Vital Energy, Inc. (NYSE:VTLE) Q4 2023 Earnings Call Transcript

Vital Energy, Inc. (NYSE:VTLE) Q4 2023 Earnings Call Transcript February 22, 2024

Vital Energy, Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day, ladies and gentlemen, and welcome to Vital Energy, Inc.’s Fourth Quarter and Full Year 2023 Earnings Conference Call. My name is Dessire (ph) and I will be your operator for today. At this time, all participants are in listen-only mode. We will be conducting a question-and-answer session after the financial and operations report. As a reminder, this conference is being recorded for replay purposes. It is now my pleasure to introduce Mr. Ron Hagood, Vice President, Investor Relations. You may proceed, sir.

Ron Hagood: Thank you, and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer; Bryan Lemmerman, Executive Vice President, Chief Financial Officer; Katie Hill, Senior Vice President and Chief Operating Officer; as well as additional members of our management team. During today’s call, we will be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts and assumptions are intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Our actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we’ll be making reference to non-GAAP financial measures.

Reconciliations to GAAP financial measures are included in the press release and presentation we issued yesterday. Press release and presentation can be accessed on our website at www.vitalenergy.com. I’ll now turn the call over to Jason Pigott, President and Chief Executive Officer.

Jason Pigott: Thank you, Ron, and thank you for joining us this morning. 2023 was a great year for Vital Energy as we drove change on multiple fronts. Throughout the year, we executed on our strategy to build shareholder value, expand our development portfolio, generate free cash flow and strengthen our balance sheet. In 2023, we achieved record production of 96,600 barrels of oil equivalent per day and oil production of 46,300 barrels per day, an increase of 17% and 22%, respectively, versus full year 2022 at lower than anticipated capital costs. 12 months, we increased our oil production by approximately 60%. For a full year 2023 net income of $695.1 million, adjusted net income of $325 million and cash flows from operating activities of over $811 million.

We closed six accretive Permian Basin acquisitions were $1.6 billion in cash and stock, adding approximately 88,000 net acres and 465 gross oil weighted locations, 280 of which were announced with the acquisitions, increasing inventory of oil weighted development locations to more than 10 years at current activity levels, an increase of 85% compared to the beginning of the year. We exited 2023 with a net debt to consolidated EBITDAX ratio of 1.09 times, which was 8% lower than the prior year end. Before we reduced Scope 1 greenhouse gas emissions intensity and methane emissions intensity of 38% and 65%, respectively, as of year-end 2022. Additionally, we were the first Permian operator to receive the third-party TrustWell certification for responsible operations, placing Vital Energy in the top quartile of U.S. onshore operators.

Our strategic shift to focus on entry into the Delaware Basin and expand into the Southern Midland Basin is paying off and the transition process is going extremely well. We are drilling wells faster, well costs are cheaper, and they are more productive than originally anticipated. Mostly (ph), we are transferring knowledge and technology across both basins, making us a stronger operator setting us up for more record breaking activity in 2024. Turning to 2024. We are entering the year in a position of strength as a result of our work to extend our bond maturities, reduce the amount drawn on the RBL and reduce our total leverage. We are pleased to confirm our prior guidance adjusted for the recently announced working interest additions of capital investment between $750 million and $850 million, with oil production guidance of 55,000 and to 59,000 barrels of oil per day and total production of 116,500 to 121,500 barrels of oil equivalent per day, plan to generate more than $350 million of adjusted free cash flow at current prices and our cash flow projections are supported by a strong hedge book.

Focus on further paying down debt and reducing our leverage ratio to less than 1.0 times throughout the year. Strategically, in 2024, we maintained focus on our core principles of generating free cash flow, reducing debt and leverage, expanding our development portfolio, advancing sustainability and integrating digital solutions. I will now turn the call over to Katie to provide an operational update.

Katie Hill: Thank you, Jason. Operationally, we had an extremely successful 2023. We consistently exceeded production expectations throughout the year, delivered capital investments below plan, successfully integrated six asset acquisitions, and established a core operating position in the Delaware Basin. Our team has extensive experience onboarding new assets and optimizing development plans, as we successfully demonstrated in our Howard County position over the past few years. We’ve gained experience with the asset, we refine spacing design, completion techniques and production methods. Bulk of our 2023 development was in Howard County, and the results showcase the success of this integration and optimization process. New wells in Howard regularly exceeded production expectations and we continue to drive execution efficiencies.

In the fourth quarter, we set company records in drilling, delivering a 10,000 foot lateral in 6.5 days and a record setting 7,716 drill feet in a day. We also set records and completions during the fourth quarter for daily pumping hours, stages per day and average transition times on a pad. Production processes brought on high-value production from wells earlier than modeled as we optimize pump sizes to dewater wells more quickly after drill out and to better recover from offset brackets. Our fourth quarter oil production driven by outperformance in Howard County and our recently integrated assets in Upton County exceeded the midpoint of our guidance range by 7% or 3,700 barrels per day. Two-thirds of the beat was driven by new wells delivering above expectations.

Other driver of our 2023 results has been the optimization of our base production. Last year, wells brought online prior to January 1, exceeded production expectations by 10%. It was accomplished through both process improvements and the continued application of optimization technologies. The end result has been faster and more targeted response times and increased mechanical run times across the field. This operating model has proved to be scalable, and we are improving results through integration of the Driftwood and Forge acquisition that we closed on in early 2023. Production from new wells on the assets is exceeding expectations by 10% on legacy Driftwood and 33% on legacy Forge acreage. We are early in the process of optimizing base operations on the properties, but are already exceeding production expectations on the legacy Forge asset by 4%.

We have also reduced well costs in the Delaware Basin by 12% versus what was assumed at the time of close through improved cycle time, supply chain optimization and well redesign. We are delivering wells more quickly for less capital and with higher productivity than expected acquisition, these results have been built into our forward-looking forecast and reflect continued year-over-year improvement. We onboard these assets, our teams are evaluating geologic data, cost assumptions and production results from our asset and from offset operators. Based on this work, we have organically added another 185 high return wells to the 280 originally included in our acquisition assumptions. In the Midland Basin, we added 65 Spraberry and Wolfcamp locations in Upton County through detailed technical evaluation that incorporated offset operator results and importantly, a robust data set acquired from a vertical well we drilled on our acreage that collected high-quality geologic data.

In the Delaware Basin, we added 120 wells in core development horizons across the position based on results from our recently completed wells and the improved economics from reducing well cost 12% since we began operating in the area. In 2024, we remain focused on organically adding low cost inventory through additional technical work and through increased opportunities to bolt-on acreage adjacent to our leasehold. Our capitally efficient development plan optimizes activity between the Midland and Delaware Basin. This quarter, we are bringing online several Delaware packages and a 20-well Western Glasscock package. Fluid production data from our recently turned in line Delaware wells continues to support our development plan. On the Midland Basin, Western Glasscock package, drilling and completion operations have gone very well, and five wells are currently flowing back.

Pressure on these wells is promising, and the package is already producing 3,000 gross barrels per day. Clients, the remainder of the package will be brought online over the next four to six weeks with peak oil planned for the middle of the second quarter. I’ll now turn the call over to Bryan for a financial update.

Bryan Lemmerman: Thank you, Katie. During the fourth quarter, we closed three previously announced Permian acquisitions and an additional transaction to increase working interest on a portion of the acquired properties. Our thoughtful approach to financing these transactions have significantly strengthened our capital structure. Recently, our bonds were upgraded by Moody’s and our bond yields have improved by around 175 basis points. 2024 budget is designed to generate substantial free cash flow, while growing full year average production versus fourth quarter 2023 volumes. Free cash flow is expected to build throughout the year with capital being highest in the first quarter and then coming down throughout the year. The capital progression is driven by first quarter activity being on higher working interest wells and as more activity moves to the Delaware Basin, the average working interest will lower, resulting in lower quarterly capital spend.

We are focused on further strengthening our balance sheet, and we plan to utilize free cash flow to reduce absolute debt and achieve our year end 2024 target debt ratio of 1.0 times. Debt reduction will be focused on our credit facility, and we expect the balance to be zero in the third quarter of the year. We believe we can achieve substantial benefits from utilizing free cash flow to reduce leverage, including lower future interest expense. In early February, we announced a second transaction to acquire additional working interest on some of our recently acquired Permian properties. Due to the shares issued in this transaction, our NOL carryforwards will likely be subject to 382 limitations. Importantly, we have been managing our utilization of intangible drilling credits and estimate that at current pricing and projected activity levels, we will not pay federal cash taxes for at least the next three years.

I will now turn the call back over to Jason for closing comments.

Jason Pigott: Hey, Bryan. To close, I want to reiterate that Vital Energy is a much different company today than we were a year ago. We are much stronger, and this would not have been possible without the talented team we have behind us. Operator, I will now turn the call over for questions.

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Q&A Session

Operator: Thank you. The floor is now open for your questions. [Operator Instructions] Your first question comes from the line of Neal Dingmann, Truist Securities. Your line is open.

Neal Dingmann: Good morning, all. Nice quarter. Just my first question, maybe both of them are going to be around maybe Slide 9 and 8. First, maybe some of you and Katie said that on both of these. Could you maybe start on Slide 9, like, where you show about the successful integration of the properties. And I’m just wondering, now that you’ve done that, when you look at both now the mixture of the [indiscernible] recently added Delaware as well as the Midland Basin. I mean, has that changed? I know you’ve got the four rig focus this year. Could you maybe talk about how you plan to attack that now that you’ve got all the assets sort of working together?

Katie Hill: Sure. Good morning, Neal. This is Katie. We had — throughout the year, this year, we’re planning to run, like you said, a four rig program, and we’re continuing with our strategy, of course, of drilling our best wells next. So as we think about the capital allocation throughout the year, we’ll shift a little bit more heavily into the Delaware in the second half. There’s some really good opportunity as we’ve closed on the assets and integrated them. We’ve been able to optimize the plan this year, and we’re excited to get some capital deployed in that area. As we think about moving into ’25, there’s still some really great investment opportunity in the Midland. So we’ll continue with that mix of Midland Delaware Basin and try to optimize across the two assets throughout the next couple of years here.

I think there’s additionally quite a bit of opportunity in the Delaware that we’ve built into the plan around our production optimization work. As you mentioned on Slide 9, you can see that we’ve outperformed on base production assumptions early in the Driftwood and Forge assets from early 2023. And as we think about deploying that technology and base optimization work across the three assets we closed in the second half of the year, that will continue to support the 2024 plan and the projections that we have out there. So I think a really good opportunity for us across the basin.

Neal Dingmann: Yeah. Great details. And then just a follow-up, looking actually at Slide 7 or 8, where you talked about additional zones and then you show the sort of cost reductions. I’m just wondering something you had mentioned when you now tackle, I guess, what do you all view as sort of the optimal project or optimal pad size? It seems like for even being a smaller operator, you’ve all been able to walk that up and capture some efficiencies. So again, I guess when I’m looking at these two, just wondering like when you co-develop now, how big of projects are optimal and you think makes the most sense for you all?

Kyle Coldiron: Yeah, Neal. This is Kyle Coldiron. So I think the answer really depends on the area and kind of the stack pay that you have. So if you look at our Western Glasscock package that they have coming online right now, essentially, that’s kind of two very large pads that — where we drilled those 20 wells. And one of the great benefits of that was that we were basically able to park our Halliburton fracture there and complete 10 of those wells without ever having to move the fleet. So just the efficiency really skyrockets from those big pads. As we move over to the Delaware side, we tend to drill a little bit smaller pads kind of in the three to five type of range. Ultimately, a lot of that has to do with just our well spacing assumptions over there and what targets we’re hitting.

So I think to your question, it depends on the area, but across the board, we are a continuous improvement culture on our operations team, and we’ve been able to drive both drilling and completion costs down across both basins. I think as you can see in the materials that we shared today.

Neal Dingmann: It makes sense. Thanks for the details. Great job, guys.

Jason Pigott: Thanks, Neal.

Kyle Coldiron: Thanks, Neal.

Operator: Our next question comes from the line of Zach Parham with JPMorgan. Your line is open.

Zachary Parham: Good morning. Thanks for taking my question. I guess, first, can you talk a little bit about the inventory additions in the Delaware. In the Midland, it seems pretty clear. You added two additional zones based on some industry activity around you. But can you detail exactly what you added in the Delaware and kind of, how that fits into the program going forward?

Jason Pigott: Zach, good morning. It’s Jason. I’ll take a stab, and then I’ll hand it over to Kyle. I mean one of the things that we’ve done repeatedly is add inventory after we’ve completed acquisitions. You saw it in Howard County when we added the Middle Spraberry. In Western Glasscock, we added the Wolfcamp B, and that’s a zone that’s being completed today on those large pads we’ve got out there. So as you mentioned, again, we’ve added Lower Spraberry and Wolfcamp A in Howard — sorry, Southern Midland. We took core data that should indicated to us these zones would be good, and then we had offset operators that brought those online and confirmed what we saw in the geology. We would develop them a little bit differently than some of the offsets were they lined wells on top of each other where we would stagger them.

So we think there’s some upside even to those results that you could see out there. We go to Delaware, that’s driven by costs. And when you reduce well costs from $12 million to $10.5 million, that improves economics of every well in the field. when your production performance is 33% higher, that improves economics of every well out there. So it’s, again, improving total returns across all those areas. And I think the other thing too is, I mean, we’ve got other zones that we’re going to be testing this year. We’ve got the Wolfcamp C, which we’re going to be test — is coming online today in Western Glasscock. That’s a totally new zone for us that could add future inventory or future earnings calls. So we’re putting a full court press on testing multiple zones across both the Midland and Delaware to, again, continue to increase inventory over time.