Granite Ridge Resources, Inc (NYSE:GRNT) Q3 2024 Earnings Call Transcript

Granite Ridge Resources, Inc (NYSE:GRNT) Q3 2024 Earnings Call Transcript November 8, 2024

Operator: Good morning, and welcome everyone to Granite Ridge Resources Third Quarter 2024 Earnings Conference Call. Currently, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] I will now turn the call over to James Masters, Investor Relations Representative for Granite Ridge.

James Masters: Thank you, operator, and good morning everyone. We appreciate your interest in Granite Ridge Resources. We will begin our call with comments from Luke Brandenberg, our President and Chief Executive Officer, who will provide an overview of key matters for the third quarter and an outlook for the remainder of 2024. We will then turn the call over to Tyler Farquharson, our Chief Financial Officer, who will review our financial results. Luke will then return to provide some closing comments before we open up the call for questions. Today’s conference call contains certain projections and other forward-looking statements within the meaning of federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied in these statements.

We would ask that you also review the cautionary statement in our earnings release. Granite Ridge disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in yesterday’s press release and our filings with the Securities and Exchange Commission. This conference call also includes references to certain non-GAAP financial measures. Information reconciling non-GAAP financial measures discussed to the most directly comparable GAAP financial measures is available in our earnings release that is posted on our website. Finally, as a reminder, this conference call is being recorded.

A replay and transcript will be made available on our website following today’s call. With that, I will now turn the call over to Luke.

Luke Brandenberg: Thank you, James, and good morning everyone. Appreciate you joining us today. I’m pleased to report that our third quarter results have exceeded our internal expectations across the board. This success is a testament to our team’s creative deal sourcing and exceptional underwriting, and to the operational excellence of our partners. I’m grateful for our team’s efforts as we continue to demonstrate our capabilities in the public arena, just as we have done privately for over a decade. Tyler will provide that detailed overview of the quarter, but I’d like to highlight a few key points. Our Controlled Capital program, which gives us full control over development timing and targets project rates of return in the mid-20s or better continues to thrive.

Though still in its early stages, production to date has exceeded targets by approximately 15% and CapEx has come in about 15% under budget. We now have an inventory of over 40 net locations in the Permian that we plan to develop over the next two to three years. Given our early success, we plan to allocate even more resources to Controlled Capital. In 2024, this will account for nearly 50% of our CapEx and based on current inventory, I anticipate that in 2025 approximately 60% of our CapEx will be dedicated to Controlled Capital. On the deal front, we successfully closed over a dozen transactions this quarter, adding nearly 16 net locations at a total cost of $31 million. These new locations are projected to require $125 million in future development capital.

This aligns with our typical ratio where $1 of entry drives roughly $3 to $4 in the ground. These additional locations are primarily within our Controlled Capital program and include inventory under our new Midland Basin focused strategic partner where we continue to grow our position and plan to pick up a rig later this year or early next year. Turning to production, I mentioned last quarter that we anticipated a 5% to 10% decline in gas production for the third quarter. I’m pleased to report that we were wrong as we actually saw an increase in gas production. This outperformance was primarily driven by our first Controlled Capital pad in London County, Texas. Looking ahead to the fourth quarter, we do expect some flush gas production to taper off, potentially leading to a quarter-over-quarter gas production decline of up to 10%.

However, this should be partially offset by a modest increase in oil production. When going through our quarterly results, it stood out to me that 16.2 net wells in process as of September 30th is higher than usual. To add a bit more color, 12 of those net wells are under just four operators in the Delaware Basin. Of those 12, five are in our Controlled Capital program. We currently expect to put two to four net wells on production in the fourth quarter, followed by a significant increase in the first quarter. I’ll wrap up with a look ahead to next year. As mentioned on our August call, we anticipate double-digit production growth in 2025 compared to 2024. While we are not providing formal guidance for 2025 at this time, we do expect year-over-year production growth to be in the mid-teens with the oil weighting of 2025 production projected to be in the low 50% range.

On that note, I’ll hand it over to Tyler to provide more insights into our results.

Tyler Farquharson: Thanks, Luke, and good morning everyone. For the third quarter we reported average daily production of 25,200 Boe per day, marking a 9% increase over the second quarter and 5% from the third quarter last year. Notably, our oil volumes increased by 16% from the prior quarter to 12,700 Boe per day, raising our total oil percentage to 50% in the third quarter, up from 47% in the prior quarter. Our annual production guidance range of 23.3 Boe to 25.3 Boe per day remains unchanged. However, we now expect more oil production for the year than originally guided and expect our fourth quarter oil production mix to be in the low 50s as we exit 2024. Overall, we expect our fourth quarter production to decline slightly versus our reported third quarter results.

Net income for the quarter was $9.1 million or $0.07 per share excluding non-cash and non-recurring items, adjusted net income was $18.5 million or $0.14 per share. Adjusted EBITDAX for the quarter was $75.4 million, representing a 10% increase from $68.3 million in the prior quarter despite a 6% decline in realized pricing on a Boe basis. Year-over-year, adjusted EBITDAX was down approximately 9%, primarily due to the impact of asset divestitures in Q4 2023 and lower realized pricing. Per unit lease operating cost improved significantly from the prior quarter, coming in at $5.62 per Boe, a 14% improvement from $6.50 per Boe in the second quarter. Production and ad valorem taxes were 6.7% of sales, down from the 7.6% last quarter both metrics below our annual guidance range for 2024 and we feel comfortable reaffirming our full year operating expense guidance.

Our per unit G&A expense excluding non-cash stock-based compensation improved by 25% to $2.16 per Boe for the quarter. This highlights the scalability of our business model. As production and sales grow, unit overhead costs continue to decline. Our annual guidance range of $23 million to $26 million is unchanged. During the quarter, our operating partners completed and placed on production a total of 93 gross or 5.2 net wells, with activity nearly evenly split between the Permian Basin and the DJ Basin and a handful in the Bakken. As of September 30, we had an additional 6.2 net wells in process, and as Luke mentioned, we expect two to four of those wells to be placed on production during the fourth quarter. In total, we continue to expect 22 net wells to 24 net wells to be placed online during 2024, with nearly 80% of those wells being in the Permian Basin.

In the third quarter, we closed multiple transactions, adding 15.9 net future drilling locations primarily in the Permian Basin, for a total cost of $30.9 million. Our acquisition capital guidance for 2024 remains unchanged at $60 million. Our development capital spending during the third quarter $77.6 million in line with expectations. We reaffirm our development capital guidance of $300 million at the midpoint of the range. Notably, a substantial portion of our capital expenditures in the second half of this year have been directed towards our Controlled Capital development programs. We expect these investments to drive significant production and cash flow in the first half of 2025. During our Q4 call, we will provide formal 2025 guidance, which we anticipate will reflect strong year-over-year growth due in part to nearly $150 million worth of capital during 2024 for activity expected to turn to sales during early 2025.

Finally, consistent with Granite Ridge’s value proposition, we continued our quarterly cash dividend program paying $0.11 per share in the third quarter. Subsequent to quarter end, our board declared another $0.11 per share cash dividend payable on December 16, 2024 to shareholders of record as of November 29, 2024. This annualized dividend represents a 6.9% yield based on Wednesday’s closing price, which underscores our commitment to returning differentiated value to our shareholders. I will now hand it back to Luke for his closing comments. Luke?

Luke Brandenberg: As we celebrate our second anniversary as a public company, it is an opportune time to reflect on our journey in future direction. One of my key priorities moving forward is to reshape the narrative around Granite Ridge. We are often categorized with non-controlled companies, but this does not accurately reflect our business. Typically, operators allocate about 75% of their capital expenditure to controlled projects and 25% to non-op. This year Granite Ridge will allocate nearly 50% to control projects, increasing to around 60% next year. This allocation is more characteristic of an operator, yet we do not operate wells. The value we create at Granite Ridge lies in our capital allocation strategy. We blend our non-op roots with control over development by controlling the per [ph] strings.

If we control development but we do not operate, what are we? Publicly Traded Private Equity, Granite Ridge combines the control of an operator with private equity’s agility and capital allocation. By integrating private equity principles into a public entity, we aim to drive long-term value for shareholders in a vehicle with increased liquidity, enhanced visibility and alignment, and immediate shareholder returns. This is a unique model, and it is proving successful. We invite you to join us in building something special. Thank you all for joining us this morning. I’m enthusiastic about the future of Granite Ridge. 2025 promises to be an exciting year for us. Our earnings release highlights several upcoming conferences over the next month.

I look forward to seeing some of you in-person or catching up on a call soon. As the holiday season approaches, I wish you and your families all the best. Operator, please open the floor for questions.

Q&A Session

Operator: [Operator Instructions] Your first question comes from the line of Noah Hungness with Bank of America. Please go ahead.

Noah Hungness: Morning, guys. I just wanted to start off here on your LOE costs. You guys came in pretty well below your guided range for the year. Could you just kind of talk about what drove that and how we should think about LOE costs moving into 4Q and maybe into early 2025?

Tyler Farquharson: Yes, sure. Morning. Yes. So this year we’ve seen LOE costs come in under where we’ve been guiding to at least the past couple of quarters. That’s mainly due to less workover expense. I think at some point that will revert back to the mean. But for now, I think our Q4, we’re expecting that we’d probably come in towards the lower end of our guidance range, which would put us again towards the low end of the guidance range for 2024.

Noah Hungness: Great. And then I kind of was hoping you guys could expand on. I was looking at your burgers and beers list of kind of basins. You have added some leasehold, and it looks like you guys added some in Appalachia. I was hoping you could just give us some color there on where you’re looking? Or is that in the Marcellus? Or the Utica? And if it’s in one of those areas, is it more liquids or dry gas focused?

Luke Brandenberg: Yes. Noah, this is Luke. Thanks for the question. Happy to take that. So we are really focused on the Utica condensate window more Guernsey and Harrison. That’s really a neat opportunity for us where we came across a group that has been active in that area, and they were coming across really unleased minerals. And we were able to form a partnership with them such that whenever they had unleased, we got a first look at those. And so that’s been a really opportunity. They’ve been in the Utica since Gosh, I think 2006. They were up there in the very early days of the first wave. So it’s just a cool opportunity for us to really be a capital partner to groups that are finding need [ph] opportunities. Again, this is the area, if I had to paint a picture on a map that you got the dry gas stuff to the east, you’ve got EOG oil window to the west and we’re in that radical middle where it’s really a condensate, rich condensate area.

We’re not putting a ton of capital to work there. There’s wherever you are, people have figured out the good areas pretty quick. So it’s tough to find unleased or stuff at a good deal. But the capital we have put to work we’re very excited about and frankly would be excited to put more as long as we can continue to find opportunities that hit our target returns.

Noah Hungness: Sounds good guys. Thanks.

Luke Brandenberg: Thanks, Phillip.

Operator: Your next question comes from the line of Michael Scialla with Stevens Inc. Please go ahead.

Michael Scialla: Hi, good morning everybody. Luke, I wanted to see if you could give a little more color on the control CapEx partnerships you talked about. The drilling inventory now is up to 42.6 net locations. You said you might pick up a rig in the Midland Basin and fourth quarter or first quarter next year. I just want to see how many of those locations are in the Midland Basin partnership and what will determine when you get that rig? You need more inventory there still or is it something else that will determine the timing there?

Luke Brandenberg: Yes. Morning, Mike. Thanks for the question. So if I a couple of pieces on that, as you mentioned, really have two partners right now. One is primarily Delaware Basin focused, the other is primarily Midland Basin focused. The Midland Basin asset we’re really in, I’d say lease block up mode right now where they have a nice initial position. But as we did with our initial Delaware Basin partnership, a real goal was to build up enough inventory such that if we wanted to we could keep a rig running for full time for a period of time anyways to try to drive some of the efficiencies from keeping one rig going versus going up and going down. Right now, we have five or six net locations depending on what working interest shakes out to be in the Midland Basin and the rest is in the Delaware.

But we’re working on several transactions. I think that will block that up and increase that Midland Basin working interest piece. But right now again we’re targeting probably late this year, early next, more than likely. I say more than likely, to be honest, one of the cool things about our strategy is, we’re trying to find the right rig at the right time. And so that’s where we can be creative. And we’d rather have a better rig and wait a month than have a rig that’s coming out of the yard and do it immediately. So I think late this year, early next, we’ll pick up Midland Basin. We’re currently running one rig in the Delaware Basin. I’d anticipate that we’d go to two rigs in the Delaware Basin probably Midland next year.

Michael Scialla: Sounds good. Wanted to ask on Slide 9, your chart shows your look back analysis, actual production versus what you’ve underwritten with your forecasts. It looks like pretty much dead on production wise. And realize that with data out there, you can get a pretty good handle on what wells will produce in a given area. But as a non-operator, obviously timing and development is a significant risk. So, I guess my question is, is that chart just showing well performance? Or is that also showing your performance versus I guess, does it, sorry, does it incorporate timing into it as well? And if so, how are you handling the timing risk when you underwrite these acquisitions?

Luke Brandenberg: Yes, it’s a good question, Mike, and thanks for asking about that slide because it’s something that we really are proud of is at the end of the day, if we’re a publicly traded private equity firm and our real value is in capital allocation, a core piece of that is, are you any good at underwriting deals? And this slide is really goes to demonstrate that that really is a strength. And it’s a strength that goes back for over a decade that we’ve been doing this largely in the private side. But this does not incorporate timing. This just takes the, engineers made a projection of what a well would do and then tracked that and saw what actual performance was for over 1,000 wells across multiple basins. A neat thing about this, and I think a big driver for why this number is so tight is to your point, the data set that we have just being in over 3,000 wells and many in each of these basins, geology can change quite rapidly, but the more data points that you have, the better chance you have of making a good estimate.

We’ve been in the Permian basin since, gosh, 2013, so have a strong data set of actuals that really helped this. And I’d say the neat thing is like this would continue to improve. I’d say there’s not a whole lot of room for improvement. But just we get more data points every single day and our team continues to incorporate that their underwriting. So we’re very proud of our engineering team, our underwriting capabilities and that is just a true cornerstone of the business and the success we’ve had to date.

Michael Scialla: Thank you.

Luke Brandenberg: Thanks Mike.

Operator: Your next question comes from the line of Phillips Johnston with Capital One. Please go ahead.

Phillips Johnston: Hey guys, thanks for the time. Lots of good color in the prepared remarks just about the trajectory of production. Just wanted to make sure I caught everything. So let’s talk oil. So your implied fourth quarter guidance suggests about a 3% kind of downtick in oil volumes sort of on the heels of what was pretty outsized growth obviously in Q3. Then it sounds like you expected a large sequential increase in Q1, which I think is consistent with what you guys said on the second quarter call. And it seems like that might even be augmented by the nine Controlled Capital spud in the Permian. So just wondering what kind of order of magnitude we’re talking about in Q1 and then I guess for the full year I think you said double-digit growth on a year-over-year basis. Just wanted to clarify if that applied to oil or Boe or both? Thanks.

Luke Brandenberg: Yes, great questions and thanks Philip, appreciate you dialing in. On the – I’ll hit from third quarter to fourth quarter first on the gas side we anticipate what could approach a 10% decline in gas quarter-over-quarter from third to fourth. And that’s primarily driven from frankly some of these new wells and that rolling off the flush production side. A big piece of the gas outperformance from second to third quarter was our first Controlled Capital pad there in Loving County. One of the difference makers there is we drilled eight wells in that pad, two in the XY two, in the A, two, in the B, two, in the C and the B and the C are gassier zones. And say we’re generally conservative in an area where we do have fewer data points there we had a lot of X, Y and A’s but fewer proximate data points in the B and C.

And we were conservative in underwriting the gas side. We saw significant outperformance there. I anticipate that some of that will start to roll off. So again, gas looking at up to 10% decline from third to fourth quarter on the oil side, I actually anticipate that we’ll see a slight uptick to mitigate some of that gas decline, but not a significant one low single digits. As we look to next year, Tyler made this point in his comments, which I think was a good one. We anticipate spending probably $150 million in 2024 on wells that we will not see, any contribution from until next year. And a lot of those wells I think will come online early next year. We mentioned, like I mentioned, we have just over 16 WIPs at the end of 9:30 and we expect, two to four wells to turn to sales in the fourth quarter.

And so a lot of those are going to come on early first quarter. And so I anticipate first quarter we’ll see a pretty significant jump in production. I think you’ll see that both on the oil and gas side. For 2025 you were correct. I mentioned double digit growth last quarter. I mentioned in my remarks earlier we think that’ll be mid teens. So I’m going to narrow that down a little bit. We’re looking for mid-teens growth on a Boe basis. I think that you’ll see growth year-over-year in both oil and gas, but primarily on the oil side. And so that’s going to be the big driver is Controlled Capital program. That’s all I guess all Midland Basin focused. Excuse me, all Delaware and Midland Basin focused at this point. But it’ll be a primary oil driven growth in 2025, which we are very excited about.

Phillips Johnston: Okay, great. That’s good color. And then maybe can you talk about where you expect to end the year and just in terms of a next 12 months PDP decline rate and kind of what that might look like relative to kind of where you came into the year. You guys have had a decent amount of growth. So just wondering if your PDP decline rate has changed significantly.

Luke Brandenberg: Yes, I think it’s increased a bit. I’d say we’re around 40% right now. If you’d asked me this a year ago, actually I don’t. You may have, but a year ago I probably would have said it was high 30s and I would say it’s around 40%. So it has ticked up a little bit. And a big piece is again the Controlled Capital program which is the higher working interest wells. So we recognize that by doing that you do increase the treadmill a bit certainly in the near term. But that’s a big piece of why we wanted to wait to pick up a rig until we had enough inventory to keep it going. That will help to, stable out that treadmill over time.

Phillips Johnston: Sounds good. Thanks Luke.

Luke Brandenberg: Well, thanks Phillips. Have a great one.

Operator: Your next question comes from the line of Jeff Robertson with Water Tower Research. Please go ahead.

Jeff Robertson: Thanks, Luke. I think you said or – thank you. Luke, I think you said that all of your or most of your Controlled Capital is currently in the Permian Basin. I’m wondering if you’re seeing opportunities in some of the other basins that you operate for Controlled Capital type partnerships.

Luke Brandenberg: Yes, that’s a great question, Jeff, because right now we have two Controlled Capital partnerships. I’d love to have three or four. And we are looking at other basins. One of the challenges that we see right now, our Controlled Capital program is really focused on near term development. And so areas that are gas weighted are tough for us just given current economics. Drilling new gas wells right now is just more challenged. And so, there are areas on the gas side that could be compelling from an inventory capture perspective. And there are some teams out there that are very high quality, have created a lot of value and I think could be interested in a type of partnership that we have. But gas side is tough and so as we do look in other areas, we’re, I’d say in some form of dialogue with a couple other teams right now.

I would think Bakken and Eagle Ford are two of the basins that we’re looking at pretty hard right now in the sense that we see an opportunity for our existing assets to potentially contribute to building a partnership. The one thing in all these basins, frankly is that the treasure maps are well defined in a lot of spots and so you’re not finding unleased acreage. And so a big piece has really become that trading game. So a big advantage that we have and really a way that we can add value to potential partners is, we do have a lot of acreage across these different basins. Take the Bakken for example. That could be used to trade. Sometimes trade is more appealing than cash for a lot of these large operators you may want to work with. So that’s a long winded way of saying absolutely, we love times [ph] schemes in different basins.

I think Eagle Ford and Bakken are very compelling based on the opportunity set that is out there and the data that we have. I’d say Eagle Ford is a bit tougher just because there’s fewer opportunities. But yes, we’ll continue to look. We are certainly open for business on that side, and I like to allocate more and more capital to that program. We’ve loved the success to date. I think that we can provide a differentiated solution to some of these proven management teams and we will continue to look, so thank you for asking that.

Jeff Robertson: I guess as a follow up, it sounds like it would probably be complicated, but you could use some of Granite Ridge’s leases in some of these basins to help it control partners solidified acreage in an area that the two of you would like to participate. Is that fair and is that too complicated to try to put together?

Luke Brandenberg: No, it’s not too complicated. We’ve actually done that on multiple occasions with our Delaware Basin focus partner, where we’ve had acreage in a good area and they were trying to cut a deal with that operator in a different area, and we were able to use that acreage as currency to help grease the skids and get the deal done. So no, it’s a great point. I think it is a true value-add that we have, with our partners in the Delaware and Midland Basin. Day one of getting that partnership going, we said, hey, look, here’s everything that we have in your area of interest. If there’s a way that you can use that to help facilitate, capturing inventory in other parts, have at it. That’s we can easily find a way to make that work for both sides. So it’s a great point. I think it is a big differentiator for us as folks are looking for capital partners.

Jeff Robertson: Thank you.

Luke Brandenberg: You got it. Thank you, Jeff.

Operator: We have no further questions in our queue at this time. And with that, that does conclude today’s conference call. Thank you for your participation. And you may now disconnect.