Granite Ridge Resources, Inc.

Good day, ladies and gentlemen, and welcome to Vital Energies, Inc. Third Quarter 2024 Earnings Conference Call. My name is Jericho and I will be your operator for today. At this time, all participants are in listen-only mode. We will be conducting question and answer session after the financial and operations report. As a reminder, This conference is being recorded for replay purposes. It's now my pleasure to introduce Mr. Ron Higgett, Vice President, Investor Relations.

You may proceed, sir. Thank you and good morning.

Joining me today are Jason Paget, President and Chief Executive Officer, Brian Lemmerman, Executive Vice President and 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'll 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 four looking statements for a variety of reasons, many of which are beyond our control. In addition, we will be making reference to non-GAAP financial measures. Reconciliations to GAAP financial measures are included in the press release and presentation we issued yesterday afternoon. Press release and presentation can be accessed on our website at www.vitalenergy.com. We'll now turn the call over to Jason Paget, President and Chief Executive Officer.

Good morning, and thank you for joining us today. We are delighted to announce that Vital Energy has delivered exceptional results in the third quarter, surpassing our expectations. Our recent strategic acquisitions, particularly the transformative point acquisition, have propelled us to new heights. We reached a new production record during the quarter and our cost reduction initiatives are significantly improving our cash flow before we take your questions today I'll cover four key items. First, some quick highlights from the third quarter importantly recent results will increase our fourth quarter production outlook. Next, I'll provide additional information about our recent point acquisition. This asset has exceeded expectations early on and provides us with the luxury of adding activity in a higher productivity area in 2025. Then I will discuss how our team is continuing to improve and extend our inventory. Lastly, I will share some early thoughts on our 2025 outlook. While we won't share full details until early next year, We expect to build on the strengths we've reinforced with our third quarter results. Now let's talk about the third quarter. Our financial results surpassed expectations driven by higher than expected production, inline capital, and a solid demonstration of our ability to lower operating costs over time on acquired assets. For the quarter, both standalone vital energy and the point energy assets delivered at the high end of production expectations, combining to produce about 59,200 barrels of oil per day. Our oil production guidance for the quarter was 55 to 58,000 barrels of oil per day and did not include any volumes for point. However, the team did a great job to close this transaction early, giving us a boost for the quarter. If it weren't for some weather-related flooding in Howard County, which caused approximately 650 barrels of oil per day to be shut in, our beat would have been almost 6% altogether. To help demonstrate why we are so excited about the point transaction, we have a slide in today's deck with two charts showing point production surpassing underwriting expectations for both base production and on a new 10 well package. Additionally, These wells were completed with an optimized frac design on wider spacing than the previous operator, paving the way for us to develop this asset at a significantly reduced cost compared to the prior operator. Lease operating expenses substantially improved during the quarter, coming in at $878 per BOE, below guidance of $895 per BOE, a 9% improvement over our second quarter operating expense. These costs are inclusive of higher LOE related to the point assets. Excluding point, LOE would have been just over 870 per BOE. In the third quarter, we delivered on our planned reduction in operating costs through several targeted initiatives aimed at improving efficiency and optimizing resource use. Key projects included optimizing our work over fleet and transitioning several rigs to 24-hour operations. which reduced downtime and improved cost efficiency. We also implemented changes to our H2S chemical processing and introduced chemical improvements across both the Midland and Delaware basins, reducing material costs and improving product quality. Throughout the quarter, we made strategic labor and staffing adjustments to better align with the long-term base operational needs. We continue to use our cross-basin scale to support a cost-effective power strategy and have locked in a significant portion of our power costs through hedging to reduce volatility and de-risk future cost pressure. These combined efforts have delivered substantial cost savings, enhancing our overall profitability and positioning us for sustained operational efficiency. Capital investments for standalone vital energy were $236 million for the quarter within guidance of $215 to $240 million. The early close of point resulted in $6 million of additional capital in the quarter, resulting in a total capital expenditure of $242 million for the quarter. The momentum from production outperformance and cost savings will carry into the fourth quarter. We have increased the midpoint of our oil production guidance by 1500 barrels of oil per day and 3000 BOE per day of total production while reiterating our previous capital guidance. Since April of 2023, we have completed six acquisitions and have fundamentally changed our Permian Basin footprint, growing our Delaware position to almost 90,000 acres. The point acquisition materially enhanced the quality of our Delaware Basin assets and complements our overall Permian position. Our portfolio today has more optionality and flexibility to shift capital to our highest return projects than ever before. Our team has done an incredible job of adding inventory organically over the last couple of years through innovating on well designs like horseshoe-shaped wells, reducing our cost structure, and testing new formations. Through these efforts, we have added over 300 locations representing just under three and a half years of inventory. We have a large number of wells that sit just above our $50 breakeven cutoff. As little as a 5% improvement in the cost of these wells would shift 155 wells into the sub $50 breakeven range, extending our runway of sub $50 breakeven wells to just over six years. five times the number of wells we had available to us in January of 2023. Our operations team has already reduced costs in the Delaware basin from $1,200 per foot to $1,040 per foot since we entered the basin. 2025 expectation is $925 per foot with longer laterals and faster drill times next year. We have delivered at a rapid rate of change and we see plenty of opportunities to continue this trend. In addition to ads via cost cutting measures new formations like the burnett could also lengthen our inventory runway crane county barnett well reached a peak rate over 1000 barrels of oil per day these initial results are very encouraging. Our second crane county well is being completed, right now, with a smaller more efficient completion design the relative performance of these two wells will help triangulate the optimal design for the future. The rapid increase in inventory length and quality that we have delivered on over the last few years allows us to take a pause on M&A and put more emphasis on operational excellence instead of asset transitions. Going forward, we will use nearly all of our free cash flow for debt reduction, which will provide the greatest positive impact for our shareholders. We anticipate that at current commodity prices, we should be able to generate more than $400 million of adjusted free cash flow over the next five quarters or through the end of 2025. Our strong hedge position over this timeframe supports our cash flows and our forecast for lower debt and maintaining leverage. Looking forward, we expect to hold oil production flat with our original 4Q guidance range midpoint of 66,500 barrels of oil per day with a capital range of around $900 million below consensus expectations of around $925 million for 2025. And as efficiencies continue to improve, our intention is to maintain flat production with improving capital efficiency, and we believe we can maintain this trend for the next five years. To conclude my comments for this morning, We beat expectations for the third quarter. We are raising guidance for the fourth quarter. Point is a great asset for us. Our operating efficiencies are progressing on all fronts, resulting in lower expected capital spending for 2025. And well quality and operational efficiencies should allow us to maintain production for the next five years with flat to decreasing capital costs. Operator, we are now ready for questions.

And we will now begin the question and answer session. If you have dialed in and would like to ask a question, please press star one on your telephone keypad to raise your hand and join the queue. If you would like to withdraw your question, simply press star one again. Our first question comes from Neil Dingman from Truist Securities. Your line is now open.

Morning, guys. My first question is just on your cost reductions on slide six, where you show the DMC per foot targeting 925 mixture. I'm just wondering, how much of this improvement is driven by the lateral length efficiency you mentioned? And maybe could you give details about other upside, you know, within that well cost that you're experiencing that's sort of notable on that slide?

Yeah, Neil, we're really excited about all the progress we've made in the Delaware Basin and both basins. Really, the team has not had a lot of swings at bat, but have been improving very quickly over time. But I'll turn it over to Katie to give you some more color on the future.

Morning, Neil. Like Jason said, we're really excited about that 925 afoot. It reflects a lot of great work across both the operations team and our land team in getting a position put together that allows us to drill extended laterals next year. Like Jason said, we've already reduced costs in the basin by about 20% since we entered a little over a year ago. And I think something that's really worth noting is that it's really less than 15 wells that we've had the opportunity to take from spud to turn in line. And we've been able to deliver that dollar per foot reduction with a small program so far. So excited about the opportunity going forward. That 925 reflects both the operating efficiencies that we've already implemented and are executing on today, plus an additional work that we have line of sight on being able to implement over the next few months. And then also the ability to drill extended laterals next year that's helping to drive that cost down even further. One of the areas that we're really pleased with progress is looking at drilling cycle times. When we first started and looked at underwriting, you know, back at the end of 23, the expectations were 25 to 30-day wells from spud to rig release. And if We're consistently delivering much lower than that today, closer to 20 days a well, and have even set a record at 16 days per well. And that trend is really consistent across all phases. So just great work by the execution team and still some opportunity in front of us.

Great details, Katie. And then maybe just my follow-up, because I think it's still so important on just your operations, is looking at 25 regional operations. Can you remind me maybe broadly how much ops will be in Dell versus Midland and whether the Dell will – most of that be the point? And, you know, I assume so, and if so, you know, what type of potential LOE benefit or sort of trajectory could we get if you continued in that direction?

The Delaware is a great opportunity for us, particularly with the point asset that we're working to integrate today.

You can see on slide five early outperformance on the point wells, so really excited about what that can do to our portfolio. We're going to take capital to that asset almost immediately. We're shifting activity there towards the end of this year and certainly really heavily investing next year. About 75 percent of our 2025 capital will be in the Delaware, 25 percent in the Midland. Of that 75 percent, about half will be on the point asset and then half will be on other Delaware assets that we put together over the last year or so. I think the LOB question is a great one and an important one for us to address. We had a great quarter. Really pleased with the 878 that we were able to report in Q3. We executed on a lot of the projects that we've talked about delivering in 24 that helped to drive costs down across both basins. And a lot of those opportunities are absolutely applicable to points. We've left Q4 at 935 per BOE, really just to reflect that we're in a period of asset integration and onboarding that is not our expected long-term run rate. A lot of the work that, again, we've done in 24 in both Midland and Delaware, we can take to point, and we're starting to do that already. So I'd expect to exit this year around 935. We'll be driving costs down across 2025 and expect by end of next year to be back into the high eight. So just really pleased with the opportunity to be investing. Great asset. It does a lot for our portfolio.

It's great details.

Look for that, Eloise. Thanks, Kenny. Our next question comes from Zach Arham with JP Morgan.

Your line is now open.

Hey, guys. Thanks for taking my question. First, you commented on the Barnett wells a little bit earlier. Can you talk a little bit about the cost there and how those will compete with your wells in the Delaware and Midland Basin?

We're really excited about the Barnett, Zach. It's also very early. I wouldn't take our cost for these wells to be what we plan on for the future. We did these about as inefficiently as you can. We drilled four wells spaced across our footprint, both on our HVP and in the new acreage. And when you're drilling a well in a new formation and completing it as one well instead of a zipper frack, those costs aren't as relative. And it's still early. As I mentioned, we pumped a very large frack with a lot of sand on it on the first one. My message to the team was like, we're going to see exactly how much these wells can deliver, and it can deliver 1,000 barrels a day or more. The next phase for us is test a smaller frack on it, which should be much cheaper, and see does the performance come down or not. We're kind of doing the same thing that we saw in Point, where they pump big fracks, then you step it down to a smaller fraction. I think it's just still too early. These wells are new. They haven't hit. We don't have a good estimate on final decline rates. They're a very different production profile than we see from other assets. These wells kind of get slowly better every day versus our Wolf Camp A wells. They start off at high peaks and decline. So it's early, but we're really excited about it. For me, when I think of what we've done in Crane, this is the first time that we've gone out there and had an idea for a new concept in a zone that's been tested but not tested where we were bought acreage and have a really good initial production test on it. We started this two years ago and then we're doing it in parallel with all of our acquisitions and that's setting up the future that we have today where we don't need M&A to add wells and we can add it organically. So we'll give you some more color in the future but it's still really early, but results are very positive so far.

Thanks, Jason. And then my follow-up, I wanted to ask on the cave bear well or cave bear pad that you had in the slide deck, can you give us a little detail on how that pad was developed? I knew you said it was drilled and completed by point, but with the vital design, was that at four wells per section? And is that kind of how you expect to develop those assets going forward? And Maybe comment on which zones that pad developed as well. Thanks.

Thanks, Zach. This is a 10-well pad that was being developed during the transition.

Point drilled these at a little bit tighter spacing than our long-term plans. These are five wells per section. It's across the A and the B. We did pump our completion design on all the wells, so this is reflective of what our go-forward completion looks like. But we expect to up space and plan to up space on the remainder of the development going forward.

Thanks a lot.

Our next question comes from Noah Hungus with Bank of America. Your line is now open.

Good morning, Paul. I just wanted to start off here on hedges. Just given that the strip for oil in the second half of 25 and 26 is below $70, how should we think about you all adding hedges as we move through this year and into next year?

We've been very consistent with our hedges. We tend to be 75% hedged out into the future. What we've done, I think the team has done a great job of lately here, is just playing volatility. And when we see it, we'll add hedges in that $75 range. We added them when we had this conflict in the Middle East, this flare-up in the Middle East. So that's kind of where we are. As we get closer to the end of next year, we may add those. But for right now, we're two-thirds hedged for $25. I think we're 88% hedged or so for $25. end of the rest of this year. So that's what we've been doing. We make 24 million barrels per year. $5 a barrel has over $100 million impact to our free cash flow. So we want to give opportunity for oil prices to rise, but also protect cash flows as we get closer to year end and we're setting up a 26 budget.

That makes sense. And then could you guys give any maybe additional color on what you all may be planning to try to lower DNC costs, you know, and just noting the impact of a 5% reduction, how that adds to your inventory. Is there anything, any operational details you guys could give us on maybe what you're looking to implement?

We've already implemented really good work on cycle time and the kind of turn in line

efficiency that's been accomplished. What is still left to do, and the team is constantly, you know, questioning and I would say learning from repeat experiences in the Delaware, but what's still left to do is really working through every service cost, making sure that we're either at or better than market, and frankly, you know, working through with our partners that we're implementing best practices, both in the Midland and the Delaware. You noted the continued 5% improvement When I think about the work that we've been able to deliver on in just a year on a pretty small subset of wells, I have a lot of confidence in our ability to continue to drive costs down past that 925 a foot. The 5% sensitivity that we show on inventory is really a question of when and not if, and I think it's a really fair goal for us over the next couple of years. So excited to continue to be developing in the Delaware. We have a fair amount of capital allocation there next year. So there'll be a good opportunity for us to continue to drive costs down.

Sounds good, guys. Thank you. Thank you.

There are no further questions.

I'll hand the call over to Mr. Ron Hinkley.

Well, thank you all for joining us today. We've discussed and you can hear we are very excited about this quarter and what the future has in store for us. slow down the M&A for the future, you're going to see this operational excellence showing up every quarter, allowing us to, again, take our free cash flow and pay down our debt, which is going to be a great return for our shareholders in the future. So we look forward to talking to you on our next call.

Thank you. Conference is now concluded.

Thank you for joining us. Have a blessed day.