Good morning, and welcome everyone to Granite Ridge Resources fourth quarter and full year 2025 earnings conference call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If you would like to ask a question, please press star one on your telephone keypad. To withdraw your question, press star one again. I will now turn the call over to James Masters, Vice President, Investor Relations. Thank you, operator. Good morning, everyone. We appreciate your interest in Granite Ridge Resources. We will begin our call with comments from Tyler Ferguson, our President and Chief Executive Officer, who will review the quarter's results and company strategy, along with an overview of 2026 financial and operating guidance and introduce our newly announced Chief Financial Officer, Kyle Kettler. He will turn the call over to Kyle to review our financial results in greater detail. Tyler will 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 in our earnings release on our website. Finally, this call is being recorded and a replay will be available on our website following today's call. With that, I'll turn the call over to Tyler. Thank you, James. Good morning, everyone. We are proud to report results for our third full year as a public company. While much has changed since the company went public in 2022, our commitment to pursuing the highest risk-adjusted rate of return projects and creating durable shareholder value remains the same. It is that commitment that drove our evolution from a traditional non-operated company pursuing a diversified investment strategy to a capital allocator focused on the Permian Basin, backing proven management teams to acquire and develop high-quality assets, a strategy shift that is the driving force behind our results. For the fourth quarter and full year of 2025, average daily production increased 27% year-over-year to 35,100 BOE per day. Total production for the year increased similarly to 32,000 BOE per day. Adjusted EBITDAX for the quarter was approximately $70 million and $315 million for the full year. Capital expenditures for the fourth quarter were $127.5 million, split approximately half to development and half to inventory acquisitions. Our full-year CapEx was $401 million. Finally, we maintained our quarterly dividend of $0.11 per share, which continues to demonstrate our commitment to return meaningful capital to shareholders. Since going public, we have significantly increased production while maintaining a conservative balance sheet. That capital-efficient growth is a result of consistently hitting our underwriting targets and increasing our capital allocation to operator projects, thanks to a structural opportunity we identified in the market. Over the past decade, private capital retreated from the natural resources sector in a major way, fundamentally changing the landscape for energy development. Private equity fundraising declined dramatically, and the remaining capital focused on fewer teams chasing larger opportunities. This left a scarcity of capital and competition in the unit-by-unit operated segment. At the same time, proven operating teams who had built and sold successful companies increasingly lacked access to aligned capital partners. Granite Ridge recognized the opportunity and stepped into the gap by developing our operative partnership model. We first partnered with Admiral Permian Resources, a Midland-based operator with multiple successful exits and deep ties in the community. Central to our strategy was that the Delaware Basin, containing some of the highest quality shale resource in the world, is now controlled by a small number of large asset managers overseeing vast overlapping land positions. These land positions come with a variety of complications like lease expirations, fragmented working interests, and inventory management issues that can turn into high-return drilling opportunities for the right partner. Granite Ridge, through Admiral, has become that partner. Over the past three years, we have executed over 50 transactions across the Permian Basin and have grown net production to nearly 10,000 BOE per day. Granite Ridge and Admiral have become preferred counterparties, and inventory additions continue to outpace our two-rig development program. We've also signed up three additional operator partners, each pursuing a different strategy in the Permian. We've been deliberate about limiting public disclosure of these partners to preserve their competitive positioning. Each team has successfully built and exited private equity-backed companies in the Permian and have significant personal capital invested alongside us, creating meaningful alignment. We look forward to sharing their progress and demonstrating the scalability of the operator partnership strategy. These partnerships greatly expanded our proprietary deal flow, which was already a competitive strength. Last year, we reviewed nearly 700 opportunities with a capture rate of just 15%. In 2025, we invested $122 million across 107 transactions. Securing approximately 20,500 net acres and 331 gross or 77.2 net locations, almost exclusively split between two buckets. Non-operated in the Utica Shale and operated partnerships in the Permian. Because we focus on short cycle opportunities underwritten at strip pricing, our entry costs remain notably low relative to large format transaction comps. In the Permian, our average acquisition cost per net location was just $1.4 million, far below recent public market transactions. This is a through cycle strategy. We target 25% full cycle returns at strip pricing, compound production, and cash flow growth, and protect downside through disciplined leverage. Since our first operated partnership investment with Admiral, we have fundamentally transformed our business from passive non-op to controlled capital with scale, growing production and high quality near-term inventory. The results of which are becoming clear in our financials and outlook. Granite Ridge came public with cash on the balance sheet and no debt, subscale. In the years since, we deliberately used leverage to achieve sufficient scale to support our next evolution, sustainable free cash flow. We're getting close. We see 2026 as a year of transition. Production growth is moderating and development capital expenditures are aligning more closely with expected cash flow. At current strip prices, we expect to achieve free cash flow from operations in 2027. The midpoints of guidance for production and capital for this year are as follows. We expect annual production to average 35,000 BOE per day, representing a 9% increase over 2025. We expect our exit in 2026 to be essentially flat or modestly up from exit in 2025. We forecast oil volumes to be approximately 51% of total production. Development CapEx are projected at $315 million, with an additional $20 million-$30 million for acquisitions that we currently have in the pipeline. Approximately 90% of the capital invested in 2026 will be focused on operated projects. To summarize, we will spend roughly 15% less than last year to achieve production growth of approximately 9%. At current strip pricing, we anticipate a modest outspend in 2026. One of our express goals for the business is to generate alpha through the expansion of cash flow above maintenance capital. We currently estimate maintenance capital of approximately $250 million, which provides room for disciplined growth above that level. We've built our business for capital efficient growth and free cash flow visibility at $60 oil. In response to the geopolitical shocks of the past week, we have added oil hedges and will continue to closely monitor the market. Recent events aside, we have been encouraged by the market resilience shown to date and remain bullish on the medium-term outlook. Should prices fall below $60 per bbl for a sustained period, we retain flexibility with our partners to adjust the development schedule and moderate capital deployment. Finally, let me expand on two recent announcements. Alongside Diamondback Energy, we partnered with Conduit Power to support the development of 200 MW of natural gas-fired power generation in ERCOT, scheduled to come online fully in 2027. This transaction will effectively provide a synthetic hedge to our Permian gas realizations and is expected to enhance value by approximately $1-$2 per Mcf on our gas exposed to this contract. We think similar opportunities may exist to further improve our gas realizations, and we'll be diligent in pursuing them. Second, we recently announced the appointment of Kyle Kettler as our chief financial officer after a six-month search. We went through a thoughtful, diligent process to find the right person that can help guide us through this next season of growth. Our business has matured and the challenges and opportunities are much different than they were a few years ago. We were looking for an oil and gas professional with tremendous experience in capital markets, but also someone with creativity and a track record of creating value. Somebody that could be a thought partner as we grow the business. We couldn't be happier that Kyle decided to join us. He brings significant capital markets expertise, an extensive network, and a keen strategic perspective that will be critical as we transition towards sustainable free cash flow in the next phase of Granite Ridge's development. I'm thrilled to welcome him to the team in his first earnings conference call. Kyle? Thank you, Tyler. Good morning, everyone. It's my pleasure to join my first Granite Ridge earnings call and look forward to spending time with our analysts and investors in the months ahead. Granite Ridge is building something truly different, allocating capital and creating value from a platform that's unique in public and private E&P. I'm excited to be here. Tyler covered the strategic highlights in 2026 outlook. I'll focus on the fourth quarter and full year financial results and our capital position. For the fourth quarter, oil and natural gas sales totaled $105.5 million. Revenue was essentially flat compared to the prior year quarter because of commodity pricing. Production grew an impressive 27% year-over-year. In the fourth quarter, our average realized oil price was $55.49 per bbl, compared to $65.53 per bbl in the same period last year. Natural gas averaged $1.81 per Mcf in the quarter, or 48% of Henry Hub. These weak realizations, particularly in the Permian Basin, had a meaningful impact on revenue and by extension, EBITDAX and operating cash flow. As a result, Adjusted EBITDAX for the quarter was $69.5 million, and operating cash flow totaled $64.5 million. For the full year, oil and natural gas sales totaled $450.3 million, with production increasing 28% year-over-year to 31,984 bbl equivalent a day. Full year Adjusted EBITDAX was $315 million, and operating cash flow was $296.4 million. The takeaway is straightforward. Our asset base is scaling. Oil remains roughly half of the mix, and volume growth is industry-leading. Pricing, especially Permian Basin, was a swing factor in the fourth quarter revenue and cash flow. That dynamic reinforces the importance of our initiatives like the Conduit Power transaction Tyler mentioned, which we expect will help improve Permian gas realizations over time. On the cost side, lease operating expense in the fourth quarter was $7.72 per bbl equivalent. That's higher than last year, driven primarily by our increasing focus on the Permian Basin. Service costs, primarily saltwater disposal, increased, a dynamic that's structural in the basin. For the full year, LOE averaged $7.27 a bbl equivalent. Our 2026 guidance for LOE is $6.75-$7.75 per bbl equivalent. Production and ad valorem taxes ran just under 6% of revenue in the quarter. G&A was $8 million, including $1.4 million of non-cash stock compensation. On a full year basis, cash G&A was what we expected. Annual guidance for these metrics are the same as last year. Production taxes of 6%-7% of revenue and cash G&A of $25 million-$27 million. Turning to capital, this is where the strategic shift Tyler described really starts to show up in the numbers. We invested $127.5 million in the fourth quarter, roughly half into development and half into acquisitions. For the full year, total CapEx was $401 million, including $279 million of drilling and completion CapEx and $122 million of property acquisitions. That acquisition CapEx was not large format M&A. It was nimble, repetitive, unit-by-unit inventory capture, high graded, and underwritten at strip. Our acquisition strategy gives us control over timing and capital intensity. We're not locking in multi-year development programs irrespective of commodity price. Operationally, we placed 67 gross wells online during the quarter and 322 gross wells for the year. That activity underpins the 28% annual production growth we delivered in 2025. On to the balance sheet. We exited the year with $350 million outstanding on the 2029 senior notes and $50 million drawn on the revolver. Liquidity totaled $339.5 million at year-end. Net debt to Adjusted EBITDAX was 1.2x inside of our long-term range. Looking ahead to 2026, we're deliberately shifting gears. The plan is to grow production while reducing capital spending. 2026 production is expected to average 34,000-36,000 BOE per day, with oil just under half the mix. Development capital is projected at $300 million-$330 million, with total capital of $320 million-$360 million, including acquisitions. The key point is this: growth is moderating, capital intensity is coming down, and development spending is aligning much more closely with expected cash flow. That transition from scale building to cash flow durability is the financial inflection point for the company. Through the transition, we're maintaining our $0.11 per share quarterly dividend. Stepping back, the last three years have been about scaling the platform and capturing inventory. While 2026 is about capital efficiency, balance sheet discipline, and positioning Granite Ridge to generate sustainable free cash flow. With that, I'll turn it back to you, Tyler. Thanks, Kyle. Let me close with a few high-level points. First, 2025 was a transformational year for Granite Ridge. We scaled the operated partnership model, expanded our controlled inventory in the Permian, and grew production 28% year-over-year. We leaned into an opportunity set that is structurally advantaged and difficult to replicate. Second, we're now shifting from outside growth to durability. Our 2026 plan reflects a moderation in growth, tighter alignment of development capital with cash flow, and a clear path towards sustainable free cash flow generation in 2027. Third, our competitive advantage is our structure and business development engine. By underwriting unit by unit at strip pricing, partnering with proven operators, and maintaining capital flexibility, we've consistently hit our investing underwriting targets, which has resulted in significant growth in production and asset value. Finally, we remain committed to balanced shareholder returns. The dividend remains a core component of our framework. As we cross into free cash flow, we'll have increasing optionality around capital allocation. We appreciate the continued support of our shareholders, partners, and employees and look forward to the year ahead. Operator, we're ready to take questions. We will now begin the question and answer session. Please limit yourself to one question and one follow-up. If you would like to ask a question, please press star one on your telephone keypad. To withdraw your question, press star one again. Please pick up your handset when asking a question. If you are muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster. Your first question comes from the line of Phillips Johnston with Capital One. Your line is open. Please proceed with your question. Hey, thanks for the time. Firstly question for Kyle. Your fourth quarter realized oil and gas prices as a percentage of NYMEX were a little bit lower than usual in the fourth quarter, especially on the gas side. I think in your comments, you sort of alluded to weak Waha prices as the driver on the gas side. That makes sense. That's not surprising. Is there anything to call out on the oil side? Also as a follow-up, what should we be thinking about for our models, in 2026 in terms of both oil and gas differentials? Yes. Thanks. Yes, the fourth quarter was weak on natural gas realization. That was driven by Waha pricing. We've got a substantial portion of natural gas coming from the Permian Basin, and that Waha base has widened out during the quarter two on us. Going forward, we've modeled that. You can see the Waha strip. We're utilizing that as a way to predict what Waha prices will be over the next year. Those prices are pretty low early in the year, and they tighten up a little bit towards the back end of the year. On 2027 going forward, the strip is much better, but still negative around $1 or so. On the oil side of the equation, there's really not anything particularly that sticks out. There's a bit of a negative difference between realized and benchmark prices, but we've got that in our model going forward as well. Okay. Sounds good. Then can you maybe give us a sense of how many net wells are planned for 26 relative to the 38 that you brought online last year? Would you expect any significant change in the mix for this year? I think last year's mix was close to 85% of the Permian, with most of the balance in Appalachia, Haynesville, and the DJ. I just kind of wanted to get some color there. You bet. Last year was 38 net wells turned online. Towards the end of the year, it got a little gassier with some Haynesville wells coming on. We see 2026 being about 29 net wells coming online. The relative mix of gas and oil should tilt back towards oil as the year goes on with more Permian Basin activity. Okay. Yeah. Phillips, on that point- Thank you. On the oil point, we're actually, if you look at oil production growth from 2025 to 2026, we actually see 12% growth there. A little more oil growth from 2025 to 2026 versus gas. Yeah. I guess that implies kind of your oil mix ticks back up to 51% from 49% in Q4 here. All right. Great. Thanks. Yes. That's all right. Your next question comes from the line of Derrick Whitfield with Texas Capital. Your line is open. Please proceed with your question. Good morning, guys, and congrats on the acquisition success you had in 2025. Thanks, Derrick. Wanted to start on slide 14. As you think about the business's transition to sustainable free cash flow in 2027, are you outlining that this morning as a business objective for 2027 based on your desire to lower leverage or is this based on your current view of the opportunities ahead of you? Not trying to pin you guys down as we live in a dynamic environment. I'm just trying to understand the driver and how firm the message is. Yeah. No, it's not an opportunity set driver. It is a leverage driver. We've spoken, you know, we've been very consistent about we wanna run the business, to you know, 1x-1.25x or so leverage, just to execute the base business plan. We've said that we would go north of that for something more strategic. To operate the base business plan, think of that as 1.25x. You know, again, we've planned. There's a lot going on in the world, as we all know right now. We've planned, you know, this year and next year more in a $60 oil environment. You know, that's the lens we're looking through when we're thinking about 2027 free cash flow. Obviously, with higher prices, you know, there's gonna be some additional capacity that we could take in 2026 and 2027, to continue to prosecute, you know, additional inventory capture or additional development drilling and still be able to deliver some free cash flow. Great. As my follow-up, I wanted to focus on your operated partnerships. We certainly appreciate what you're highlighting with Admiral in today's presentation. Could you maybe offer some color on general activity and inventory levels across your other operated partnerships? Sure. Yeah, I'd love to fill in some blanks there. We've spoken publicly about our first two. You know, Admiral had the benefit of getting a head start on our other three partners. They're the most mature and steady state of the four partners. I, you know, I think the Admiral story is pretty clear to everyone in the public domain. They're, you know, focused on Delaware Basin, unit by unit inventory capture from some of the larger asset managers in the basin. That story's been successful. We're running a couple of rigs there. We're adding inventory faster than the development base there. We hope to be able to replicate this same evolution with the other three partners. Partner two is actually PetroLegacy. We've mentioned that before, former EnCap act. That team is focused on the Midland, Northern Midland Basin, Dean play. They've captured a position there in the Dean play. We'll probably get started on some selective development of that position this year. That market's gotten extremely competitive as everyone knows. I'm not sure how much additional running room we'll have there. We're actually looking, the PetroLegacy team is looking at some other opportunities in the basin and also potentially outside of the basin. Hope to have some drilling results from them this year. Our third team, we haven't disclosed who that is, but I can tell you kind of what they're doing. They are again another successful team that's exited private equity. They are focused on some of the emerging plays in the Permian Basin, think, you know, Woodford Barnett. Those transactions will probably look a little more blocky from an acreage perspective. You know, larger chunks of acreage will come with some appraisal to, you know, figure out what exactly we have. If that's successful, that will add a lot of medium term inventory for us and, you know, start to fill in some of the development drilling in 2028 and beyond. Team four is our newest team. They're also a Midland-based team, successful exit from private equity. They look a lot like the Admiral team, except they're mainly focused on Midland Basin opportunities. I think they'll be, you know, sourcing opportunity from the larger asset managers out there kind of on a unit by unit basis. You know, we've, you know, we're probably about six months into that one, so that one's, you know, very new. They've already started to capture inventory. Typically, it takes us, you know, maybe 18 months or so, 12 months, to get enough inventory to have about, you know, 18 months to two years of inventory in front of the team, in order for us to justify picking up a rig. I probably wouldn't expect a whole lot of development activity from this, from that team this year. As we move into 2027, I think, we'll see them start to fill in with some development. Great. Great color. Greatly appreciate that, Tyler. You bet. Your next question comes from the line of Jared Giroux with Stevens. Your line is open. Please proceed with your question. Hey, good morning, guys. Thanks for taking my question. Morning. My first question is in regards to the move to generating free cash flow in 2027 versus continuing to at this same growth rate you've been doing the last couple of years. First part of the question is, how'd you decide to generate free cash flow versus growing? The second part is I know it's early, but if this free cash flow will be returned to shareholders, and if so, in what form are you guys thinking? Will this just be cash that goes on the balance sheet for maybe a good opportunity? Thanks. Yeah. Yeah. It's probably TBD on the second part. Obviously, you know, we've got a lot of options there. We'll kind of When we get there, we'll see kinda what the best option is at that time. I guess on the, on the first part, I mean, we, you know, we're wanting to transition the business into something that's more durable and long term. We think we've done a good job of gaining some scale over the past handful of years, maturing the business, maturing the strategy. We still see a ton of opportunity in front of us from an inventory capture standpoint. I think being able to show some free cash flow and, you know, keep our leverage, you know, around our target, which is still very conservative at 1.25x, that'll still give us a ton of opportunity, you know, to pursue additional inventory capture as we wanted to accelerate some. I'd just add the growth rate's been pretty significant over the last couple of years, and it'll still be high single digits going into next year. They'll still be, I feel like, pretty good growth. A lot of the capital spending is through operated partnerships, and that's based on a development plan we've coordinated with them. That puts us in this modeling position where we think we can see into 2026 and 2027 and turn into free cash flow in the 2027 time period. That's perfect. Thanks for the color. One more question, just about slide nine. Could you just give a little more color on that slide? Yeah, you talked about Granite retains 92% of the 10-year projected cash flows, and also at the Hamburglar well or pad that achieved a hurdle revision. Can you just give a little more details on this case study? Thanks. You bet. What we did here was just to give you an example of what the economics are between us and our, and our operated partners. We had some questions from investors over time on this one. The real thrust of it is to show that While we do have some reversions in the reserve database, they're effectively not very punitive at all. They're relatively very small on a multiple capital basis. That's really what we're trying to achieve with this in this slide. That's perfect. Thank you. Your next question comes from the line of Noah Hungness with Bank of America. Your line is open. Please proceed with your question. Good morning. For my first question here, I was just hoping you guys could touch on the opportunity set and the competitiveness you're seeing to add inventory. In 2025, you guys were able to add locations well below, I think, what we saw from going market price. How do you see those dynamics today? Good question. That opportunity still exists for us. Our operative teams are still executing on transactions that look exactly like that. We have, you know, roughly $25 million of acquisition CapEx scheduled right now. You know, that's basically what we have captured or what we have line of sight to now. If we wanted to continue to add inventory, and increase that budget, that opportunity is still available to us. I think, you know, again, like I said in the remarks, that's a good opportunity for us over the past couple years, and we see the operative partnership inventory captures, you know, having a number of years out in front of us on that front. As far as like the rest of deal flow, we've seen, you know, still very strong deal flow. I think we had, you know, a record last year on deal flow that we screened. That's continuing. The distributed wellbore market is still very strong. We don't participate in that market very much. Returns there aren't, you know, something that we'd underwrite to, but that's a very strong market. The larger kind of marketed packages, those are, you know, still out there with lots of divestiture targets from a lot of the consolidation. Again, we don't really participate in that market either. You know, lastly, on some of the smaller I'd say where we're seeing probably the least amount of deal flow, and kind of trending down has been in some of the smaller marketed processes for non-op. That's been a little bit weak, but again, that's not an area that we typically source opportunity from. I guess finally, in the Appalachia, Utica Shale Basin, we're still seeing a ton of opportunity there. That's a traditional non-op play for us, so we've been very successful over the past year and a half, leasing there. We actually added probably about another couple thousand net acres in the Utica play in Q4. We're continuing to see lots of opportunity there. That's helpful color. For my second question, Tyler, could you just talk about how we can think about the oil cadence through 2026, and then what does exit-to-exit production growth look like for oil? Yeah, sure. exit-to-exit oil production growth is 12%. That's Q4 2025 to Q4 2026. oil growth over the year, it'll be down a little bit in the first half, you know, single-digit, low single-digit decline kinda Q1 and Q2, and then increasing in the second half. again, from Q4 to Q4, we expect 12% growth. Great. Thank you. There are no further questions at this time. That concludes the conference call for today. We thank you for your participation and ask that you please disconnect your line. Have a great day.