GRNT

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 1 to raise your hand. To withdraw your question, press star 1 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 34.5 thousand 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 negative $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 3 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 2 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 6 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 3 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 twelve months adjusted EBITDAX was 1.3 times 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, 2 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 split 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 Farquharson, 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 1 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.

Good morning, and welcome, everyone, to Granite Ridge Resources, Inc. 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 1 on your telephone keypad. To withdraw your question, press star 1 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, Inc. We will begin our call with comments from Tyler Parkinson, 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 then turn the call over to Kyle to 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 Resources, Inc. 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 will turn the call over to Tyler.

Thank you, James, and 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 nonoperated 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 2025, average daily production increased 27% year over year to 35,100 barrels of oil equivalent per day. Total production for the year increased similarly to 32,000 barrels of oil equivalent per day. Adjusted EBITDAX for the quarter was approximately $70,000,000 and $315,000,000 for the full year. Capital expenditures for the fourth quarter were $127,500,000, split approximately half to development and half to inventory acquisitions. Our full year capital expenditures were $401,000,000. 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 Resources, Inc. 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 interest, and inventory management issues that can turn into high-return drilling opportunities for the right partner. Granite Ridge Resources, Inc., through Admiral, has become that partner. Over the past three years, we have executed over 50 transactions in the Permian Basin and have grown net production to nearly 10,000 BOE per day. Granite Ridge Resources, Inc. and Admiral have become preferred counterparties, and inventory additions continue to outpace our two-rig development program. We have also signed up three additional operator partners, each pursuing a different strategy in the Permian. We have 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 $122,000,000 across 107 transactions, securing approximately 20,500 net acres and 331 gross, or 77.2 net, locations, almost exclusively split between two buckets: nonoperated 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 $1,400,000, 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 operator partnership investment with At Home, 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 Resources, Inc. came public with cash on the balance sheet and no debt, but subscale. In the years since, we deliberately used leverage to achieve sufficient scale to support our next evolution: sustainable free cash flow. We are 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 barrels of oil equivalent per day, representing a 9% increase over 2025, and 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 capital expenditures are projected at $315,000,000, with an additional $20,000,000 to $30,000,000 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 expressed goals for the business is to generate alpha through the expansion of cash flow above maintenance capital. We currently estimate maintenance capital of approximately $250,000,000, which provides room for disciplined growth above that level. We have 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 barrel 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 megawatts of natural gas-fired power generation 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 to $2 per Mcf on our gas exposed to this contract. We think similar opportunities may exist to further improve our gas realizations, and we will 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, a track record of creating value, somebody that could be a thought partner as we grow the business. We could not 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, the next phase of Granite Ridge Resources, Inc.’s development. I am thrilled to welcome him to the team in his first earnings conference call. Kyle?

Thank you, Tyler, and good morning, everyone. It is my pleasure to join my first Granite Ridge Resources, Inc. earnings call, and I look forward to spending time with our analysts and investors in the months ahead. Granite Ridge Resources, Inc. is building something truly different, allocating capital and creating value from a platform that is unique in public and private E&P. I am excited to be here. Tyler covered the strategic highlights and 2026 outlook, so I will focus on the fourth quarter and full year financial results and our capital position. For the fourth quarter, oil and natural gas sales totaled $105,500,000. Revenue was essentially flat compared to the prior-year quarter because of commodity pricing; however, production grew an impressive 27% year over year. In the fourth quarter, our average realized oil price was $55.49 per barrel, compared to $65.53 per barrel 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 $69,500,000, and operating cash flow totaled $64,500,000. For the full year, oil and natural gas sales totaled $450,300,000, with production increasing 28% year over year to 31,984 barrels equivalent per day. Full year adjusted EBITDAX was $315,000,000, and operating cash flow was $296,400,000. The takeaway is straightforward. Our asset base is scaling, oil remains roughly half of the mix, and volume growth is industry leading. Pricing, especially in the Permian Basin, was a swing factor in fourth quarter revenue and cash flow. That dynamic reinforces the importance of 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 barrel equivalent. That is higher than last year, driven primarily by our increasing focus on the Permian Basin. Service costs, primarily saltwater disposal, increased, a dynamic that is structural in the basin. For the full year, LOE averaged $7.27 per barrel equivalent. Our 2026 guidance for LOE is $6.75 to $7.75 per barrel equivalent. Production and ad valorem taxes ran just under 6% of revenue in the quarter, and G&A was $8,000,000, including $1,400,000 of noncash stock compensation. On a full-year basis, cash G&A was what we expected. Annual guidance for these metrics is the same as last year: production taxes of 6% to 7% of revenue and cash G&A of $25,000,000 to $27,000,000. Turning to capital. This is where the strategic shift Tyler described really starts to show up in the numbers. We invested $127,500,000 in the fourth quarter, roughly half into development and half into acquisitions. For the full year, total capital was $401,000,000, including $279,000,000 of drilling and completion capital and $122,000,000 of property acquisitions. That acquisition capital 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 are not locking in multiyear 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. Now onto the balance sheet. We exited the year with $350,000,000 outstanding on the 2029 senior notes and $50,000,000 drawn on the revolver. Liquidity totaled $339,500,000 at year end. Net debt to adjusted EBITDAX was 1.2 times, inside of our long-term range. Looking ahead to 2026, we are deliberately shifting gears. The plan is to grow production while reducing capital spending. 2026 production is expected to average 34,000 to 36,000 barrels equivalent per day, with oil just under half the mix. Development capital is projected at $300,000,000 to $330,000,000, and total capital is $320,000,000 to $360,000,000, 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. And through the transition, we are maintaining our $0.11 per share quarterly dividend. So, stepping back, the last three years have been about scaling the platform and capturing inventory, while 2026 is about capital efficiency and balance sheet discipline, positioning Granite Ridge Resources, Inc. to generate sustainable free cash flow. With that, I will 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 Resources, Inc. We scaled the operator 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 are now shifting from outsized 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 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 will 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 are 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 1 on your telephone keypad. To withdraw your question, please press 1 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. First, a 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 alluded to weak Waha prices as the driver on the gas side, so that makes sense and is not surprising. But is there anything to call out on the oil side? And 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, and that was driven by Waha pricing. We have a substantial portion of natural gas coming from the Permian Basin, and that Waha basis widened out during the quarter on us. Going forward, we have modeled that. You can see the strip. We are utilizing that as a way to predict what Waha prices will be over the next year, and those prices are pretty low early in the year, and they tighten up a little bit towards the back end of the year, and then 2027 going forward. The strip is much better but still negative around a dollar or so. On the oil side of the equation, there is not anything particularly that sticks out. There is a bit of a negative difference between realized and benchmark prices, but we have that in our model going forward as well.

Okay. Sounds good. And then could you maybe give us a sense of how many net wells are planned for 2026 relative to the 38 that you brought online last year? And would you expect any significant change in the mix for this year? I think last year’s mix was close to 85% in the Permian, with most of the balance in Appalachia, Haynesville, and the DJ. I just wanted to get some color there.

You bet. So 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, and the relative mix of gas and oil should tilt back towards oil as the year goes on with more Permian Basin activity.

Yes, Phillips, on that point, on the oil point, if you look at oil production growth from 2025 to 2026, we see 12% growth there, so a little more oil growth from 2025 to 2026 versus gas.

Yes, and that, I guess, implies your oil mix ticks back up to 51% from 49% in Q4 here. Alright. Great. Thanks.

Your next question comes from the line of Derek Whitfield with TPH&Co. Your line is open. Please proceed with your question.

Good morning, and congrats on the acquisition success you had in 2025. I wanted to start on slide 14. As you think about the business’ 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 it based on your current view of the opportunities ahead of you? I am not trying to pin you down as we live in a dynamic environment, just trying to understand the driver and how firm the message is.

It is not an opportunity set driver. It is a leverage driver. We have been very consistent about wanting to run the business to about one to one and a quarter leverage just to execute the base business plan. We have said that we would go north of that for something more strategic, but to operate the base business plan, think of that as one and a quarter. We have planned this year and next year in a more than $60 oil environment. That is the lens we are looking through when we are thinking about 2027 free cash flow. Obviously, with higher prices, there is going to be some additional capacity that we could take in 2026 and 2027 to continue to prosecute additional capture or additional development drilling and still be able to deliver some free cash flow.

Great. And as my follow-up, I wanted to focus on your operated partnerships. We appreciate what you are highlighting with Admiral in today’s presentation, but could you offer some color on general activity and inventory levels across your other operated partnerships?

I would love to fill in some blanks there. We have spoken publicly about our first two. Admiral had the benefit of getting a head start on our other three partners, so they are the most secure and steady state of the four partners. I think the Admiral story is pretty clear to everyone in the public domain. They are focused on Delaware Basin, unit-by-unit inventory capture from some of the larger asset managers in the basin. That story has been successful. We are running a couple of rigs there. We are adding inventory faster than the development base there, so we hope to be able to replicate this same evolution with the other three partners. Partner two is actually PetroLegacy. We have mentioned that before, former EnCap-backed. That team is focused on the northern Midland Basin Dean play. They have captured a position there in the Dean play. We will probably get started on some selective development of that position this year. That market has gotten extremely competitive, as everyone knows, so I am not sure how much additional running room we will have there. The PetroLegacy team is looking at some other opportunities in the basin and also potentially outside of the basin. We hope to have some drilling results from them this year. Our third team, we have not disclosed who that is, but I can tell you what they are doing. They are another successful team that has exited private equity. They are focused on some of the emerging plays in the Permian Basin—think Woodford, Barnett. Those transactions will probably look a little more blocky from an acreage perspective—larger chunks of acreage. They will come with some appraisal to figure out what exactly we have, but if that is successful, that will add a lot of medium-term inventory for us and start to fill in some of the development drilling in 2028 and beyond. Team four is our newest team. They are also a Midland-based team, an exit from private equity. They look a lot like the Admiral team, mainly focused on Midland Basin opportunities. I think they will be sourcing opportunity from the larger asset managers out there on a unit-by-unit basis. We are about six months into that one, so that is very new, but they have already started to capture inventory. Typically, it takes us maybe 12 to 18 months to get enough inventory to have about 18 months to two years of inventory in front of the team in order for us to justify picking up a rig. I probably would not expect a whole lot of development activity from that team this year, but as we move into 2027, I think we will see them start to fill in some development.

Your next question comes from the line of Jerry Giroux with Stephens. Your line is open. Please proceed with your question.

Good morning, and thanks for taking my question. My first question is in regards to the move to generating free cash flow in 2027. First, continuing at the same growth rate you have been doing the last couple of years, how did you decide to generate free cash flow versus growing? And the second part is, I know it is early, but if this free cash flow will be returned to shareholders, and if so, in what form are you thinking? Or will this just be cash that goes on the balance sheet for maybe a good opportunity?

It is probably to be determined on the second part. We have a lot of options there, and when we get there, we will see what the best option is at that time. On the first part, we want to transition the business into something that is more durable and long term. We think we have done a good job of gaining some scale over the past handful of years, maturing the business and the strategy. We still see a ton of opportunity in front of us from an inventory capture standpoint, but being able to show some free cash flow and keep our leverage around our target, which is still very conservative at one and a quarter times, will still give us a lot of opportunity to pursue additional inventory capture if we wanted to accelerate some.

I would just add, the growth rates were pretty significant over the last couple of years, and it will still be high single digits going into next year. So it will still be pretty good growth. A lot of the capital spending is through operated partnerships, and that is based on a development plan we have 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 is perfect. Thanks for the color. And then one more question about slide nine. Could you give a little more color on that slide? You talked about Granite Ridge Resources, Inc. retains 92% of the ten-year projected cash flows, then also that the Hamburglar wells or pads achieved the hurdle reversion. Could you give a few more details on this case study?

You bet. What we did here was just to give you an example of the economics between us and our operated partners. We had some questions from investors over time on this one. The thrust of it is to show that while we do have some reversions in the reserve database, they are effectively not very punitive at all. They are relatively very small on a multiple-of-capital basis, and that is really what we are trying to achieve with this end-of-slide.

That is 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.

Morning. For my first question, I was hoping you could touch on the opportunity set and the competitiveness you are seeing to add inventory. In 2025, you were able to add locations well below what we saw from going market price. How do you see those dynamics today?

Good question. That opportunity still exists for us. Our operator teams are still executing on transactions that look exactly like that. We have roughly $25,000,000 of acquisition capital expenditures scheduled right now. That is basically what we have captured or 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. As I said in the remarks, that has been a very good opportunity for us over the past couple of years, and we see the operated partnership inventory captures having a number of years out in front of us. As far as the rest of deal flow, we have seen still very strong deal flow. I think we had a record last year on deal flow that we screened, and that is continuing. The distributed wellbore market is still very strong. We do not participate in that market very much. Returns there are not something that we would underwrite to, but that is a very strong market. The larger marketed packages are still out there with lots of divestiture targets from a lot of the consolidation. Again, we do not participate in that market either. Lastly, on some of the smaller marketed processes for non-op, we are seeing probably the least amount of deal flow and trending down. That has been a little bit weak, but that is not an area that we typically source opportunity from. Finally, in the Appalachia Utica Shale Basin, we are still seeing a ton of opportunity there. That is a traditional non-op play for us. We have been very successful over the past year and a half leasing there. We added probably another couple thousand net acres in the Utica play in Q4, and we are continuing to see lots of opportunity there.

That is helpful color. And then for my second question, Tyler, could you 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?

Sure. Exit-to-exit oil production growth is 12%. That is Q4 2025 to Q4 2026. Oil growth over the year will be down a little bit in the first half—low single-digit decline in Q1 and Q2—and then increasing in the second half. From Q4 to Q4, we expect 12% growth.

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.