Good morning, and welcome to Granite Ridge Resources' Third Quarter 2025 Earnings Conference Call. I will now turn the call over to James Masters, Investor Relations representative for Granite Ridge.

Thank you, operator, and 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 31,900 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 0.9x, well below our long-term target range of less than 1.25x. 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 operator 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 3 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 operator partnership model is our most capital-efficient path to scale. Unlike many E&Ps that make large point-in-time acreage acquisitions exposed to multiyear 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 2 recently formed partnerships focused on the Midland and Delaware Basins. Collectively, these partnerships now encompass 28.1 net producing wells and 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 2 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 1,500 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 3 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 1.25x, 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 and invest through cycles. Commodity 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 million 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 31,000 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 EBITDAX of 0.9x, comfortably below our long-term target of 1.25x. 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've 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.

Your first question comes from the line of Michael Scialla with Stephens.

I 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?

Yes. 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. I think that it will take them 6 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 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.

I appreciate that detail. And Tyler, you mentioned you would in a $55 or lower oil price environment, cut CapEx back to $225 million next year. Can you provide a little bit more detail on that? I assume most of the production would come out of the partnerships. Maybe how much flexibility you have there in lay down rigs and crews? And how would the mix change going forward in that scenario versus your traditional non-op position versus the partnerships?

Yes, we anticipate that operators will act rationally, leading to a significant decrease in inbound AFEs for the non-operated portfolio. For our operated partnerships, we have complete control over the timing and pace of development. As we prepare our plan for 2026, we are incorporating a high degree of flexibility to potentially delay some activities if oil prices fall to the low $50 range. This control is what we appreciate about our operated partnerships, as it allows us to create a capital plan that aligns with our needs in response to lower prices. In addition to adjusting our drilling activities in a low price scenario, we would likely reallocate funds not just for inventory acquisitions but also potentially for some PDP style transactions.

It seems there is not really a change in the mix between traditional non-operational activities and partnerships, but both areas will be lower with less emphasis on drilling and more on acquisitions.

Yes. I think we'd love to be more opportunistic on acquisitions in that price environment.

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

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 steam and Petro legacy ramping? And then is it fair to assume PLE's production shows up more towards the second quarter or midyear?

Yes. I think on that last point on PLE, I think, yes, that is a midyear production contribution expectation for PLE. They're getting started drilling now. That will probably show up starting kind of late second quarter. On Admiral, they're running 2 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 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?

Yes. We actually love where we're at right now. Three to 5 years of inventory feels like the right amount of inventory for us. We're not interested in buying long-term inventory and having to warehouse that on the balance sheet for years 5 and beyond. I think having control over the operator partnerships gives us a lot more comfort in having 3 to 5 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. I think if anything, maybe we could get some more durability on some inventory outside of the Permian Basin. But we're pleased with where we are overall, particularly with what we've established in the Permian.

Your next question comes from the line of Noah Hungness with Bank of America.

For my first question here, I wanted to touch on LOE. It was a little higher than we thought for the third quarter. Can you maybe just talk about how we should expect that to trend in 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?

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.

Yes, Noah, we are exploring other options for our Permian gas. There are many gas-powered projects out there that other operators in the basin are considering, and we are also evaluating similar alternatives. We believe this could be a viable solution for some of our Waha gas, in addition to hedging against our Waha exposure. As we move into next year, we're examining multiple approaches for managing our Waha gas.

I really appreciate that insight. Building on that, how should we think about the pricing for that? Is it related to power exposure, a premium to Waha, or is it a flat price?

It would be some power exposure that we'd realize as a premium to Waha.

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

Thanks for the color on how production volumes could trend into Q4. I wanted to ask the same question on how CapEx should trend into Q4. If we look at what's implied for Q4 based on your unchanged guidance range, the potential range for Q4 is pretty wide at around $125 million to $150 million. 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.

Yes. Yes. So we had some timing adjustments on the acquisitions. Our development capital actually came in where we thought it would be for the quarter. So 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 fourth quarter 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 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 have?

It's all returns driven, right? Where we're seeing the best opportunity now continues to be in the Permian. So I'd expect 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 rich condensate phase. We've been very successful this year on picking up a lot of inventory and acreage in that part of the play in Ohio. And we're starting to see AFEs come in. We actually have 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 drilling and development as we go into '26.

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.