Granite Ridge Resources sees 27% production boost in Q3 2025, reaffirms commitment to disciplined growth and shareholder returns amidst stable oil prices.

Good morning and welcome everyone to Granite Ridge Resources third quarter 2025 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press star one again. Thank you. I will now turn the call over to James Masters, Investor Relations Representative for Granite Ridge.

Thank you, operator. Good morning, everyone. We appreciate your interest in Granite Ridge Resources. We will begin our call with comments from Tyler Farquharson, our President and Chief Executive Officer, who will review the quarter's results and company strategy. We will then turn the call over to Kim Weimer, our Interim Chief Financial Officer and Chief Accounting Officer, who will review our financial results in greater detail. Tyler will then return to provide closing comments before we open 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. We ask that you 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 these statements. These and other risks are described in yesterday's press release and our filings with the securities and Exchange Commission. This call also includes references to certain non GAAP financial measures. Information reconciling these measures to the most directly comparable GAAP measures is available on our earnings release on our website. Finally, this call is being recorded and a replay and transcript will be available on our website following today's call. With that, I'll turn the call over to Tyler. Thank you, James, and good morning, everyone. I appreciate everyone joining us today for our third quarter 2025 earnings call. Our results this quarter once again highlight the strength of our business model, grounded in disciplined capital allocation, operational excellence and strong execution across our platform and operating partners. In the third quarter, average daily production increased 27% year over year to 31.9 thousand barrels of oil equivalent per day. Adjusted EBITDAX rose 4% from the prior year period to 78.6 million. Capital expenditures totaled 80.5 million, consisting of 64 million in development and 16.5 million in acquisitions. We ended the quarter with a leverage ratio of 0.9 times, well below our long term target range of less than 1.25 times. In addition, we continued our quarterly dividend of $0.11 per share, underscoring our commitment to a reliable competitive return to our shareholders. Subsequent to quarter end, we enhanced our capital structure and liquidity position. Earlier this week, our lending group reaffirmed the $375 million borrowing base on our revolving credit facility and we successfully issued 350 million of senior unsecured notes due 2029 with an 8.875% annual coupon. Together, these actions increased our pro forma liquidity to $422 million and further enhanced our flexibility to execute our business plan while preserving balance sheet strength. 2025 marks an important inflection point for Granite Ridge as we scale our operated partnership platform and further define our model as publicly traded private equity. Through these partnerships we combine the control of an operator with the capital discipline of an investment firm, a framework that supports deliberate cycle resilient decisions around capital allocation and inventory selection. Year to date, approximately 50% of our capital spending has been deployed from these partnerships. We are particularly pleased with the success of Admiral Permian Resources, our largest and longest standing operator partnership which continues to set the benchmark for performance. Admiral now controls 30 distinct drilling units across the Permian Basin and as of quarter end had 63 producing wells with 14 more in progress. Admiral's multi horizon portfolio has consistently delivered results in line with our underwriting expectations while advancing technologies such as U turn well design further enhancing efficiency and cost control while also making them a preferred partner for larger asset managers. So far in 2025, Admiral has added 61 gross 17.2 net locations for an average of $1.9 million per net location, representing over $200 million of future development capital. In less than three years the partnership has captured 198 wells 94 net to granite, representing nearly $1 billion of development capital. Admiral now produces 7,400 boe per day net to granite or 23% of Granite Ridge's total production. Admiral's success illustrates why we believe the operated partnership model is our most capital efficient path to scale. Unlike many EMPs that make large point in time acreage acquisitions exposed to multi year commodity cycle risk, Granite Ridge executes drilling unit level acquisitions narrowly underwritten at current strip pricing for near term development. We believe this approach provides superior risk adjusted returns and flexibility. While each partnership is unique, Admiral's success has become a blueprint for our other partnerships including Petrolegacy and two recently formed partnerships focused on the Midland and Delaware basins. Collectively, these Partnerships now encompass 28.1 net producing wells at approximately 30.1 net undeveloped locations with an additional 37.7 net locations expected to close before the end of the year. Each partnership is structured to generate operated deal flow, strong full cycle returns and control over capital deployment and development timing. Petrolegacy initiated its drilling program in the Midland Basin at the end of the third quarter with production contributions expected early next year. Meanwhile, our two newer operated partnerships are actively advancing business development initiatives expected to add meaningful high quality inventory ahead of transitioning to development mode. Our traditional non op business continues to deliver stable cash flow and diversification. During the third quarter we participated in 59 gross or 9.3 net wells turned to sales primarily across the Permian and Appalachian basins. We remain particularly encouraged by our results in the Appalachian Basin where We've added over 1500 net acres this year and consistently outperformed our underwriting expectations. Earlier this year we increased our acquisition capital guidance by $100 million to capture attractive opportunities across both our operated and traditional non operated strategies. As of quarter end, we invested $43 million through our operator partnerships, adding 27 net wells and $20 million through non operated acquisitions, adding 6.7 net wells primarily in the Delaware Basin and in Appalachia. Before year end we expect to invest an additional $47 million to secure 38 net locations along with additional acreage in the Utica play. Collectively, these additions will add nearly three years of drilling inventory at an average cost of $1.7 million per net location. Turning to the macro environment, oil and gas prices have remained relatively stable over the past 12 months, providing a constructive backdrop for continued disciplined growth. We remain focused on opportunities that clear our 25% full cycle return hurdle and exceed our cost of capital even as we modestly outspend cash flow. As always, our spending and leverage remain guided by our leverage target range of 1 to 1.25 times and we're committed to staying within those bounds. Looking ahead to 2026, we are constructive on the long term oil outlook but cautious near term given uncertainty in global supply growth. We'll provide detailed guidance with our Q4 release, but our strategic framework remains clear. Above $60 oil, we plan on pursuing measured growth with modest outspend. If we see sustained oil prices below $55 per barrel, we plan on pivoting to a maintenance Mode targeting roughly $225 million in CapEx while maintaining flexibility for opportunistic acquisitions. Our strategy is designed for agility supported by a just in time inventory model, diversified asset base and minimal drilling commitments, allowing us to remain nimble through varying market conditions. We also continue to actively hedge around 75% of production each quarter with nearly 50% of expected 2026 volumes already hedged. Combined with a strong balance sheet, this ensures we can operate in a best through cycles. Bonded markets will remain volatile, but our platform is built for it. We're confident Granite Ridge is well positioned for another year of disciplined growth, consistent returns and sustainable shareholder value in 2026. With that, I'll turn it over to Kim for a detailed financial review.

Thank you Tyler and good morning everyone. I'll start with a brief overview of our financial results. Revenue for the third quarter was 112.7 million compared to 94.1 million in the prior year period. Adjusted EBITDAX was 78.6 million, up 4% year over year. Net income was 14.5 million or $0.11 per diluted share, while adjusted net income was 11.8 million or $0.09 per diluted share. Operating cash flow before working capital changes totaled 73.1 million. On the cost side, LOE came in at $8.03 per boe, higher than expected, primarily due to an increase in saltwater disposal, contract labor and other service costs in the Permian Basin. Production and ad valorem taxes were 6% of sales and G&A was $2.38 per boe, consistent with our guidance range. Our disciplined capital allocation approach remains unchanged for the quarter. Total capital spending was 80.5 million, including 64 million of drilling and completion and 16.5 million of acquisitions. We continue to expect full year 2025 capital expenditures of 400 to 420 million, of which $120 million is expected to be invested in 50 transactions that will add 75 net locations to Granite Ridge's inventory. Our development capital spend is allocated approximately 51% to operated partnerships and the balance to traditional non op. As we look ahead to the fourth quarter and into 2026, we expect continued production growth from our operated partnerships as new wells come online. We are maintaining our full year production guidance of 31 to 33,000 boe per day, with oil expected to represent roughly 50% of the mix. Our balance sheet remains a source of strength, ending the quarter with net debt to EBAX of 0.9 times, comfortably below our long term target of 1.25 times. We ended the quarter with 11.8 million of cash and 300 million drawn on our 375 million credit facility resulting in liquidity of 86.5 million. As Tyler mentioned, we completed a $350 million issuance of senior unsecured notes due 2029 at an 8.875 coupon. This transaction strengthens our capital structure as we head into 2026, with net proceeds used to pay down the revolver and bolster cash on hand on a pro forma basis. At quarter end, our liquidity increased to 422 million. We continue to return meaningful cash to shareholders. Our $0.11 per share quarterly dividend remains a central component of our total return framework, equating to an annualized yield of approximately 8.3% at recent prices. With that, I'll hand it back to Tyler for closing comments.

Thank you, Kim. To wrap up, the third quarter was another strong quarter for Granite Ridge, marked by continued operational outperformance, excellent execution across our operator partnerships led by Admiral Permian, robust cash generation and disciplined capital management, and steady shareholder returns. We built a model that combines growth, yield and flexibility, and it's working, delivering durable value for our shareholders through the cycle. Our business offers exposure to some of the best assets and operators in the country with downside protection through diversification, a robust hedge book and low leverage. Thank you to our employees, partners and investors for your continued support. With that, we're happy to take your questions.

At this time, I would like to remind everyone, in order to ask a question, press star, then the number one on your telephone keypad. Your first question comes from the line of Michael Ciallo with Stevens. Please go ahead.

Morning, guys. Want to see if you can say morning. Want to see if you could talk a little bit more about your third and fourth partnerships? You said they're both moving strategic plans forward. Anything else you can tell us there in terms of what those plans might look like and where they are in terms of potentially drilling or adding acreage? Yeah. So both of those partnerships are in aggregation mode right now. They're both Permian focused. One of the partnerships is focused on some of the emerging plays within the Permian, and the other partnership is focused on the Midland Basin. You know, I think that it'll take them, you know, six or so months in order to aggregate. What we like to see is about 18 months worth of development in front of each one of those partnerships before we commit to running a rig full time on each one. So I'd expect for us to have a little bit of activity, development activity in 2026 if they continue to be successful on aggregating inventory here over the next handful of months. During the fourth quarter, we actually have some of the first transactions with one of those partnerships closing in the fourth Quarter. So we'll get some inventory via one of those partners in the fourth quarter and then the last partnership that we signed up isn't too far behind. So, you know, I wouldn't expect a ton of development activity from them in 2026, but it just depends on how successful they are in aggregating inventory. We appreciate that detail. Tyler, you mentioned you would, in a $55 or lower oil price environment, cut CapEx back to 225 next year. Can you provide a little bit more detail on that? I assume most of the production would come out of the partnerships. How much flexibility you have there in laying down rigs and crews and how would the mix change going forward in that scenario versus your traditional non op position versus the partnerships? Yeah, yeah, we'd expect to see coming out of the non op portfolio, you know, operators act rationally. So we'd expect to see a lot less inbound afes on the non op piece then on the operated side. On the operator partnership side, you know, we have full control over the timing and the development pace of those partnerships. And as we're starting to construct our 26 plan, we're building in, you know, tremendous flexibility there to be able to push some of that activity out. If we do see, you know, a quarter or two worth of oil price in the low 50s, you know, that's why we like the operator partnership so much as we do maintain that control over those partners partnerships to be able to construct a capital plan that kind of fits our needs as we, you know, if we end up experiencing some lower prices, you know, in addition to the drilling side, I think what you'd probably see from us in that low price scenario, you know, we pull back on some drilling and I think we'd actually probably reallocate those dollars to not only inventory acquisitions, but also potentially maybe some PDP style transactions as well. Okay, so not prob. Sounds like not, not really a change in the mix between the traditional non op and the partnerships, but just both would be lower and less focus on drilling, more focus on acquisitions. Yeah, I think we'd love to be more opportunistic on acquisitions and in that price environment. Got it. Thank you.

Your next question comes from the line of John Annis with Texas Capital. Please go ahead.

Hey, good morning all and thanks for taking my questions. For my first one, understanding that there's lumpiness quarter to quarter and you haven't published guidance for next year. How should we think about the growth trajectory in the fourth quarter and into 2026 with Admiral running at full STE and Petrolegacy ramping. And then is it fair to assume PLE's production shows up more towards the second quarter or mid year? Yeah, I think on that last point on ple, I think, yeah, that is a mid year production contribution expectation for ple. They're getting started drilling now. You know, that'll probably show up starting kind of late second quarter. On Admiral, they're running two rigs now. We expect that to continue through 2026. I think on the production cadence you're right. We haven't guided to 26 yet, so we can't really speak a whole lot to 26. But on Q4 of 25 we do expect to see, you know, somewhere in the high single digits production growth from the third quarter to the fourth quarter. Terrific. For my follow up, can you talk about what you see as the ideal length of inventory that you would like to get to and how do you weigh that with the commodity underwriting risk that comes with that longer dated inventory? Yeah, we actually love where we're at right now. Three to five years of inventory feels like the right amount of inventory for us. We're not interested in, you know, buying long term inventory and having to warehouse that on the balance sheet, you know, for years five and beyond. I think having, you know, control over the operated partnerships gives us a lot more comfort in having three to five years worth of inventory because it's actually controllable inventory now versus having to rely on non op partners. So we're actually quite pleased with where we are on our inventory. You know, I think if anything, you know, maybe, maybe we could get, you know, some more durability on, you know, some inventory outside of the Permian basin. But you know, we're pleased with where we are overall, particularly with what we've established in the Permian. Appreciate all the color. I'll turn it back. You bet.

Your next question comes from the line of Noah Hugness with Bank of America. Please go ahead.

Morning. For my first question here, I wanted to touch on loe. It was a little higher than we thought, than we thought for the third quarter. Can you just talk about how we should expect that to trend the 4Q and also for 26.

Sure. As our production has increased within the Permian basin roughly in Q3, about 77% of our oil production was from the Permian. Our saltwater disposal costs have increased, so on total have increased our LOE per boe. So we would expect that we will be towards the higher end of guidance for 2025 on a full year Basis.

And I guess how can you think about it for 26 if you can?

Yes, yes. We haven't guided towards 26 yet. We'll continue to look at our production expectations as we move into 2026 and working with our operated partners, what we can expect for that loe per boe going forward and we'll guide to that at that time. Great.

And then for my second question here, it's really on Waha. I mean, natural gas prices in Waha continue to be really weak. They look like they'll be weak basically until a lot of those pipes come on in second half 26. And then it looks like Waha basis gets really strong at or below basically transport costs out of basin. Do you guys have Waha hedges on today for second half 26 and beyond and would you consider adding them or adding more to basically eliminate your Waha exposure given how strong the forward curve is?

With regards to the first question, we do not currently have any basis hedges in place for our Waha exposure and going forward have considered adding those as you mentioned, for the strength of the curve going forward. So we will continue to look at that and evaluate that going forward. Yeah, Noah, there's, you know, we're also looking at other alternatives for our Permian gas. There's, you know, there's lots of, you know, gas to power projects out there that you've seen some other operators in the basin signing up or evaluating. And that's also something that's on the table for us. You know, we're looking at a few of those options now. We think that that could also be a good solution for some of our Waha gas in addition to, you know, hedging some of the Waha exposure as well. So we're kind of looking at a solution for Waha gas a couple of different ways as we kind of move into next year. I really appreciate that, caller. Just to kind of build off of that, if I could. How, how, how could we think about the pricing for that? Is it power exposure? Is it a premium to Waha? Is it, is it flat price? It would be some power exposure that we've realized as a premium to Waha. Great stuff, guys. Thank you. Thanks.

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

Hey, thanks for the time and thanks for the color on how production volumes should trend into Q4. I wanted to ask the same question on how CapEx should trend into Q4. If we look at, you know, what's implied for Q4 based on your unchanged guidance, Range. The potential range for Q4 is pretty wide at around 125 to 150. So just wanted to know if we should be steering towards kind of the midpoint of that range or towards the low end or the high end. Thanks. Yeah, yeah. So we, we had some timing adjustments on, on the acquisitions. Our development capital actually came in where we thought it would be for the quarter. So, you know, we're not changing guidance for the full year. We still expect to close all the acquisitions that we outlined on our last call for the year. So we just see that timing shifting into the fourth quarter. If I had to guess, I think that, you know, fourth quarter, you know, would be somewhere in the $125 million range, with a big chunk of that being the remaining acquisitions that we're closing for the year. Okay, perfect. And then I appreciate the color on 26 and it's obviously early, but if we do assume current strip prices hold, how should we think about capital allocation for next year in terms of oil versus gas? Would you, would you be inclined to kind of keep your investment mix roughly the same or would you sort of lean into gas a little bit more than you. You know, it's all returns driven. Right where we're seeing the best opportunity now continues to be in the Permian, so I'd expect, you know, a very significant oil weighting. That being said, outside of the Permian, we are, via the traditional non op strategy, having a lot of success in Appalachia. And that's more, you know, rich condensate, you know, phase. We're, we've been, you know, very successful this year on picking up a lot of inventory and acreage in that part of the play in Ohio. But we're starting to see afes come in. We actually have, you know, a handful of pads already online in Ohio and I would expect to see additional capital being spent up there on both acquisition front and, you know, drilling and development as we go into 26. Sounds good. Thanks, Tyler. You bet. Thank you, sir.

There are no further questions at this time. Ladies and gentlemen. That concludes today's call. Thank you all for joining. You may now disconnect.