Ranger Oil Corp (ROCC) 2022 Q2 法說會逐字稿

Good morning, and welcome to the Ranger Oil Corporation's Second Quarter 2022 Earnings Conference Call. (Operator Instructions) Please note, this event is being recorded.

I would now like to turn the conference over to Ranger's Senior Vice President and Chief Financial Officer, Rusty Kelley. Please go ahead.

Good morning, and thanks for joining us today to discuss our second quarter results and the strong progress we've made year-to-date to create lasting value for our shareholders. I'm joined today by our CEO, Darrin Henke; and our COO, Julia Gwaltney. We'll be happy to take your questions at the end of the brief remarks today.

Please note that we'll discuss certain non-GAAP measures on today's call. Definitions and reconciliations of these measures to the most comparable GAAP measure are provided in our second quarter earnings release and presentation, which can both be found at www.rangeroil.com. Our comments today will also contain forward-looking statements within the meaning of federal security laws.

These statements are subject to a number of risks and uncertainties that could cause actual results to be materially different from those forward-looking statements, including those identified in the risk factors in our annual report on Form 10-K and quarterly reports on Form 10-Q.

I'll now hand it over to Darrin.

Good morning, everyone, and thanks for dialing in. Ranger has executed extremely well year-to-date. Yesterday, we published strong second quarter results, along with an updated slide deck. I hope you've had a chance to review these materials.

In less than 2 years, we've transformed Ranger into an E&P leader and now have all the key ingredients for premium market valuation. Simply put, we are answering the call for what investors are looking for from the E&P sector today. First, our business strategy is well defined.

We have flexibility to deliver value through multiple vehicles. These include strategic and accretive acquisitions at the right price. Disciplined capital investments within a strong balance sheet, organic and profitable growth, operational expertise that creates synergies and strong returns and a clear framework to return cash to shareholders.

We recently expanded our cash return framework. Our Board reloaded our share buyback program, increasing our authorization to $140 million and extending the program through June 2023. Year-to-date, we have repurchased more than 3% of our outstanding stock and remain active in the market today. At current valuations, we see repurchasing our shares today as a very compelling investment.

Due to the strength of both our performance and capital structure, we accelerated the timing of our inaugural quarterly dividend and increased its planned initial payout. Our Board declared a quarterly dividend of $0.075 per share payable August 4.

Our balance sheet has continued to strengthen. Our leverage ratio dropped to approximately 0.8 at the end of the second quarter as we reduced our debt by an additional $50 million in the first half of the year. Second, recent bolt-ons have created significant value.

We are incredibly excited about the 8 strategic and highly accretive bolt-ons announced this year. These transactions, which closed late in the second quarter and early in the third quarter, added about 20,000 net acres and transacted at a discount to our estimate of the proved developed PV-10 value of the assets. Combined, their initial purchase price totaled about $139 million and were funded substantially through cash flow.

Our team has been laser-focused on finding attractive opportunities within our Eagle Ford footprint. Because of their fit and our operating capabilities, we expect strong returns through synergies, increased working interest, longer laterals and the utilization of existing infrastructure. Please refer to the map in today's presentation to see our expanded footprint.

A healthy deal flow exists in the Eagle Ford today. We've been able to selectively screen for transactions where we see opportunities to lower costs and improve cycle times to access premium markets and generate free cash.

The operational synergies inherent in these transactions mitigate the need for additional rigs and services, thus improving certainty in our cycle times and helping offset inflation. We have proven our ability to find and close deals that create meaningful value.

Next, we have a deep inventory of high-return future drilling opportunities. Our recent bolt-ons strengthen our already deep inventory. We have an estimated 20-year inventory at today's commodity prices, which equates to about 1,000 locations, primarily developing the Lower Eagle Ford Shale. Lastly, we are operating in one of the best basins in the United States. We have an exceptional team of people at Ranger today focused on continual improvement in everything we do.

Our results are among the best in the Eagle Ford and stack up to anyone. That being said, all basins are not created equal. The Eagle Ford is one of the most attractive basins in the U.S. due to its high oil cut existing infrastructure, close proximity to premium-priced Gulf Coast markets and an efficient regulatory framework. These attributes yield a superior margin.

In today's slide deck, there's a slide that highlights our EBITDA margin compared to public E&P peers, sorted by basin. As you will see, we are certainly advantaged due to our high margin.

We delivered strong financial performance in the second quarter, exceeding analyst expectations during the period. Our pro forma adjusted free cash flow was $62 million, and we had net income of $148 million. Adjusted EBITDAX was $190 million. Production once again came in at the upper end of our guidance range. Total sales were about 38,500 barrels of oil equivalent per day and our oil sales were about 27,500 barrels per day. Costs and expenses were all within previous guidance ranges.

There is no doubt that inflationary pressures are real today. However, I am exceptionally proud of how our team has managed our business against those pressures. For the second quarter, our drilling and completion capital investments were $122 million as we found innovative ways to mitigate higher costs.

Let me talk a little more about our 2022 outlook. Our capital plans for the remainder of this year fall into 2 key areas. First, we expect the capital for our initial 2022 drilling and completion program to remain within our original guidance at $425 million, which included adding a third spot rig in the second quarter to develop a couple of high-return pads in LaSalle County. This temporary drilling and completion activity will conclude in the third quarter, and we expect to drop back to a 2-rig program for the balance of the year.

At current commodity prices, we believe these spot rig investments will reach payout in about 1 year and will be additive to our 2023 forecast. Second, because of our ongoing operating efficiencies driving accelerated development activity, combined with increased working interest and longer laterals associated with the recent bolt-ons, we expect about $30 million of incremental drilling and completion capital. These investments are expected to increase our volumes in late 2022 and provide us with considerable momentum as we enter 2023.

With the incremental drilling and completion CapEx, our new annual CapEx guidance range is $440 million to $470 million. More detail on our capital program can be found in our slide deck and earnings release. As we look to 2023, we are evaluating the addition of a full-time drilling rig to next year's development program, expanding our historical 2 rig fleet to 3 rigs.

In summary, we continue to make disciplined investments in the Eagle Ford while carefully screening for accretive acquisitions that allow us to build future value.

Our investment levels have allowed us to both reduce leverage and meaningfully expand our cash return framework for investors, creating a winning recipe, especially on a per share basis, one that we believe is sustainable and will ultimately lead to a premium valuation.

That concludes our prepared remarks today, and we are happy to take your questions. Operator?

(Operator Instructions) Our first question is from Neal Dingmann with Truist.

My first question, I was just wondering if you could speak on kind of more maybe just for modeling. I was trying to get a sense for if you could speak to the upcoming cadence of maybe some things of kind of how you're looking at spending and maybe same for production in D&C as well to get a better idea of how we might want to shape that through the -- into the end of the year.

Yes. Thank you, Neal. I'd be happy to address that. So we picked up the third spot rig in the second half of the second quarter, and it's drilling its last well currently. We'll then complete those wells and get those online about the end of the third quarter. So you see an increase in capital relative to the first quarter and second quarter due to the third spot rig, most of that capital being deployed in the third quarter. You'll see the benefit of that capital in -- primarily in the fourth quarter and in 2023 as we bring those wells online. And so you'll see a nice increase in our guidance for the fourth quarter if you work through that math on production. And also in the fourth quarter, you'll see our capital pull back more similar to the first half of the year versus the third quarter. Does that answer your question, Neal?

Well, that does and I'm just wondering, is it -- I know you don't have '23 guide, I'm not looking for any specific. Is that type of spend also as you get into '23? Or is it just still too early to determine that, that [what] you're talking about this. For the year-end, you talked about in 4Q spending maybe going down a little bit. So maybe for you, Russ, I'm just wondering, I know, again, being cognizant of not having '23 out there, anything we can think about that 4Q plan into '23.

Yes. So as we're thinking about '23, as we said, we're considering adding a third full-time rig to our 2-rig fleet which will, of course, materially increase capital, but it also will grow our production materially. With the -- if we stay at kind of our 2-rig program, we're going to have production growth in '23 probably in the mid- to high single-digit range. But if we had a third rig and it depends when we add it, of course, next year. But if we add it fairly early in the year, we're going to be looking at double-digit production growth annualized ['23 versus '22] kind of in the low to mid-teens would be what we would see there from a production growth standpoint.

So certainly excited about the opportunity to add a rig. It's a lot more than just adding the rig. We got to look at all the services, be it pipe, frac services, sand, et cetera, we got to make sure the entire supply chain is there and ready to support that third rig because we certainly want it to perform at similar levels as -- from an operational efficiency and execution standpoint as our 2 rigs that we have in our fleet today.

Great to hear on the production growth. And then lastly, Darrin, it sounds like out there, I'm hearing some what I would call pretty exciting chatter in the market on the Austin Chalk. I'm curious as you could give maybe your view or plans specifically to your -- on that play.

Yes, there's definitely some recent highlights in and around our legacy acreage in Gonzales and Lavaca Counties. There's been 2 recent completions wells by 1 by COP, 1 by EOG that have pretty exciting cumulative production rates at this point. There's 2 rigs that have recently been brought in 1 by EOG and 1 by BP to drill offsetting our acreage to drill Austin Chalk wells, and we submitted a permit for an Austin Chalk well. Just this week, we filed an application for permitting to drill a well perhaps late in the year or next year.

So a lot of things going on in the Austin Chalk in and around our acreage. And as we've said before, we intend to really study what the offset operators are doing and when it makes sense from a risk-adjusted returns basis. So we certainly have a lot of running room in the Austin Chalk as well.

The next question is from Michael Furrow with Johnson Rice.

So just a quick one. In regards to these 8 bolt-ons, during the year, are these smaller transactions being targeted because there's a lack of larger scale M&A opportunities in the basin or possibly some disconnection between buyers and sellers in the current market?

We've been successful, I think, with the bolt-ons. Just when you look at the size and the fact, they really create synergies for Ranger Oil that they may not for other operators due to how they fit in and around our existing position. And so these tactical opportunities, there's a number of them out there. We've executed on 8 already to date, and there'll be -- there'll likely will be more to come next quarter and beyond.

When you look at M&A across the broader Eagle Ford, there's a lot of opportunities at all different sizes. And I think when you're above $100 million kind of the $100 million to $500 million range, there's a lot of competition from other entities, other parties that are working to -- that are willing to pay up in an effort to create scale for their entities, for their companies. And we think that's going to be a tough marketplace to compete in, but we will absolutely be at the table and we'll certainly be looking at those opportunities.

There's also larger opportunities that are available where we think there's less competition. And so we talk about a barbell approach that being the tactical bolt-ons and then the larger transactions where we think Ranger will have the best odds of success of continuing on the M&A front.

The next question is from Davis Petros with RBC.

The first one, and maybe for you, Darrin, it's just kind of how do you think about kind of free cash flow allocation going forward? It's been nice to see you all back with the buyback program and kind of reloading that through mid-next year. But how should we think about when you all want to step in to defend the stock and kind of keep that buyback pace versus using free cash flow for more of these tactical bolt-ons to enhance returns going forward.

Yes. When we think about the allocation of free cash flow, we really see 4 buckets, 4 pillars that we focus on. It's potentially paying down more debt. It's additional organic investment, return of cash to shareholders via the dividend or share repurchases. And then, of course, additional accretive strategic acquisitions. And with the free cash flow that we're generating, it's not an either/or, it's really both and we're doing all of these things this year. All 4 of these were allocating free cash, and we see that -- we think that will be the opportunity in the future as well. So it's -- our commitment to our shareholders on a risk-adjusted basis, we will invest our dollars where there's the most accretion, the most value for our shareholders.

Got it. Good to hear all good options. And kind of a second one, you talked about a little bit in your prepared remarks, but it's nice to see you all have been able to kind of keep managing inflation to keep it within that, that upper end of the initial budget. But just kind of if you can expand on maybe anything specifically you all are doing on that front, what's been keeping costs maybe better relative to peers? And then again, kind of as we look into 2023, recognizing you all don't have guidance out there, but is there any kind of any color you can provide on maybe how drilling longer laterals post these recent acquisitions? Can you maybe add some efficiency gains to next year's program like this year is where you can run at maybe a 3-rig pace and get a little bit more or a little less spending, I guess, for that amount of growth, if that makes sense?

Yes. Yes, I've heard a couple of questions in there. I'll start digging into them and Julia might be able to help me out as well. So when you think about inflation and how we've managed it year-to-date, we're drilling materially longer laterals this year than the last few years. And so that ultimately drives down the dollar per foot that we spend on our wells.

We've also increased the pump rate on our frac jobs, and that's allowed us to lengthen out the stages, which reduces plugs, reduces the time on location fracking the well. So that's also another efficiency gain that's helped us mitigate inflation.

As we look forward in the second half of the year, we're going to be transitioning from 5.5-inch long stream pipe production pipe to 6-inch casing. That's going to allow us to even pump higher rates on our frac jobs and lengthen the stages out even further. So again, providing additional efficiencies that will keep our costs in line for the second half of the year. The bolt-ons, not only did we pick up additional working interest in existing wells. So you're really increasing our capital program without having to add rigs just by increasing your interest in the wells that you're drilling.

We're also increasing lateral lengths because that acreage -- the wells that we have planned later this year will drill across from our legacy acreage onto the new acreage that we bought via the bolt-ons. So again, longer laterals, greater efficiency, reduces the dollar per completed lateral foot. We intend to look at all those options plus many more. And when we think about 2023 and that program, it will -- you'll see increased lateral lengths probably again year-over-year going into next year.

Got it. Good to hear. And kind of just one last thing to take on to that. Do you have any color on maybe what leading edge inflation is looking at kind of in rigs or services when you're maybe considering looking at adding a third rig in the next year?

We've -- it's tough to predict where inflation will go with commodity prices where they're at. We haven't seen as much pressure as much increases as of late than what we saw earlier in the year. So hopefully, that's a good sign for us that maybe inflation will be -- we'll stay where it is, and it will be in check. But really too early to predict. But I can assure you we're staying on top of it. We're testing the market for value is what we think about when we're choosing service partners. It's not necessarily the lowest cost provider, but the best overall value looking at their efficiencies, their ability to execute our program and our plans and then what that will cost us. So we're on top of it and too early to tell for sure, but I hope we're starting to see some signs of abatement.

(Operator Instructions) The next question is from Nicholas Pope with Seaport Research.

Kind of following up on those inflation comments. Kind of curious on the operating cost side, kind of what the drivers are? It seems like you're seeing more on the LOE relative to the gathering process, which seems like it's fairly flat with kind of the previous guides. I'm just kind of interested in what the components are and where you think you are on the operating cost side of the inflation profile?

Yes. Thanks for asking the question. That gives me a chance to really highlight our production team and the great work that they're doing and identifying workovers. Where we were last year, we ran about 1 workover rig consistently in the field, and that jumped between doing capital work, running tubing, part of the drilling program and staying on the workover expense side.

In the second quarter, we added a second workover rig because we had so many projects identified. These are great projects on average payout in less than a month, get wells back online, lower the risk of us meeting our objectives and delivering on production as well as finding opportunities to slightly increase, continue to feed that pipeline of opportunities. And just this week, we added a third rig. So an additional expense for the projects pay out extremely quickly, it's a really good piece of business and hats off to our team for continuing to push it forward.

I'm not sure if more activity is if I'd classify that as inflation. It sounds like -- I mean, as you look at that, it sounds like there is a lot more activity that you're doing kind of production maintenance type work. Is that kind of where that wedge is on the LOE that seems to be having been at it? Is that how I should interpret that?

Yes, it is a component of it. We'll continue to look for opportunities to stabilize our base, flatten our base decline. There is a cost component to it as well. Fuel, everybody is aware the fuel prices has gone up. It's hard for us to complain much about that, but it is a component of our operating expense as well.

This concludes our question-and-answer session. I would like to turn the conference back over to Darrin Henke for any closing remarks.

In conclusion, I again wish to thank all the Ranger employees and contractors for their tireless efforts and relentless pursuit of excellence, which are directly contributing to 2022 shaping up to be another transformational year for our company. Between the strengthening balance sheet, debt reduction, the implementation of both the share repurchase program and dividend and the multitude of acquisitions already closed this year, Ranger is truly firing on all cylinders. We look forward to seeing many of you on our upcoming [non-deal] road shows. Thanks for joining the call today.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.