REPX - AMEX

Thank you, and good morning. Welcome to our conference call covering the second quarter 2023 results. Yesterday, the company published a number of items, which can be found on our website under the Investors section. A Form 10-Q, a summary earnings release, supplemental info on non-GAAP measures and 2 presentations, one of which provides an update for second quarter results, with the other providing a company overview. Participating on the call today are Bobby Riley, Chairman and CEO; Kevin Riley, President; and me, 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'll also reference certain non-GAAP measures. These 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. Good morning, and a warm welcome to all participants on our Q2 2023 earnings call. We are pleased with the results of the second quarter, which reflects record-high metrics across production and cash flow from operations. As we reflect on the past quarter, I want to spotlight the following accomplishments: number one, we closed on the acquisition of oil and natural gas assets in New Mexico and successfully transitioned operations to the company; number two, we averaged oil production of 15,100 barrels per day or 21,200 barrels of oil equivalent per day; number three, we generated $66 million of adjusted EBITDAX and $56 million of operating cash flow; and lastly, we paid dividends of $0.34 per share for a total of $7 million. These achievements highlight our dedication to strategic growth and operational excellence. We look forward to providing a more comprehensive overview of our performance throughout this call. Thank you for your continued interest and support. I will now turn the call over to Kevin to discuss operational results for the quarter.

Thank you, Bobby, and good morning. The team successfully implemented our plan in the second quarter, including the integration of the New Mexico assets. The results of the quarter reflect both the performance of our legacy assets and the newly acquired assets. As Bobby previously mentioned, our production reached peak metrics during the second quarter. Total equivalent production of 21,239 BOE per day, a year-over-year increase of 109% and quarter-over-quarter increase of 61%. Oil production of 15,055 barrels per day, a year-over-year increase of 80% and quarter-over-quarter increase of 52%. The increase in production is attributable to the impact of the acquired assets as well as organic growth. Consistent with prior guidance, the company drilled 8 gross horizontal wells during the second quarter, including 4 wells in Texas and 4 wells in New Mexico. The company completed 5 gross 4.2 net horizontal wells during the quarter, including 4 wells in Texas and 1 well in New Mexico. The company turned to sales 6 gross, 5.2 net horizontal wells during the second quarter 2023. The company incurred $39 million in total accrued capital expenditures before acquisitions for the second quarter, lower than the company's previously released guidance due primarily to deferred completion activity. On a cash basis, the company had total capital expenditures before acquisitions of $48 million for the quarter. Riley is committed to operating efficiently, both on its legacy assets and the newly acquired assets in New Mexico. Since closing the acquisition, we have identified opportunities to optimize production in New Mexico through well remediation efforts. Those efforts resulted in our LOE per BOE coming in just outside the high-end range of guidance at $9.06 per BOE. Additionally, the company progressed its efforts on the build-out of its on-site power generation joint venture. We are targeting an in-service date for the initial phase during the latter part of the current quarter. Lastly, regarding cost, we continue to see a slight decrease in service intangible costs as compared to 2022 and hope to see continued benefits from that in the second half of the year in 2024. With that, I will turn the call over to Philip to discuss the financial results. Thank you.

Thank you, Kevin. For the second quarter 2023, we're reporting operating income of $45 million and net income of $33 million or $1.65 per diluted share. Operating cash flow for the 3-month period was $56 million or $51.5 million before changes in working capital, the latter of which was up by $14 million or 38% quarter-over-quarter. The primary driver of the increase is the higher production volume from both organic development and the new acquisition assets. Quarter-over-quarter realized oil prices were down about 2%, while realized natural gas prices were down 96%, and realized NGL pricing was down 26%. The low natural gas and NGL realizations are a function of having some fixed midstream fees tied to volumes which are exacerbated when market prices are very low, like we experienced in the second quarter. On an absolute basis, natural gas revenue was down by less than $0.5 million, while NGL revenue increased. Oil makes up 98% of our revenue. Interest expense was materially higher than the prior quarter as to be expected as we use debt to finance the acquisition. Operating cash flow also includes $3.6 million of transaction expenses related to the acquisition. Year-to-date, we've accrued $81 million of CapEx with $83 million of cash CapEx. For the quarter, cash CapEx was $48 million, about $9 million higher than accrual-based CapEx. Last quarter, we had the opposite dynamic where cash CapEx was lower than accrual. This will vary quarter-to-quarter, so it's not surprising to see. As Kevin described, we had a very high level of development activity in the quarter, both in Texas and New Mexico, which led to the strong production levels reported as well as to the higher level of CapEx, which was still meaningfully under guidance. We took over the New Mexico asset only in early April, which had been idle with development activities since the end of last year. So it was important to us to start a development right away in order to have a good level of average production for the year. In a normal or ideal year, we would have activity in that first quarter as well, smoother throughout the year, or is effectively loaded in the second quarter in this year. Given a large amount of activity completed to date and corresponding good results, we've reduced our remaining activity level and CapEx for the end of the year. We'll have a fair amount of activity continuing into the third quarter with forecasted accrual CapEx of $35 million to $40 million. Combining this third quarter estimate with the $81 million accrued year-to-date, that would correspond to approximately 90% of our full year CapEx guidance range of $130 million to $140 million through the third quarter. So based on that, you can see we currently forecast very modest activity in the fourth quarter. When viewed then on a full year basis, which is how we encourage investors to look at most metrics, we believe our reinvestment ratio of CapEx to operating cash flow will appear more reasonable and closer to last year's level. Connecting this to free cash flow, we report this metric using cash CapEx. We also include cash items like transaction costs, which some companies exclude. So as anticipated, free cash flow for the quarter and year-to-date has been modest at $3 million this quarter or $5.5 million year-to-date. This has been driven by the concentrated development activity, combined with operating cash flow impacted by softer commodity pricing in the first half of the year. We're optimistic that full year free cash flow will balance out with the lower spending levels in the back half of the year, especially in the fourth quarter, with excess cash flow beyond the dividend for incremental debt paydown. I'll end by pointing out a few items on our balance sheet given some notable additions from last quarter. At quarter end, we had $394 million book value of debt or $410 million principal value of debt. The difference between the 2 is primarily attributed to the discount on which the notes were issued and deferred financing costs. I'd also highlight that $20 million of the notes is booked as a current liability, this is due to the fact that we have a quarterly principal payment of $5 million. As noted on our prior call, we like this feature as it offers a regular paydown mechanism without the customary premium or make-whole. I'll now pass it back to Bobby for closing.

Thank you. And again, we value your time and interest in our company. As always, we are focused on creating value for our shareholders and look forward to updating on our progress in the next quarter and beyond. Operator, you may open the call up for questions.

[Operator Instructions] Your first question comes from the line of Neal Dingmann of Truist Securities.

My first question is on capital efficiency, I would say, specifically, appreciate the updated guide to be able to limit even more so now spending, though maintaining that stable production and ultimately resulting in what appears at least in our model as well, increased free cash flow. I'm just wondering, could you remind me either through, and how your D&C has improved along with maybe the base decline? Or what are some of the other drivers maybe, Bobby, for you and Kevin, on what -- or even Philip, on what's sort of driving this?

So for last quarter, our results were driven largely by the acquisition of the Red Lake asset or Pecos, in addition to organic growth. If you disaggregate them and break them down, I would say the legacy asset did grow substantially quarter-over-quarter to the tune of about 10%, but that was due to the completions that we brought online late in Q1 and Q2. As far as drilling efficiencies or capital costs, we're continuing to see price decreases, particularly on steel products and some services like completions. Unfortunately, we're still working off the inventory that we had acquired in late 2022 to procure development opportunities for 2023. So we're not able to fully realize that benefit yet, but we do anticipate later in this year and into 2024, starting to see the benefits of those price reductions.

Yes, I look forward to that, Kevin. Great details. And then my second question, just maybe on overall infrastructure. I know there's always sort of ebb and flows on infrastructure. Are there different proactive steps you all can take going forward to help and mitigate any downtime with any of the vendors, or is it just sort of how the field plays maybe just anything you can say just on generally specific -- I'm sorry, generally around just sort of infrastructure in Texas, New Mexico, et cetera.

In Texas, we have worked with our midstream partner out there, and they're currently doing a second or maybe a third expansion to the midstream facilities to further facilitate additional flow which we anticipate that coming online, let's say, early to mid-2024. In addition to that, we have announced and are working on the on-site power generation, which provides for usage of our gas in the event there is no capacity, and we hope to expand that same thought process or initiative over into New Mexico. New Mexico, we've had a few disruptions, which we've mentioned. Largely, there was a fire in Q2 -- or no, I think it was October of 2022, which DCP had announced that their Kristina Booster Station, which they had done some maintenance for repairs for that, and that's been since put back online. So we're working in the right direction to provide more stability in the New Mexico and Texas as far as midstream goes.

Your next question comes from the line of Noel Parks of Tuohy Brothers.

Just had a couple of things. I was wondering on the cost side, the bits of sort of hope we see on the horizon with inflation leveling out and maybe even going back the other way. I'm just curious, as far as what you can tell the drivers of that might be up in your region, is it mainly just service companies seeing a little bit less confident about the rig count going forward and considerable utilization, or any other factors you see that seem to be helping.

I think there's probably a combination of that. Rig costs have softened a little bit. But if you think about our wells, we drill them in 10 to 11 days, so you change from 15,000 to 14,000 a day. It's not a substantial savings, but it is savings. Where we've seen the most is completions and -- on tubulars. Tubulars, in some cases, various sizes all differ due to availability and demand. But -- and some pipe that we use a lot of, I've seen prices drop as much as 50%, which that makes a difference in the well cost.

Great. And actually, that brings to mind a question between some of the vertical drilling you're going to have on the plate versus the horizontal from your legacy Texas acreage, a lot of it. The proportion of completed well cost that works out between the drilling part and the completion part. Can you just give me a feel for what that breakout is like these days?

So we are not currently doing any vertical development as far as producers go. We have drilled some injection wells for CO2 and for water that are vertical. But on a completion well or a horizontal well, I would say the current breakout is approximately 35%, which would truly be drilling cost, and then post drilling for completion tubulars facilities, the balance about 65%.

Okay. Got you. And one other thing just talking about activity up in your part of the basin. If we had this uptick in oil, and I was just wondering, has anyone out there among your peers that you know and sort of just plowing ahead with a drilling program whether there was a 6 handle on oil or an 8 handle on oil? Or have you seen most of the peers being sort of opportunistic like you sort of looking at hedging possibilities, what their activity levels optimized might look like, et cetera?

I don't think that our areas in particular have seen a lot of activity driven at the high pace and not slowing down regardless our -- our areas are mostly HBP in Texas and New Mexico, so it provides a lot of flexibility. And unless one of our peers is preparing for some sort of divestiture, they're not necessarily just out drilling to drill.

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

This might be one of those questions it's way too early to ask, but Kevin or Philip, when you think about putting together a program in 2024, can you just talk about the benefit of owning 2 assets maybe being able to deploy capital over a steadier operating plan as you think about setting up your program next year?

Yes. Sure, Jeff. That's exactly right. That was one of the initial attractions to having a diverse set of assets, similar in style but diverse and geography. We can smooth that out. You've seen a bit of concentrated spending we had this quarter. So that's absolutely the plan. We do drill these wells very quickly, as Kevin was just describing. So that's a positive. But as for spreading things out, when you get a rig, it's most efficient and you achieve the most cost savings on an absolute basis if you do those all back to back. So one possibility of spreading activity over a quarter, starting it towards the beginning or end and you straddle a quarter like that. We can also spread out drilling and completions just a bit. But in general, we're pretty excited about 2024. It is early, as you say, but we're already getting to a materially better place with effective margins. If you think about where we were for the -- a lot of the second quarter, we had low 70s pricing, $67 pricing for a while. And the well costs were still stubbornly high that the industry was experiencing, right? As Kevin was describing, you had some holdover from commitments made during that peak pandemic supply chain tightness and sets high pricing. Since then, you've seen those come down. As Kevin described, you've seen the steel come down dramatically from China. And then at the same time, we've got a roughly $10 increase in the oil price, and so that makes a dramatic difference. So we're -- like I said, it's early, but we're excited about 2024 and that we can get some attractive margins and overall free cash flow.

Just one other question. On the 4 wells that you all have planned to drill in Texas in the third quarter, would those be expected to be completed and producing in the fourth quarter of '23?

We currently plan to have 3 of those wells producing in Q4, and we have commenced those drilling operations on the first well, but our current intention is to potentially carry a [DUC] over into 2024.