-thirds of the year, which equates to only 200 to 300 barrels per day on average when viewed on an annual basis. And adjusting to exclude for that, we’re still at about 11% annual oil growth. Meanwhile, the CapEx reduction continues to improve. So essentially, we’re forecasting that we’ll achieve the plan volumes with less activity and less spending. We believe this will continue to translate to meaningful free cash flow. At $75 WTI for the balance of the year, we currently forecast full year 2024 free cash flow in the area of approximately $115 million, corresponding to year-over-year growth of approximately 65%, and corresponding to about 22% yield on the market value of our equity as of yesterday.

By comparison, median of E&Ps across all sizes, and excluding the gas year companies, has consensus free cash flow growth of approximately 10% year-over-year, and a current yield on equity value of approximately 12%, based on estimates using public data. The average across the S&P 500 companies is 5% year-over-year free cash flow growth, and 5% yield on equity value. We consider these some of the more distinguishing metrics for our company, as compared to the wider market. I’ll turn it back to Bobby for closing. Thank you.

Bobby Riley: Thank you. Once again, we appreciate your time and interest in our company. We’re pleased with our recent results, 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 open up the call for questions.

Q&A Session

Operator: [Operator Instructions] Our first question will come from the line of Neil Dingman with Truist Securities. Please go ahead.

Unidentified Analyst: Hey, good morning. This is Julian Roche, on for Neal. Thanks for taking our questions. How should we think about the incremental volumes throughout the year, given the recent acquisition in May, and then any consequential potential impacts there on go-forward guidance? Then, as like a follow-up, maybe give us a little bit more color on the revised power JV. Then kind of how, I know you said it acts like a hedge, so I just want to understand the dynamic there.

Philip Riley: Sure. Good morning, Julian. This is Philip. I can cover that since I mentioned it in my prior remarks. So, the acquisition is really only about 400 to 500 barrels a day production. We closed on that April 7th, and so when you do the math on an annual basis, what you see that contributing is about 200 to 300 barrels a day, when you’re dividing by 366 days a year. So, that was the logic there. We are forecasting growth for the year of I think the midpoint shows about 13%, so you exclude that and you’re still at 11%. We’re doing slightly less activity. You can see that in the well counts we’re showing there. We’ve got reductions in the CapEx. They’re reflecting that. As well as some additional cost savings. That’s the first part of your question. Anything you want to clarify there before I move on to power?

Unidentified Analyst: No, that’s helpful. Thank you.

Philip Riley: On power, as Bobby mentioned, we increased our ownership in the JV to 50%. That was planned all along from the beginning. We had that right in there that we established in February ‘23 when we set this up. What we’ve done at this point is expand the scope of the JV to have the ability to sell power energy effectively, selling generation energy into ERCOT, as well as the ancillary services. Ancillary services is a fancy word for basically standby power. ERCOT’s not a capacity market like you have in other ISOs in the U.S., but with the various challenges that Texas has had with cold and hot and everything in between, they’re adding more and more of this service to the grid to make it more resilient. They’re paying people to be ready and standby.

What we’re planning is a mix of thermal and battery. We’re still planning on what the optimal mix could be. Thermal being another word for natural gas fire generation. These would be received generators like we’ve got in Texas doing our self-generated power. And then some batteries can help with the ancillary. You can do both for ancillary. This isn’t a peek or play. This is something that we think we’ll dispatch most of the time based on where we see prices clearing these days with increased power demand with the low growth as well as a frankly highly variable grid, especially out in West Texas. In the area that we’re talking about, approximately two-thirds of the generation stack is wind. And wind is highly variable, much more so than solar actually.

And so, you’ve got periods where we believe that net gas generators are going to dispatch quite often. So, we’re going to continue to update you on that. That’s something that we hope to have coming online next year. Our guess is it’s a second quarter or third quarter type of thing that is significantly faster than some of the bigger projects, even solar and wind take for the interconnection queue. So, it’s an expedited plan that we’re excited about and we’re hopeful to hit. Thank you.

Unidentified Analyst: Got it. Thank you very much. I appreciate that additional color on that.

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

John White: Good morning and congratulations on a strong quarter. In your press release and prepared remarks, you highlighted savings on drilling and completion activities and you provided some additional detail on that. Do you want to give us an idea from the geographic standpoint where you’re experiencing that?

John Suter: Yes. Yeah, thank you John. This is John Suter. Really we are experiencing that in our Champions Play in Texas. We think as we keep modifying this, as we move over into New Mexico, we’ll carry some of these same savings over there with us. They’re a little bit different well-to-well as far as the completions go, but still we anticipate having those good savings.

John White: Okay, thank you. And on the New Mexico bolt-on acquisition, do you plan to embark on a well work over program there in the second half?

John Suter: Yeah. We have a larger work over program in New Mexico. That’s just one part of it, but certainly we have escalated that a little bit. We also have gained a lot of value there by taking those wells and connecting them to the power system. We’ve taken a number of wells off generators and probably saved $35,000 a month on the number of wells we’ve done there. So we’re doing all the usual work at getting them integrated, but certainly we’re including that in our work over program.

John White: Sounds good. Thanks for the extra detail. I’ll pass the call back.

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

Jeff Robertson: Thanks. Good morning. John, on the work over program in New Mexico, is that adding barrels that would not have been factored into the acquisition economics for either the 2023 acquisition or the bolt-on?

John Suter: Yeah, I think it’s really a small segment of our production, but still an important one. Like I said in our opening remarks, I think we’ve increased those volumes probably 50% with pump-off controllers, with the various work overs we’ve been doing, improving the artificial lift, but certainly it’s a smaller impact of our production compared to horizontal wells.

Jeff Robertson: And though it’s way too early for 2024 guidance, but can you all talk at all about how you think about putting together a capital program next year with the current asset base?

Philip Riley: I’ll take it, Jeff. I think you meant 2025.

Jeff Robertson: Yes, I’m sorry.

Philip Riley: If we’re talking ‘25, yeah, it is a little early. You know, every time we think we were done with volatility, we get something new in the Middle East or political backdrop. So we got a busy and noisy few months ahead of us here in the fall. We’ll watch that, but in general, our business model and strategy is to grow free cash flow while minimizing the amount we have to reinvest and really focusing on that capital efficiency. So we’ll see where prices are bouncing around and what that affords us. Frankly, between a $70 and $80 WTI level is fantastic. We’re not holding out for $90 or $100. This is a great level for us. Our wells are economic far, far below that, but we want to be mindful of it. It’s a balance of managing inventory, maintaining a good amount where you all appropriately award us a sufficient going concern value.

But that’s how we’re looking at it is to hopefully have some continued modest growth there, hoping to grow that free cash flow still, super excited about that kind of 60% to 70% level year over year growth we’re seeing this year. Hoping John’s team can continue to push the envelope on well cost savings. So we’ll continue to collect bids on AFVs to see how that’s coming out. That may shape our thinking. And then finally, I just want to say this is a bit of a segue, but it’s tied to how we think about capital allocation is we see a lot of opportunities out there right now on the inorganic front. And so we’re being a little bit measured just to keep a little bit of powder dry as we see a lot of exciting things out there that we’ll have a better idea of where those will have landed later in the fall.

Jeff Robertson: Thank you, Philip.

Operator: Our next question will come from the line of Noel Parks with Tuohy Brothers. Please go ahead.

Noel Parks: Hi, good morning. Just had a couple. You actually just sort of touched on the AFV process getting rolling. And just as far as overall service capacity for your needs in your part of the basin, do you see the market as pretty well balanced at this point? Or do you think maybe you’re looking at either inflationary or deflationary trends as you look ahead in the next year?

John Suter: I think that what we’re seeing is that we’re able to get rigged services as we need them at reasonable prices. The stimulation market is kind of a mixture of both large and there’s a number of small companies that have moved out there that are really doing an excellent job for that area as well. So really think that certainly in the last, I don’t know, six months, as we said, about half of our savings have come from market pricing. But I think it’s stabilized. We’re getting a good value and a good quality of service for what’s out there right now.

Bobby Riley: Something from a macro point of view, Noel, is you watch all the corporate deals happening, all this consolidation, and every time one of these faster growers, smaller companies, gets gobbled up by a bigger guy, more often than not, that’s pulling demand out of the system for these services. We’ve obviously had a tremendous amount of consolidation. Look at the year-over-year rig count. I mean, it’s down by 90 or 100. Look at what DiamondBack just announced, how they’re saying, we thought we could do that. We’re actually going to reduce it by even 6 more rigs. All of that, we’re not necessarily competing with those guys for the same rig, but it generally pulls pressure out of the system. Same thing with fracing. It’s a pretty favorable environment for us. So we’re excited about that.

Noel Parks: Great. Thanks for the observation. I think it’s really timely. And just some thought about, or just looking for some thoughts on the outperformance your expectations that you’ve seen in your acquired areas. And just in retrospect, benefit of hindsight, do you think you just were overly conservative in your original take on what the assets could do? Or is it more just that there’s just a lot of stuff that the old owners weren’t able to get to, they just didn’t have the capital or maybe the technical resources to get at some of the low-hanging fruit that you’re now benefiting from?

John Suter: Yeah, I wasn’t here at the time, but I can tell you from what I’ve learned so far, it’s really down to a number of things. We do have a number of wells that are outperforming their type curves, that are really, what I believe, from a little bit of a stimulation recipe change that I think is still under review, but giving us some very positive results. I also think that, I don’t know, it’s just from a number of things. Primarily the stimulation change, but also just a number of wells coming on where certainly we had the four wells we turned in this quarter were really solid. But it’s not one thing, I don’t think it’s the neglect of the previous people. We’re just doing a really good job on homing in on kind of what the optimal stimulation is for these wells.

Noel Parks: Got it. Thanks a lot.

Operator: Ladies and gentlemen, that will conclude our question-and-answer session and today’s conference call. Thank you all for joining. You may now disconnect.