Hello, everyone. Thank you for joining us, and welcome to the Granite Ridge Resources First Quarter 2026 Earnings Conference Call. After today's prepared remarks, we will host a question-and-answer session. If you would like to ask a question, please press star one to raise your hand. To withdraw your question, press star one again. I will now hand the conference over to James Masters, Vice President of Investor Relations. Please go ahead. 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. He will turn the call over to Kyle Kettler, our Chief Financial Officer, 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. You should not place undue reliance on these statements. These and other risks are described in our 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. 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. We delivered strong operational execution in the first quarter. 18% production growth year-over-year to 34,500 barrels of oil equivalent per day and adjusted EBITDA of $71 million. We are positioned well for continued growth in the back half of 2026, with a trajectory to free cash flow in 2027. Two items in the quarter require additional discussion: lease operating expense and continued Waha weakness, which I will address both before turning to what is, in my view, the more important story. The opportunity set in front of us has improved materially since we set guidance in March, and we are positioning the platform to capture it. Starting with the financials. Oil and natural gas sales totaled $128.3 million, a $5.3 million increase over the first quarter of 2025. Oil revenues drove the improvement with an 11% production increase and essentially flat realized pricing of $69.94 per barrel. Natural gas revenues declined by $6.3 million year-over-year, driven by a 36% decline in realized gas prices to $2.55 per Mcf, reflecting the ongoing impact of negative Waha pricing in the Permian. We've addressed this through an active basis hedging program. From February through April, we layered in Waha basis swaps across the fourth quarter of 2026 through the first quarter of 2028 at a weighted average basis of approximately - $1.50, covering roughly 45% of total Permian gas in the fourth quarter and stepping into 2027 with coverage rising to nearly 70% on a PDP basis when our conduit volumes are included. Turning to lease operating expense, LOE came in at $9.57 per BOE, above our prior guide, and was largely the result of a combination of increased early life flowback expense from an elevated level of wells turned to sales in Q4 2025, saltwater disposal costs, and a one-time charge tied to an asset impairment. A smaller structural piece comes from the DJ and Bakken, where production is naturally declining and fixed costs are spread over fewer barrels. We view the quarter as a near-term outlier rather than a change in our cost trajectory. As 2026 volumes come online, per unit LOE should trend lower, and Kyle will walk through our updated full year range. Let me now turn to the important part of the story. As capital allocators invest through cycles, our full cycle 25% underwriting threshold is always anchored to the long-dated strip. Spot prices have increased dramatically, and the forward curve has come up meaningfully as well, which has bolstered economics on near-term development opportunities. On the non-op side of the portfolio, we have seen some acceleration in AFEs, particularly in the Utica, adding to an already attractive set of opportunities in that basin. Additionally, on the operator partnership side, we are actively evaluating additions to the 2026 capital program that will reflect our ability to access high quality inventory that would otherwise be inaccessible to companies of our size. The most significant of these is a Permian Basin opportunity with a major operator who is seeking to grow near-term production but is budget constrained. This operator needed someone who can quickly secure a rig, fill the Bone Spring targets, complete the wells, and bring them online before year-end. Our Admiral Permian team is the right fit for this project. At a 55% IRR and 2.4 MOIC at strip, this is another opportunity that demonstrates the structural advantages of the operator partnership model, where relationships and local connections are not easily replicated and where a proven, reliable operator like Admiral can secure highly attractive projects in the heart of the Delaware Basin. On capital, we invested $68.4 million during the first quarter. $58.3 million of development capital and $10.1 million in acquisitions, closing 17 transactions in the Delaware and Utica Basins that added three net undeveloped locations to our inventory. Total capital was below the pace implied by our full year guidance, reflecting the timing of projects. As a result, first half development capital is weighted towards the second quarter, likely exceeding $100 million, with another $40 million slated for acquisitions. On guidance, we are making two changes today. We are raising the full year LOE guidance range to $7.75-$8.75 per BOE. We are increasing acquisition capital by $25 million at the midpoint, reflecting transactions we have completed and deals we have clear line of sight to close. Importantly, the majority of these acquisitions were agreed to before the significant shift in oil prices. Reflection of our deal flow and underwriting process rather than a response to the current price environment. They look even more attractive today. Development capital guidance is unchanged at $300 million-$330 million, resulting in total capital guidance of $345 million-$385 million. Production guidance remains 34,000-36,000 BOE per day. We believe we are on track to meet or exceed the midpoint. The capital we are deploying in 2026, including the incremental opportunities in front of us, is building the production base that will drive the 2027 inflection. This is the last year we expect to outspend operating cash flow, and we have clear line of sight to that destination and a framework that delivers durable growth, a double-digit free cash flow yield, and a sustainable dividend. I'll now turn the call over to Kyle for a deeper look into the quarter's results. Thank you, Tyler, and good morning, everyone. Tyler covered the strategic picture and operational context, so I'll focus on the financial details of the first quarter, our balance sheet and capital position. For the first quarter, oil and natural gas sales totaled $128.3 million, a $5.3 million increase over the prior year period. Oil revenues were $103.4 million, up from $91.8 million in Q1 2025, driven by an 11% increase in oil production to 16,433 barrels per day at an average realized price of $69.94 per barrel, compared to $69.18 per barrel in Q1 of 2025. Natural gas revenues were $24.8 million, down from a $31.1 million in the prior period, reflecting a 36% decline in realized prices to $2.55 per Mcf, partially offset by a 24% increase in production. The gas price deterioration, specifically the ongoing impact of negative Waha basis differentials in the Permian, was the primary headwind on revenue and cash flow for this quarter. On an equivalent basis, our average realized price was $41.35 per BOE, excluding settled hedge commodity derivatives, compared to $46.71 per BOE in Q1 2025, including settled derivatives, realizations were $37.53 per BOE for the quarter. Adjusted EBITDAX for the quarter was $71 million and net cash provided by operating activities was $58.3 million. On a GAAP basis, we recorded a net loss of $47 million or $0.36 per diluted share. The net loss is almost entirely attributed to a $72 million loss on derivatives during the quarter, of which $60.2 million was an unrealized mark-to-market loss, driven by an increase in oil prices during the period. Adjusted net income for the quarter was $3.1 million or $0.02 per adjusted diluted share. I want to spend a moment on lease operating expenses. As Tyler indicated, this warrants additional context. LOE was $29.7 million in the quarter, or $9.57 per BOE, compared to $16 million or $6.17 per BOE in Q1 2025. That's a 55% increase on a per unit basis. The increase reflects, first, higher saltwater disposal costs in the Permian Basin, which are largely due to higher water cuts in pullback operations. Second, higher miscellaneous supplies and contract labor, particularly in newer Admiral operating areas that have been online for six to 12 months and are still in a higher cost phase of operation, partly due to compression rental. Third, we wrote off minimum volume commitment obligations totaling $2.2 million in the quarter that was associated with our asset impairment charge. Fourth, the D.J. and Bakken, where we have no new development, continue to see fixed costs spread over declining production, creating upward pressure on per unit LOEs. We believe this number will improve as new wells that come online throughout 2026 add to production volumes and dilute these fixed cost elements. As Tyler mentioned, we're increasing our full year LOE guidance to $7.75-$8.75 per BOE. Production ad valorem taxes were $8.2 million for the quarter, or 6.4% of oil and natural gas sales, which is in line with our guidance of 6%-7% of revenue. Total G&A was $9.1 million for the quarter, inclusive of $1.4 million of non-cash stock compensation. Cash G&A was $7.7 million, reflecting an increase from the prior year, primarily driven by an amendment to our management services agreement. On a per unit basis, G&A was $2.93 per BOE, modestly higher than $2.84 per BOE in 1Q 2025, reflecting an increase in stock compensation. Turning to capital, we invested $68.4 million during the quarter, comprised of $58.3 million of development capital and $10.1 million of property acquisition costs. We closed 17 acquisitions in the Delaware and Utica basins, adding three net undeveloped locations to our inventory. Development capital is below the run rate implied by our full year guidance range, primarily driven by project timing rather than any reduction in planned activity. We placed 1.4 net wells online during the quarter. As Tyler mentioned, we are actively evaluating additional development opportunities that could increase our development capital spending in the back half of the year. We may raise our D&C guidance range when we report 2Q results in August, when we have better visibility into the timing and certainty of those incremental projects. Today, we're revising our acquisition capital guidance upward by $25 million at the midpoint to reflect transactions completed in near-term line of sight deals, resulting in total capital guidance of $345 million-$385 million. On the balance sheet, as of March 31st, we had $400 million of long-term total debt outstanding, comprising of our 2029 senior notes and drawn amounts on our credit facility. We also had a current portion of $26.3 million in cash on hand at $30.1 million. Total debt to trailing 12 months adjusted EBITDAX was 1.3 x at quarter end. Subsequent to quarter end, we reaffirmed our borrowing base and aggregate elected commitments to $375 million. As of March 31st, 2026, our total liquidity was $314.8 million, consisting of $248.7 million of committed borrowing base availability and $30.1 million of cash. We believe this improved liquidity position provides ample flexibility to pursue our capital program and the incremental opportunities in front of us. On hedging, during the first quarter, we recorded a $72 million loss on derivatives, of which $11.8 million was realized and $60.2 million was unrealized. The unrealized portion reflects the mark-to-market impact of rising oil prices on our hedge book during the period. We view our hedge program as a risk management tool consistent with our balanced capital allocation framework. Please see the derivatives table in our press release for our current hedge position, which extends through 2028. To summarize, production growth is strong. The balance sheet and liquidity are in good shape. We're maintaining our full year guidance with targeted revisions to acquisition guidance and LOE guidance. LOE is a near-term challenge, and we are focused on improving it. The 2027 free cash flow inflection story remains intact. With that, I'll turn it over back to you, Tyler. Thanks, Kyle. Let me close with a few high-level points. First, and most important, this is the year we transition out of outspend, and we are looking ahead to 2027, committed to a capital allocation framework that achieves high single-digit production growth, more than 10% free cash flow yield and approximately 1.25x dividend coverage. This is the framework the business has been built to deliver. Second, our 18% year-over-year production growth in the first quarter further demonstrates that our deployed capital has translated into meaningful scale, one that supports our 2027 free cash flow inflection. Third, two items weighed on the quarter: LOE and Waha pricing. We believe per unit LOE will moderate as the Q4 completions mature and 2026 volume scale and the Waha basis hedges from the fourth quarter of 2026 through the first quarter of 2028 will add protection against the weakness we saw this quarter. Neither item disturbs our trajectory towards 2027 free cash flow. Fourth, the opportunity set in front of us is better than expected. The operator partnership model is delivering proprietary deal flow that validates the underwriting assumptions we made when we entered into these partnerships. Admiral's deep local relationships with large independents and majors active in the Delaware Basin are creating high return development opportunities that are a direct result of the structural advantages we have built as a partner of choice. We underwrote all of these projects at strip pricing at the time of underwriting and at more than 25% full cycle IRR. Higher prices make them even more attractive. The dividend remains a core component of our shareholder return framework. As we approach free cash flow generation, we expect to have increasing optionality around capital allocation and returns to shareholders. We appreciate the continued support of our shareholders, partners and employees, and we look forward to continuing this dialogue at our upcoming investor meetings and in August when we report second quarter results. Operator, we're ready to take questions. We will now begin the question and answer session. If you would like to ask a question, please press star one to raise your hand. To withdraw your question, press star one again. We ask that you pick up your handset when asking a question to allow for optimum sound quality. If muted locally, please remember to unmute your device.Your first question comes from the line of Michael Scialla with Stephens. Your line is open. Please go ahead. Yeah. Good morning, guys. Just wanted to ask about your plans to increase the acquisition CapEx. Is that all for the opportunity that Tyler, you described with Admiral and the large operator in the Delaware? Or is there some incremental spending beyond that, or just give some more detail there. Morning. Thanks for the question. There's actually incremental spending beyond that. That's really what I described was really additional D&C capital that we're evaluating right now. Really on the acquisition front, that's spread across a bunch of transactions that we expect to close in the second quarter. Most of these transactions we agreed to before the increase in commodity prices. Returns on these things are, you know, great. You know, we underwrite everything to a 25, but with the improvement in commodity prices, these look a lot better. It's spread, you know, it's probably spread across, you know, half a dozen to a dozen transactions. It's mainly Permian based. There's actually quite a bit of activity from our newest partner that we signed up in October of last year. They have a number of transactions that are scheduled to close during the quarter. Admiral has a few. The balance of the transactions, probably maybe 15% or so of the transactions are additional leasing in the Utica Shale in Ohio, where we continue to see pretty good success up there. One last- Just to clarify. Just- Oh, go ahead. Yeah. Remember we guide on the acquisition front, we guide to, you know, everything that we've closed, plus transactions that are in process of closing that, you know, we believe have a better than 50% chance of closing. That doesn't include, you know, any additional A&D that we may do in the back half of the year. The $25 million increase in the acquisition CapEx is for transactions that we believe will close in the second quarter. Okay. I just wanted to clarify. You said the opportunity with Admiral, you've got the acreage in hand already. Kyle mentioned that, you know, you could have some upward pressure on your D&C CapEx. Is that where that would come from if that opportunity comes to fruition? Yeah. Is that already built into? No, that's exactly right. That's where it would come from. We have, you know, a couple of opportunities that look like this with Admiral that we're evaluating now that, you know, I think, you know, will be back half of the year CapEx spend. It's something that we're working through finalizing right now. To the extent that that comes to fruition, you know, we'll obviously have an update for you in August when we have second quarter earnings on that. Got it. Okay. Thanks for that. Wanted to ask on your plans for the free cash flow inflection next year. When I look at your slide 14, you lay out a plan there that shows CapEx going down relative to 2026. I guess I'm wondering how you manage to do that while you're ramping up these partnerships. If I heard you right, too, Tyler, you said that you would still anticipate double-digit growth next year. Is that right? Yeah. Yeah. High single-digit, low double-digit production growth is where we see the business moving to, you know, starting in 2027. You know, one thing that's helping us in 2027 is on the Admiral front. A bulk of the startup CapEx has been invested. If you actually look at our J curve on our Admiral operator partnership, we crossed on that. The Admiral team, you know, if you just look at that investment, that operator partnership is actually, you know, self-sustaining, you know, pretty much starting back half of this year moving forward. That helps us tremendously in 2027 with our free cash flow inflection. We, you know, have the capacity to then also ramp up some of the other teams that we've signed up in the past year. Great. Appreciate it. Thank you. You bet. Your next question comes from the line of Derrick Whitfield with Texas Capital. Your line is open. Please go ahead. Good morning, and thanks for your time. Morning, Derrick. I wanted to start first, on the Permian opportunity you referenced with Admiral. Could you further elaborate on the scale and potential duration of these opportunities? Yeah. Yeah, you bet. You know, this is something that we see, you know, more, you know, it's not all the time, but we see and in the past handful of years have seen this more and more where a lot of the large independents and large majors in the Permian Basin are, you know, seeking to find more partners to basically expand the capability of their capital budgets. They're hesitant to increase their capital budgets is, you know, the observation that we've seen over the past handful of years. Because of that, you know, they still want to show some form of production growth or, you know, more efficient capital spending. They look to teams like the Admiral team, who has the capability to come in, farm out some of their acreage from them in exchange for a carry. It's neutral to their, to the, you know, large independent capital budget and capital spend. It provides them with some incremental production, you know, to help with efficiency, et cetera, et cetera. This is something that, you know, the Admiral team has been very successful on, transacting on, over the past handful of years. We've seen a little bit of acceleration here on this particular style of transaction since the beginning of the Hormuz conflict. Just given that, you know, still, looks like a majority of the operators are not ready to increase capital spend yet, but would like to capitalize on some of the higher prices. We've seen some recent inbounds on this. This is an example of one that we talked about earlier on the call. I would expect that we'd probably see some more of these. Tyler, just in terms of scale, I mean, should we think about this as $25 million, $50 million, $100 million? Just order of magnitude, what? It's gonna be, you know, it depends on, you know, what it is. On this particular one, you know, I would think it would be on the smaller end of that kind of range that you mentioned, you know, just a second ago. Great. Just thinking beyond Admiral, are there other operational leverage you could pull to accelerate well production in the current environment? Yeah, absolutely. You know, we have other operator partners that do have inventory. We do have, you know, some development scheduled with them this year. I mentioned a moment ago that, you know, 2Q, we expect one of our newest partners to close on a number of transactions. Those are drill ready transactions, you know, to the extent those get closed up in the second quarter. Those are drill ready transactions that if we chose to, we could slot them in later in 2026. There's definitely opportunity within the operated portfolio. On the non-op portfolio, we've actually seen an increase in AFEs in the Utica Shale in Ohio. We've seen a number of operators, you know, or a number of AFEs come in from operators where we had those scheduled for 2028, 2029 turn to sales. Those have accelerated now into this year. In the Permian, in our non-op portfolio, we haven't seen a material change to what our historical average is on that front, on the AFEs. You know, I guess if we continue to see high prices, elevated prices, I would expect at some point for us to see an increase in AFEs off of traditional non-op in the Permian as well. Tyler, just to clarify on the other operated partners, safe to assume that the higher prices we're seeing right now are not negatively impacting their ability to source opportunities? No. No. Quite a few opportunities in the market. Yeah. No, it's not impacting them because again, we're underwriting near-term development drilling mainly. When I say near term, I mean, you know, turning online in the next, you know, kinda 18 months-ish. If you look at the forward strip, most of all of this volatility, nearly, you know, nearly all of this volatility that we've seen is contained within 2026. If you look out to 2027, which is where, you know, most of the stuff that we're underwriting would be turning on to sales, you know, you have a script that looks not a whole lot different than where we were before the before the Hormuz conflict. No, we haven't seen, in the style of transactions that we're underwriting, you know, a slowdown in that type of activity. Great. Thanks for your time. You bet. Thank you. This concludes today's call. Thank you for attending. You may now disconnect.