Good day, everyone, and welcome to the Riley Exploration Permian, Inc.'s First Quarter 2024 Earnings Conference Call. At this time, I would like to hand the call over to Mr. Philip Riley. Please go ahead, sir.

Good morning. Welcome to our conference call covering the first quarter 2024 results. I'm Philip Riley, CFO. Joining me today is Bobby Riley, Chairman and CEO. 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.

Thank you, Philip, and thank you again to everyone for joining us on today's call. Yesterday, at the close of the market, we announced the results of our first quarter in 2024. I'm pleased to report that Q1 was another outstanding quarter for Riley Permian. And we are on track to deliver our previously disclosed 2024 operating plan, targeting year-over-year oil growth with a reduction in CapEx. Our net oil production saw a 4% increase compared to the previous quarter, reaching an average of 14.2 thousand barrels per day. Looking ahead to our Q2 guidance, we're forecasting a range of 14.4 to 14.8 thousand barrels per day, and we expect the majority of our incremental growth to occur in this period and stabilize for the remaining quarters as we work towards achieving our year-over-year targets. From an operational standpoint, we drilled 7 net wells, which represents approximately one-third of our projected total for the year. We released the rig in March and plan to resume drilling operations in June. Our team has achieved significant advancements in drilling efficiency by adopting cutting-edge technologies and streamlined processes. These improvements have allowed us to rely on a single rig for a portion of the year while still delivering double-digit volume growth. We completed 4 wells and brought 6 wells online during the period, benefiting from 2 drilled but uncompleted wells, or DUCs, from late 2023. On Tuesday of this week, we closed our previously announced bolt-on acquisition in Eddy County, New Mexico. This will expand our existing operating footprint in New Mexico by adding 13,900 contiguous net acres. The acreage is largely underdeveloped but is 99% held by production through legacy vertical wells. This acquisition enhances the optionality of our total development inventory by providing high-quality horizontal drilling locations, primarily in the Yeso trend, including the Blinebry, Glorieta and Paddock formations. Furthermore, the acquisition includes valuable infrastructure such as saltwater disposal wells which will optimize operations across our existing New Mexico footprint. We remain focused on creating long-term value for our shareholders and delivering predictable and sustainable growth for years to come. To achieve this, our capital strategy prioritizes discipline to allocate resources to support our growth objectives, while also delivering on our commitment to strengthen the balance sheet and return capital to shareholders in the form of dividends. Looking ahead, we remain excited about the opportunities in front of us, and we are well positioned to execute our 2024 plan and beyond. We will continue to focus on operational excellence, cost control and capital efficiency to drive long-term value creation for our shareholders. With that, I'll now turn the call over to Philip to provide more details on our financial results.

Thank you, Bobby. First quarter operating cash flow before working capital increased by 7% quarter-over-quarter despite 2% lower oil prices. The largest driver of quarter-over-quarter improvement was our settled hedges as lower-priced legacy swaps rolled off in December, and despite some generally strong prices during the quarter. In production, volume increases and cost reductions contributed to a combined $5.5 million of cash flow improvement. Oil price ended the quarter about $11 higher than at year-end, which in turn led us to book the noncash derivatives loss and which drives the lower net income this quarter. As of today, that dynamic has already partially reversed with lower oil prices. The noncash derivatives values flip flop frequently by quarter and correspond infrequently with ultimate settled amounts is one of the reasons we focus less on net income. Reinvestment rate of operating cash flow into upstream CapEx was 45% on an accrual basis and 60% on a cash CapEx basis. The larger ratio of cash-to-accrual CapEx this quarter was driven by some larger prepayments, including on infrastructure for work that had not yet occurred and that will drive success for the full year development plan. We converted 40% of operating cash flow to free cash flow in the first quarter, representing continued improvement with this metric from prior years. Free cash flow declined quarter-over-quarter, but there is no concern there. First, we use cash CapEx for our free cash flow calculation while many companies use accrual CapEx. If we had used accrual CapEx, then free cash flow would have increased by 11% quarter-over-quarter. In the fourth quarter of 2023, we had especially light cash CapEx, opposite of this quarter's dynamic. Second, we regularly encourage observers to focus on a 4-quarter measure of free cash flow over a single quarter. We'll now turn it back to the operator for questions. Thank you.

Thank you, Philip. We will now take a question from Neal Dingmann from Truist Capital.

Phil or to you Bobby, if you could talk maybe a little bit more about the acquisition, but pretty positive? Maybe in terms of what it added in terms of production? Maybe how we should think about incremental volumes throughout the year on this? And impact on guidance? And maybe even on the oil cut throughout the year? Just wondering how this might impact things.

Yes, I can start with that. The acquisition is producing about 400 barrels a day and just closed a couple of days ago, so we will only see the benefit for about two-thirds of the year. That translates to an average increase of around 260 barrels a day when considering a full year. Therefore, the guidance range we provided, 14.4 to 14.8, with the midpoint suggesting 14.5 for the year, aligns closely with our previous guidance. To achieve the high end of that range, we would need to average 15.3 for the remaining three quarters. We believe this provides a good representation of the full year. Our existing production consists mainly of a few small non-operating horizontal contributors along with some smaller vertical wells, and we appreciate the potential from our underdeveloped horizontal inventory, which we do not plan to drill this year. Overall, we're excited about the acquisition, as it helps maintain about a decade of inventory and brings valuable infrastructure necessary for our operations. Additionally, we can charge neighboring non-operating partners fees for using our saltwater disposal wells. Does that address your question?

Yes, it certainly does. It's good to hear. As a follow-up, could you or Bobby discuss oilfield services? It seems that you have a lot of flexibility regarding rig availability, letting it go and bringing it back as you choose. Is that correct? Additionally, what are you seeing in terms of oilfield services costs?

Yes, Neal, this is Bobby. I'll address that. We have a strong relationship with the local drilling contractor, allowing us to bring in and drill a batch of wells while coordinating with our offset partners to keep everything within the same area. As we move towards more pad drilling applications, we're experiencing reduced costs for rig moves and greater efficiencies in the time from spud to TD. Consequently, our costs are aligning with our expectations. On the pressure pumping side, we are noticing a softer market, which is leading to more competitive bids and pricing. This change has emerged from recent larger mergers and acquisitions that have increased the availability of frac teams and services eager to retain their market share. They are aggressively pricing their services, and we are capitalizing on that opportunity in the current market.

Our next question comes from the line of John White from ROTH Capital.

Congratulations on closing your New Mexico acquisition.

Thank you, John.

I wanted to ask about the RPC Power project. In the press release, you said you put in another $5.6 million that effectively completes the funding for the current project. So that's the funding. How would you describe the work out in the field on the actual infrastructure?

Yes. I would say we're kind of right on schedule where we thought we'd be. We're installing 20 megawatts of power out there. We've had 10 megawatts over there for some time and we're just now receiving the second package of generators to get us up to our total design. We're currently getting all of that stuff tied into our private use network, which basically allows us to self-distribute power to all of our wells. So I think, operationally, that should be 100% operational probably by the end of summer. And so far, I think we're really excited about that opportunity, at least we're producing our base load. And then looking at other opportunities that we might see coming our way with power.

And when it's fully up and running, how much of your electricity or your power needs will this project satisfy?

Yes. Almost all of our power demand in Yoakum County is being met by what we refer to as our Champions. When we initially designed the infrastructure there, we established that network, and now we are able to utilize it, which will allow us to be almost fully self-sufficient. There may be one or two wells still on separate meters, but the vast majority will be self-generating.

And does the similar opportunity exists on your New Mexico properties?

It does. As we're building out and looking at our infrastructure requirements in New Mexico, going forward, we are instead of tying individual meters back into the grid. We are installing, I don’t know if it's the term, it's a private use network or our primary point of take from the provider out there so that eventually we can tie our own generators in systems into that as well. But that's a little bit long term. We probably won't get there this year, but we're still on the laying out. It has to do with establishing drilling schedules and time to water infrastructure and all of that at the same time. But it's definitely what we do in our operation, and we will be doing that going forward.

Our next question comes from the line of Jeff Robertson from Water Tower Research.

To follow up on the power venture, Bobby or Philip, can you try to quantify the economic impact of supplying your own power to the Champions acreage compared to the alternative, which might have been selling the produced natural gas just into the grid at a relatively low price?

Yes, our goal is to enhance the margins on the hydrocarbons we produce in the area. As you're aware, when Waha pricing turns negative, the residue gas can have little to no value for us. However, we can utilize that residue gas to power our generators, which helps to support our baseload production. In terms of individual well lease operating costs, the impact is likely neutral. As a joint venture partner, the power company is expected to benefit from approximately 50% of the revenues generated from this power production.

35% ownership right now that we're set to benefit from. And we think it's kind of a high-teen type of return, Jeff, but that's a nice stable return, right? This isn't an oil well that's declining, so it's something that we're excited about.

Is it fair that the other part of the return just comes from having a more reliable source of power, which might lead to...

Absolutely. One of the main reasons for this is that we're at the end of the grid and have been experiencing frequent power disruptions, which incur significant costs to restore some of the wells. Therefore, improving reliability in our power supply is a core motivation.

In New Mexico, you talked about the saltwater disposal, the wells you acquired in the most recent acquisition and your SWD assets that serve that area. Do you need to spend much capital to either upgrade or enhance those to be able to handle Riley's activity plus be able to maybe take third-party volumes?

I think we're going to focus on just tying those wells in with some flow lines to loop them into our system to give us excess capacity. Primarily, we want to make sure that our disposal requirements are met with some spare capacity for emergencies and stuff like that. But as we continue to look at opportunities there, I think there would be some coming in that could be charging some third party. But for the most part right now, we're 100% focused on our own disposal requirements.

Either way, you eventually gain some LOE benefit as you work through that process.

Yes, we should. I mean basically, the more wells that we have, the less amount of water each well has to take, which needs less energy it takes to push it down hole, et cetera, like that, so that gives us some savings there. And this gives us some redundancy, some fallback spare capacity. And then the ability to bring in some third-party water if we see that we got the excess capacity and moving water is important to us out there, and that's one of our main focuses to make sure we stay on top of that.

Ladies and gentlemen, that concludes today's call. Thank you all for joining. You may now disconnect.