Granite Ridge Resources Inc Aktie

Hello, everyone. Thank you for joining us, and welcome to the Granite Ridge Resources First Quarter 2026 Earnings Conference Call. [Operator Instructions]

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 then turn the call over to Kyle Kettler, our Chief Financial Officer, 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 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 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.

Finally, this call is being recorded, and a replay and transcript will be available on our website following today's call. With that, I'll turn the call over to Tyler.

Thank you, James, and good morning, everyone. 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 EBITDAX of $71 million and 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 onetime charge tied to an asset impairment. A smaller structural piece comes from the DJ at Bakken, where production is naturally declining and fixed costs were 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 elongated 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, build the Bone Springs 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 [ MOI ] 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 and 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. And 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 to $8.75 per BOE and 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. A reflection of our deal flow and underwriting process rather than a response to the current price environment and they look even more attractive today. Development capital guidance is unchanged at $300 million to $330 million, resulting in total capital guidance of $345 million to $385 million. Production guidance remains 34,000 to 36,000 BOE per day, and 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 in 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 in 2025. Natural gas revenues were $24.8 million, down from $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 a 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 scheduled 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 and flowback 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 the higher cost phase of operation, partly due to compression rental.

And third, we wrote off minimum volume commitment obligations totaling $2.2 million in the quarter that was associated with our asset impairment charge.

And fourth, the DJ and Bakken where we have no new development, continue to see fixed costs spread over declining production, creating upward pressure on per unit LOE. We believe this number will improve as new wells that come online throughout 2026 add to production volumes and dilute these fixed cost elements. But as Tyler mentioned, we're increasing our full year LOE guidance to $7.75 to $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% to 7% of revenue. Total G&A was $9.1 million for the quarter, inclusive of $1.4 million of noncash stock compensation. Cash G&A was $7.7 million reflecting an increase from 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 Q2 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 to $385 million.

On the balance sheet, as of March 31, 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 and cash on hand of $30.1 million. Total debt to trailing 12 months adjusted EBITDAX was 1.3x at quarter end. Subsequent to quarter end, we reaffirmed our borrowing base in aggregate elected commitments to $375 million. As of March 31, 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 the 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 our 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.

Finally, 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.

[Operator Instructions] Your first question comes from the line of Michael Scialla with Stephens.

Just wanted to ask about your plans to increase the acquisition CapEx. Is that all for the opportunity that Tyler, you described with Admiral in the large operator in the Delaware? Or is there some incremental spending beyond that? I want to just get more detail there.

Yes. Thanks for the question. Yes, 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. So returns on these things are great. We underwrite everything to a [ 25 ], but with the improvement in commodity prices, these look a lot better. So it's probably spread across 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. And then the balance of the transaction is 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.

And then one last -- just -- yes. Remember, we guide to -- on the acquisition front, we guide to everything that we've closed plus transactions that are in process of closing that we believe have a better than 50% chance of closing. So that doesn't include any additional A&D that we may do in the back half of the year. So 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 on -- so you said the opportunity with Admiral, you've got the acreage in hand already. Kyle mentioned that you could have some upward pressure on your D&C CapEx. So is that where that would come from if that opportunity come to fruition or is that already built into the...

Yes. No, but that's exactly right. That's where it would come from. So we have a couple of opportunities that look like this with Admiral that we're evaluating now that I think will be back half of the year CapEx spend. It's something that we're working through finalizing right now. So to the extent that, that comes to fruition, we'll have -- obviously have an update for you in August when we have second quarter earnings on that.

Got it. Okay. And then I 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 managed to do that while you're ramping up these partnerships? And if I heard you right, too, Tyler, you said you would still anticipate double-digit growth next year. Is that right?

Yes. So high single digit, low double-digit production growth is where we see the business moving to starting in 2027. One thing that's helping us in '27 is on the Admiral front where a bulk of the startup CapEx has been invested. So if you actually look at our J-curve, on our Admiral operator partnership, we've troughed on that. So the Admiral team, if you just look at that investment, that operator partnership is actually self-sustaining pretty much starting back half of this year moving forward. So that helps us tremendously in 2027 with our free cash flow inflection. So we have the capacity to then also ramp up some of the other teams that we've signed up in the past year.

Your next question comes from the line of Derrick Whitfield with Texas Capital.

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?

Yes, you bet. So this is something that we see more -- 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 seeking to find more partners to basically expand the capability of their capital budgets. So they're hesitant to increase their capital budgets is the observation that we've seen over the past handful of years. And so because of that, they still want to show some form of production growth or 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. So it's neutral to their -- to the large independents capital budget and capital spend, but it provides them with some incremental production to help with efficiency, et cetera.

So this is something that 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 it 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. So 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.

And 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 -- how would you characterize it?

It's going to be -- it depends on what it is. On this particular one, I would think that it would be on the smaller end of that kind of range that you mentioned just a second ago.

Great. And then just thinking beyond Admiral, are there other operational levers you could pull to accelerate oil production in the current environment?

Yes, absolutely. So we have other operator partners that do have inventory. We do have some development schedule with them this year. I mentioned a moment ago that 2Q, we expect one of our newest partners to close on a number of transactions. Those are drill-ready transactions 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. So there's definitely opportunity within the operated portfolio.

On the non-op portfolio, we've actually seen an increase in the Utica Shale in Ohio. We've seen a number of operators with -- or a number of AFEs come in with -- from operators where we had those scheduled for '28, '29 turned 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. 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 the traditional non-op in the Permian as well.

And Tyler, just to clarify on the other operating partners. Safe to assume that the higher prices we're seeing right now are not negatively impacting their ability to source opportunities? I imagine quite a few opportunities in the market.

Yes. No, it's not impacting them because, again, we're underwriting near-term development drilling mainly. And when I say near term, I mean turning online in the next kind of 18 months-ish. So if you look at the forward strip, most of all of this volatility, nearly all of this volatility that we've seen is contained within 2026. So if you look out to 2027, which is where most of the stuff that we're underwriting would be turning on to sales. You have a script that looks not a whole lot different than where we were before the Hormuz conflict. So no, we haven't seen in the style of transactions that we're underwriting. We haven't seen a slowdown in that type of activity.

This concludes today's call. Thank you for attending. You may now disconnect.

Good morning, and welcome, everyone, to Granite Ridge Resources' Fourth Quarter and Full Year 2025 Earnings Conference Call. [Operator Instructions]

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 Farquharson, 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 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 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, 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 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 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 the scarcity of capital and competition in the unit-by-unit operated segment. At the same time, proven operating teams who have 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 operated partnership model. We first partnered with Atmel Permian Resources, a Midland-based operator with multiple successful exits and deep ties in the community. Central to our strategy was at 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 through Admiral has become that partner.

Over the past 3 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 2-rig development program. We've also signed up 3 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 2 buckets: non-operated in the Utica Shale and operated partnerships in the Permian. Because we focus on short-cycle opportunities under written 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 operator partnership investment with Athol, we have fundamentally transformed our business from passive non-op to controlled capital at 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, but subscale. In the year 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 midpoint 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 million, with an additional $20 million to $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 expressed goals for the business is to generate alpha through the expansion of cash flow above maintenance capital. We currently estimate maintenance capital of proximately $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 we'll 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 2 recent announcements. Alongside Diamondback Energy, we partnered with Conduit Power to support the development of 200 megawatts 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 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'll be diligent in pursuing them.

Second, we recently announced the appointment of Kyle Kettler as our Chief Financial Officer after a 6-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 and 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 development. I'm thrilled to welcome him to the team in his first earnings conference call. Kyle?

Thank you, Tyler, and 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. So 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. 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 $69.5 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 barrels equivalent a day. Full year adjusted EBITDAX was $315 million, and operating cash flow was $296.4 million. The takeaway 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 barrel 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 barrel equivalent our 2026 guidance for LOE is $6.75 to $7.75 per barrel equivalent. Production in Abalorem taxes ran just under 6% of revenue in the quarter and G&A was $8 million, including $1.4 million of noncash 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% to 7% of revenue and cash G&A of $25 million to $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 capital was $401 million, including $279 million of drilling and completion capital and $122 million 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're 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 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 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 to 36,000 barrels equivalent per day with oil just under half the mix. Development capital is projected at $300 million to $330 million with total capital of $320 million to $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. And through the transition, we're maintaining our $0.11 per share quarterly dividend. So stepping back, the last 3 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 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'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 investment underwriting targets, which has resulted in significant growth in production and asset value.

Finally, we remain committed to balance 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.

[Operator Instructions] Your first question comes from the line of Phillips Johnston with Capital One.

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 sort of alluded to weak Waha prices as we drive on the gas side. So that makes sense. That's not surprising, but is there anything to call out on the oil cagAndalso 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've got a substantial portion of natural gas coming from the Permian Basin. And that Waha basis widened out during the quarter too on us. Going forward, we've modeled that. You can see the last trip. We're utilizing that as a way to predict well how 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 27% 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. And 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? And -- 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. And at Pansend DJ. So I just kind of wanted to get some color there.

You bet. So last year, it was 38 net wells turned online towards the end of the year, got a little gassier with some Haynesville wells coming on. So 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.

Philips on that point on the oil point, we're actually if you look at oil production growth from 25% to 26%, we actually see 12% growth there. So a little more oil growth from 25% to 26% versus gas.

Yes. And I guess that implies kind of your oil mix picks back up to 51% from 49% in Q4 here. All right. Great.

Your next question comes from the line of Derrick Whitfield with Texas Capital.

Congrats on the acquisition success you had in 2025? I want wanted to start on Slide 14. As you think about the business' transition to sustainable free cash flow 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? And not trying to pin you guys got to be live in a dynamic environment. I'm just trying to understand the driver and how firm the message is.

Yes. No, it's not an opportunity set driver. It is a leverage driver. We've spoken -- we've been very consistent about we want to run the business to 1 to 1.25 or so leverage just to execute the base business plan. We've said that we would go north of that for something more strategic. But to operate the base business plan, think of that as quarter -- and again, we've planned -- there's a lot going on in the world, as we all know right now, we've planned this year, next year more in a $60 oil environment. So that's the lens we're looking through when we're thinking about 2027 free cash flow. Obviously, with higher prices, there's going to be some additional capacity that we could take in 2026 and '27 to continue to prosecute additional inventory 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 outside partnerships we certainly appreciate what you're highlighting with Admiral in today's presentation. But could you maybe offer some color on general activity and inventory levels across your other operated partnerships?

Sure. Yes. Yes, I'd love to fill in some blanks there. So we've spoken publicly about our first 2 Admiral has the benefit of getting a head start on our other 3 partners. So they're the most secure and steady state of the 4 partners. So I think the story is pretty clear to everyone in the public domain. They're focused on Delaware Basin, unit-by-unit inventory capture from some of the larger asset managers in the basin. So that story has been successful. We're running a couple of rigs there. We're adding inventory faster than the development base there. So we hope to be able to replicate this evolution with the other 3 partners. PARTNER II is actually Petro legacy. We've mentioned that before, former in back. That team is focused on the Northern Midland Basin Dean play. They've captured a position there in the Dean play will probably get started on some selective development of that position this year. That market has gotten extremely competitive as everyone knows.

So I'm not sure how much additional running room will have there. So we're actually looking -- the petro legacy team is looking at some other opportunities in the basin and also potentially outside of the basin. So I 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. I think it for Barnett -- and those transactions will probably look a little more blocky from an acreage perspective, larger chunks of acreage will come with some appraisal to figure out what exactly we have. But if that's successful, that will add a lot of medium-term inventory for us and start to fill in some of the development drilling in 2018 and beyond.

Team 4s, our newest team, they are also a Midland-based team a successful exit from private equity. They look a lot like the Admiral team -- it's up to mainly focused on Midland Basin opportunities, but I think there'll be sourcing opportunity from the larger asset managers out there kind of on a unit-by-unit basis. We've -- we're probably about 6 months into that one. So that 1 is very new, but they've already started to capture inventory. Typically, it takes us maybe 18 months or so, 12 months to get enough inventory to have about 18 months to 2 years of inventory in front of the team in order for us to justify picking up a rig. So I probably wouldn't expect a whole lot of development activity from that team this year. But as we move into '27, I think we'll see them start to fill in development.

Your next question comes from the line of Jared Guru with Stephens.

So my first question is in regards to move to generating free cash flow in 2027, First, continuing to -- at the same growth rate you've been doing the last couple of years. Yes. So first part of the question is, -- how do you decide to generate free cash flow versus growing? And the second part is, if you're -- 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? Or will this just be cash that goes on the balance sheet for maybe a good opportunity?

Yes. Yes, probably TBD on the second part. Obviously, we've got a lot of options there. So we'll kind of -- when we get there, we'll see kind of what the best option is at that time. I guess on the first part, I mean, 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 strategy -- we still see a ton of opportunity in front of us from an inventory capture standpoint. But I think being able to show some free cash flow and keep our leverage around our target, which is still very conservative at 1.25x. That will still give us a ton of opportunity to pursue additional inventory capture we wanted to accelerate some.

Yes. I'd just add, the growth rate has been pretty significant over the last couple of years, and it will still be high single digits going into next year. So there'll still be a 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. So that's that puts us in this modeling position where we think we can see into '26 and '27 and turn into free cash flow in the '27 time period.

That's perfect. And then 1 more question, just about Slide 9. Could you just give a little more color on that slide. Yes, you talked about Granite retained 92% of the 10-year projected cash flows -- and then also at the hamburger well or pad that achieved the hurdle revision. Can you just give a little more details on this case study.

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

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

For my first question here, just hoping you guys to touch on the opportunity set and the competitiveness you're seeing ad inventory in 2025 that you guys were able to add locations well below, I think, what we saw from going market price. So how do you see those dynamics today?

Yes. Good question. So that opportunity still exists for us. Our operator teams are still executing on transactions that look exactly like that. We have roughly $25 million of acquisition CapEx scheduled right now. That's basically what we have captured or what we have run sight to now. If we wanted to continue to add inventory and increase that budget, that opportunity is still available to us. I think, again, like I said in the remarks, that's been a very good opportunity for us over the past couple of years, and we see the operating partnership inventory captures having a number of years out sort of us on that front.

As far as like the rest of deal flow, we've seen still very strong deal flow. I think we had 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 something that we'd underwrite to, but that's a very strong market. The larger kind of marketed packages, those are still out there with lots of divestiture targets from a lot of the consolidation. Again, we don't really participate in that market either.

And 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 market processes for non-op. That's been a little bit weak. But again, that's not an area that we typically source opportunity from. And I guess, finally, in the Appalachia Utica Shale Basin, we're still seeing a ton of opportunity there. That's a traditional non-off play for us. So we've been very successful over the past year leasing there. We actually added probably about another couple of thousand net acres in the Utica play in Q4. We're continuing to see lots of opportunity there.

That's helpful color. And then for my second question, Tyler, could you just talk about how we can think about the oil cadence through '26 and then what is exit to exit production growth look like for oil.

Yes. Sure. So exit-to-exit oil production growth is 12%. That's Q4 25 to Q4 26. And then oil growth over the year -- it will be down a little bit in the first half, single-digit, low single-digit decline kind of Q1 and Q2 and then increasing in the second half. But again, from Q4 to Q4, we expect 12% growth.

There are no further questions at this time. That concludes the conference call for today.

Good morning, and welcome, everyone, to Granite Ridge Resources' Third Quarter 2025 Earnings Conference Call.

[Operator Instructions] I will now turn the call over to James Masters, Investor Relations representative for Granite Ridge.

Thank you, operator, and good morning, everyone. We appreciate your interest in Granite Ridge Resources. We will begin our call with comments from Tyler Farquharson, our President and Chief Executive Officer, who will review the quarter's results and company strategy. We will then turn the call over to Kim Weimer, our Interim Chief Financial Officer and Chief Accounting Officer, who will review our financial results in greater detail. Tyler will then return to provide closing comments before we open the call for questions.

Today's conference call contains certain projections and other forward-looking statements within the meaning of federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied. We ask that you review the cautionary statement in our earnings release. Granite Ridge disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on these statements. These and other risks are described in yesterday's press release and our filings with the Securities and Exchange Commission.

This call also includes references to certain non-GAAP financial measures. Information reconciling these measures to the most directly comparable GAAP measures is available on our earnings release on our website.

Finally, this call is being recorded, and a replay and transcript will be available on our website following today's call.

With that, I'll turn the call over to Tyler.

Thank you, James, and good morning, everyone. I appreciate everyone joining us today for our third quarter 2025 earnings call. Our results this quarter once again highlight the strength of our business model, grounded in disciplined capital allocation, operational excellence and strong execution across our platform and operating partners.

In the third quarter, average daily production increased 27% year-over-year to 31,900 barrels of oil equivalent per day. Adjusted EBITDAX rose 4% from the prior year period to $78.6 million. Capital expenditures totaled $80.5 million, consisting of $64 million in development and $16.5 million in acquisitions. We ended the quarter with a leverage ratio of 0.9x, well below our long-term target range of less than 1.25x.

In addition, we continued our quarterly dividend of $0.11 per share, underscoring our commitment to a reliable, competitive return to our shareholders. Subsequent to quarter end, we enhanced our capital structure and liquidity position. Earlier this week, our lending group reaffirmed the $375 million borrowing base on our revolving credit facility, and we successfully issued $350 million of senior unsecured notes due 2029 with an 8.875% annual coupon.

Together, these actions increased our pro forma liquidity to $422 million and further enhanced our flexibility to execute our business plan while preserving balance sheet strength. 2025 marks an important inflection point for Granite Ridge as we scale our operator partnership platform and further define our model as publicly traded private equity. Through these partnerships, we combine the control of an operator with the capital discipline of an investment firm, a framework that supports deliberate, cycle-resilient decisions around capital allocation and inventory selection.

Year-to-date, approximately 50% of our capital spending has been deployed from these partnerships. We are particularly pleased with the success of Admiral Permian Resources, our largest and longest-standing operator partnership, which continues to set the benchmark for performance. Admiral now controls 30 distinct drilling units across the Permian Basin and as of quarter end, had 63 producing wells with 14 more in progress.

Admiral's multi-horizon portfolio has consistently delivered results in line with our underwriting expectations while advancing technologies such as U-turn well design, further enhancing efficiency and cost control while also making them a preferred partner for larger asset managers.

So far in 2025, Admiral has added 61 gross, 17.2 net locations for an average of $1.9 million per net location, representing over $200 million of future development capital. In less than 3 years, the partnership has captured 198 wells, 94 net to Granite, representing nearly $1 billion of development capital. Admiral now produces 7,400 BOE per day net to Granite or 23% of Granite Ridge's total production.

Admiral's success illustrates why we believe the operator partnership model is our most capital-efficient path to scale. Unlike many E&Ps that make large point-in-time acreage acquisitions exposed to multiyear commodity cycle risk, Granite Ridge executes drilling unit level acquisitions, narrowly underwritten at current strip pricing for near-term development. We believe this approach provides superior risk-adjusted returns and flexibility.

While each partnership is unique, Admiral's success has become a blueprint for our other partnerships, including Petrolegacy and 2 recently formed partnerships focused on the Midland and Delaware Basins. Collectively, these partnerships now encompass 28.1 net producing wells and approximately 30.1 net undeveloped locations with an additional 37.7 net locations expected to close before the end of the year. Each partnership is structured to generate operated deal flow, strong full cycle returns and control over capital deployment and development timing.

Petrolegacy initiated its drilling program in the Midland Basin at the end of the third quarter, with production contributions expected early next year. Meanwhile, our 2 newer operated partnerships are actively advancing business development initiatives expected to add meaningful high-quality inventory ahead of transitioning to development mode. Our traditional non-op business continues to deliver stable cash flow and diversification.

During the third quarter, we participated in 59 gross or 9.3 net wells turned to sales, primarily across the Permian and Appalachian Basins. We remain particularly encouraged by our results in the Appalachian Basin, where we've added over 1,500 net acres this year and consistently outperformed our underwriting expectations. Earlier this year, we increased our acquisition capital guidance by $100 million to capture attractive opportunities across both our operated and traditional non-operated strategies.

As of quarter end, we invested $43 million through our operator partnerships, adding 27 net wells and $20 million through non-operated acquisitions, adding 6.7 net wells, primarily in the Delaware Basin and in Appalachia. Before year-end, we expect to invest an additional $47 million to secure 38 net locations, along with additional acreage in the Utica play. Collectively, these additions will add nearly 3 years of drilling inventory at an average cost of $1.7 million per net location.

Turning to the macro environment. Oil and gas prices have remained relatively stable over the past 12 months, providing a constructive backdrop for continued disciplined growth. We remain focused on opportunities that clear our 25% full cycle return hurdle and exceed our cost of capital even as we modestly outspend cash flow. As always, our spending and leverage remain guided by our leverage target range of 1 to 1.25x, and we're committed to staying within those bounds.

Looking ahead to 2026, we are constructive on the long-term oil outlook but cautious near term given uncertainty in global supply growth. We'll provide detailed guidance with our Q4 release but our strategic framework remains clear. Above $60 oil, we plan on pursuing measured growth with modest outspend. If we see sustained oil prices below $55 per barrel, we plan on pivoting to a maintenance mode targeting roughly $225 million in CapEx while maintaining flexibility for opportunistic acquisitions.

Our strategy is designed for agility, supported by a just-in-time inventory model, diversified asset base and minimal drilling commitments, allowing us to remain nimble through varying market conditions. We also continue to actively hedge around 75% of production each quarter with nearly 50% of expected 2026 volumes already hedged.

Combined with a strong balance sheet, this ensures we can operate and invest through cycles. Commodity markets will remain volatile, but our platform is built for it. We're confident Granite Ridge is well positioned for another year of disciplined growth, consistent returns and sustainable shareholder value in 2026.

With that, I'll turn it over to Kim for a detailed financial review.

Thank you, Tyler, and good morning, everyone. I'll start with a brief overview of our financial results. Revenue for the third quarter was $112.7 million compared to $94.1 million in the prior year period. Adjusted EBITDAX was $78.6 million, up 4% year-over-year. Net income was $14.5 million or $0.11 per diluted share, while adjusted net income was $11.8 million or $0.09 per diluted share.

Operating cash flow before working capital changes totaled $73.1 million. On the cost side, LOE came in at $8.03 per BOE, higher than expected, primarily due to an increase in saltwater disposal, contract labor and other service costs in the Permian Basin. Production and ad valorem taxes were 6% of sales and G&A was $2.38 per BOE, consistent with our guidance range.

Our disciplined capital allocation approach remains unchanged. For the quarter, total capital spending was $80.5 million, including $64 million of drilling and completion and $16.5 million of acquisitions. We continue to expect full year 2025 capital expenditures of $400 million to $420 million, of which $120 million is expected to be invested in 50 transactions that will add 75 net locations to Granite Ridge's inventory. Our development capital spend is allocated approximately 51% to operated partnerships and the balance to traditional non-op.

As we look ahead to the fourth quarter and into 2026, we expect continued production growth from our operated partnerships as new wells come online. We are maintaining our full year production guidance of 31,000 to 33,000 BOE per day with oil expected to represent roughly 50% of the mix. Our balance sheet remains a source of strength, ending the quarter with net debt to EBITDAX of 0.9x, comfortably below our long-term target of 1.25x.

We ended the quarter with $11.8 million of cash and $300 million drawn on our $375 million credit facility, resulting in liquidity of $86.5 million. As Tyler mentioned, we completed a $350 million issuance of senior unsecured notes due 2029 at an 8.875% coupon. This transaction strengthens our capital structure as we head into 2026 with net proceeds used to pay down the revolver and bolster cash on hand.

On a pro forma basis at quarter end, our liquidity increased to $422 million. We continue to return meaningful cash to shareholders. Our $0.11 per share quarterly dividend remains a central component of our total return framework, equating to an annualized yield of approximately 8.3% at recent prices.

With that, I'll hand it back to Tyler for closing comments.

Thank you, Kim. To wrap up, the third quarter was another strong quarter for Granite Ridge, marked by continued operational outperformance, excellent execution across our operator partnerships led by Admiral Permian, robust cash generation and disciplined capital management and steady shareholder returns. We've built a model that combines growth, yield and flexibility, and it's working, delivering durable value for our shareholders through the cycle.

Our business offers exposure to some of the best assets and operators in the country with downside protection through diversification, a robust hedge book and low leverage. Thank you to our employees, partners and investors for your continued support.

With that, we're happy to take your questions.

[Operator Instructions] Your first question comes from the line of Michael Scialla with Stephens.

I want to see if you could talk a little bit more about your third and fourth partnerships. You said they're both moving strategic plans forward. Anything else you can tell us there in terms of what those plans might look like and where they are in terms of potentially drilling or adding acreage?

Yes. So both of those partnerships are in aggregation mode right now. They're both Permian focused. One of the partnerships is focused on some of the emerging plays within the Permian and the other partnership is focused on the Midland Basin. I think that it will take them 6 or so months in order to aggregate what we like to see is about 18 months' worth of development in front of each one of those partnerships before we commit to running a rig full time on each one.

So I'd expect for us to have a little bit of activity, development activity in 2026, if they continue to be successful on aggregating inventory here over the next handful of months. During the fourth quarter, we actually have some of the first transactions with one of those partnerships closing in the fourth quarter. So we'll get some inventory via one of those partners in the fourth quarter. And then the last partnership that we signed up isn't too far behind. So I wouldn't expect a ton of development activity from them in 2026 but it just depends on how successful they are in aggregating inventory.

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

Yes. Yes, we'd expect to see coming out of the non-op portfolio, operators act rationally. So we'd expect to see a lot less inbound AFEs on the non-op piece. Then on the operated side, on the operated partnership side, we have full control over the timing and the development pace of those partnerships. And as we're starting to construct our '26 plan, we're building in tremendous flexibility there to be able to push some of that activity out if we do see a quarter or 2 worth of oil price in the low 50s. That's why we like the operated partnership so much is we do maintain that control over those partnerships to be able to construct a capital plan that kind of fits our needs as we -- if we end up experiencing some lower prices.

In addition to the drilling side, I think what you'd probably see from us in that low price scenario, we pulled back on some drilling. And I think we'd actually probably reallocate those dollars to not only inventory acquisitions, but also potentially maybe some PDP style transactions as well.

Okay. So not -- it sounds like not really a change in the mix between the traditional non-op and the partnerships but just both would be lower and less focus on drilling, more focus on acquisitions.

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

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

For my first one, understanding that there's lumpiness quarter-to-quarter and you haven't published guidance for next year, how should we think about the growth trajectory in the fourth quarter and into 2026 with Admiral running at full steam and Petro legacy ramping? And then is it fair to assume PLE's production shows up more towards the second quarter or midyear?

Yes. I think on that last point on PLE, I think, yes, that is a midyear production contribution expectation for PLE. They're getting started drilling now. That will probably show up starting kind of late second quarter. On Admiral, they're running 2 rigs now. We expect that to continue through 2026. I think on the production cadence, you're right, we haven't guided to '26 yet. So we can't really speak a whole lot to '26. But on Q4 of '25, we do expect to see somewhere in the high single digits production growth from the third quarter to the fourth quarter.

Terrific. For my follow-up, can you talk about what you see as the ideal length of inventory that you would like to get to? And how do you weigh that with the commodity underwriting risk that comes with that longer-dated inventory?

Yes. We actually love where we're at right now. Three to 5 years of inventory feels like the right amount of inventory for us. We're not interested in buying long-term inventory and having to warehouse that on the balance sheet for years 5 and beyond. I think having control over the operator partnerships gives us a lot more comfort in having 3 to 5 years' worth of inventory because it's actually controllable inventory now versus having to rely on non-op partners.

So we're actually quite pleased with where we are on our inventory. I think if anything, maybe we could get some more durability on some inventory outside of the Permian Basin. But we're pleased with where we are overall, particularly with what we've established in the Permian.

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

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

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

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

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

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

With regards to the first question, we do not currently have any basis hedges in place for our Waha exposure and going forward, have considered adding those, as you mentioned, for the strength of the curve going forward. So we will continue to look at that and evaluate that going forward.

Yes. Noah, there's -- we're also looking at other alternatives for our Permian gas. There's lots of gas to power projects out there that you've seen some other operators in the basin signing up or evaluating and that's also something that's on the table for us. We're looking at a few of those options now. We think that, that could also be a good solution for some of our Waha gas in addition to hedging some of the Waha exposure as well. So we're kind of looking at a solution for Waha gas a couple of different ways as we kind of move into next year.

I really appreciate that color. Just to kind of build off of that, if I could, how should we -- how could we think about the pricing for that? Is it power exposure? Is it a premium to Waha? Is it flat price?

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

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

Thanks for the color on how production volumes could trend into Q4. I wanted to ask the same question on how CapEx should trend into Q4. If we look at what's implied for Q4 based on your unchanged guidance range, the potential range for Q4 is pretty wide at around $125 million to $150 million. So just wanted to know if we should be steering towards kind of the midpoint of that range or towards the low end or the high end.

Yes. Yes. So we had some timing adjustments on the acquisitions. Our development capital actually came in where we thought it would be for the quarter. So we're not changing guidance for the full year. We still expect to close all the acquisitions that we outlined on our last call. for the year. So we just see that timing shifting into the fourth quarter. If I had to guess, I think that fourth quarter would be somewhere in the $125 million range with a big chunk of that being the remaining acquisitions that we're closing for the year.

Okay. Perfect. And then I appreciate the color on '26, and it's obviously early. But if we do assume current strip prices hold, how should we think about capital allocation for next year in terms of oil versus gas? Would you be inclined to kind of keep your investment mix roughly the same? Or would you sort of lean into gas a little bit more than you have?

It's all returns driven, right? Where we're seeing the best opportunity now continues to be in the Permian. So I'd expect a very significant oil weighting. That being said, outside of the Permian, we are via the traditional non-op strategy, having a lot of success in Appalachia, and that's more rich condensate phase. We're -- we've been very successful this year on picking up a lot of inventory and acreage in that part of the play in Ohio. And we're starting to see AFEs come in. We actually have a handful of pads already online in Ohio, and I would expect to see additional capital being spent up there on both acquisition front and drilling and development as we go into '26.

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

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

Thank you, operator, and good morning, everyone. We appreciate your interest in Granite Ridge Resources. We will begin our call with comments from Tyler Farquharson, our President and Chief Executive Officer, who will review the quarter's results and company strategy. We will then turn the call over to Kim Weimer, our Interim Chief Financial Officer and Chief Accounting Officer, who will review our financial results in greater detail. Tyler will then return to provide closing comments before we open the call for questions.

Today's conference call contains certain projections and other forward-looking statements within the meaning of federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied. We ask that you review the cautionary statement in our earnings release. Granite Ridge disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Accordingly, you should not place undue reliance on these statements. These and other risks are described in yesterday's press release and our filings with the Securities and Exchange Commission. This call also includes references to certain non-GAAP financial measures. Information reconciling these measures to the most directly comparable GAAP measures is available in our earnings release on our website.

Finally, this call is being recorded, and a replay and transcript will be available on our website following today's call. With that, I'll turn the call over to Tyler.

Thank you, James, and good morning, everyone. I'm excited to address you today as Granite Ridge's new CEO. Before diving into our second quarter results, I want to acknowledge the leadership transition that occurred during the quarter. Luke Brandenberg stepped down as CEO, and I'm honored to have been appointed to lead the company forward. Luke played a pivotal role in shaping Granite Ridge into the successful business it is today. And on behalf of the team, I want to express our gratitude for his significant contributions. We wish him all the best in his next chapter.

Turning to our Q2 performance. Our quarterly results continue to validate our business model with production and cash flow once again exceeding expectations. In the second quarter, we turned 4.9 net wells to sales and increased production by 37% year-over-year to 31,576 barrels of oil equivalent per day, driven by a 46% rise in oil production and a 28% rise in natural gas production. This growth reflects the strength of our diversified portfolio of oil and natural gas assets and our disciplined approach to capital allocation, which prioritizes the highest risk-adjusted returns.

Our operated partnership and traditional non-op investment strategies remain the driver of this success. We've partnered with 4 top-tier operators to unlock substantial value in the Permian Basin and are thrilled with the progress achieved to date. Meanwhile, our traditional non-op strategy continues to deliver consistent results with wells coming online ahead of schedule in the Permian and wells outperforming forecast in the Utica.

On the capital front, we spent approximately $77 million on development and $10 million on acquisitions for a total CapEx spend of $87 million. Year-to-date, we have invested approximately $149 million of capital on development activities, which is higher than forecast based on the accelerated timing activities and $44 million in acquisition capital expenditures. These acquisitions located in the Permian and Appalachian basins added high-quality inventory to our portfolio, enhancing our growth runway.

Given our first half performance, driven by stronger-than-modeled production and unexpected acceleration of new production, we are raising our full year production guidance by 10% at the midpoint to between 31,000 and 33,000 barrels of oil equivalent per day, which will result in year-over-year growth of 28%. We are also raising our capital expenditure guidance to an all-in range of $400 million to $420 million, driven mainly by new unbudgeted acquisitions expected to close in 2025.

Our deal team's tenacity and strategic approach have led to every transaction we sourced being off-market. For 2025, we anticipate deploying approximately $120 million in acquisition capital, adding 74 net locations. 80% of this capital targets the Permian Basin through our operated partnership strategy, the remaining allocated to our Appalachia leasing strategy, which has delivered exceptional results to date. Our business development engine is operating at peak performance, securing 3 additional years of inventory at an attractive entry cost of $1.7 million per location.

Our operator partners are doing exactly what we expect them to do, capture attractive development opportunities at below market value. They are doing an excellent job, and we're excited for the opportunity to fund these projects for the long-term benefit of our shareholders. Moving forward, our guidance will identify both development and acquisition capital expenditures separately, which we hope will offer more transparency for our investors.

We occupy a unique niche in the public energy market, looking like an energy company, but acting like an investment firm. Our vision is to become the leading public investment platform for energy development, and we will continue to invest alongside proven high-quality operating teams to capitalize on undervalued opportunity. Since commodity prices declined in early 2Q, we have moved aggressively to scale our operator platform and secure long-dated, low-risk inventory at highly attractive entry prices.

We have identified nearly $60 million of new inventory acquisitions, $40 million of which are located in the Permian Basin for our operator partners and $20 million of which are driven by organic acreage leasing in the Utica Shale.

Our strategy remains unchanged. We continue to underwrite development projects targeting full cycle returns exceeding 25%, deliver top quartile growth and return capital to shareholders through our quarterly dividend. This disciplined approach allows us to remain resilient in any market environment. We may not look like your typical E&P, but we are creating a ton of value.

Our investment strategy centers on operating partnerships with 2 gaining significant momentum. Our longest-standing partner is Midland-based Admiral Permian Resources. After selling their prior firm, Reliance Energy to Concho Resources for $1.6 billion, members of the management team founded the first iteration of Admiral Permian backed by Ares Management. Over a 3-year period, Admiral scaled its asset base in the Western Delaware Basin to 20,000 BOE per day before divesting to Petro Hunt with a trailing EBITDA of nearly $300 million.

I give you their impressive resume to highlight the value of our operator partnership program. We fund proven, highly talented teams to do what they do best, create significant value through finding and developing oil and gas. We are proud to partner with Admiral Permian Resources in their newest iteration. After just 2 years of partnership, Admiral produces over 7,000 BOE per day net to Granite Ridge or 22% of our total production. And as of June 30, post over 40 net locations of high-quality inventory.

PetroLegacy is our second partner focused on growing an asset position in the Midland Basin. Three years ago, the management team sold PetrolLegacy 2, then backed by [ in-cap ] investments to Ovintiv after growing production in the same area to 35,000 BOE per day. Our third and fourth partners signed in just the last couple of months are still confidential as they are just starting on their asset acquisition phase.

Each partner has their own story, their own unique investment strategy. But taken together, they've had a very specific investment thesis for Granite Ridge, which is that there now exists a void of private capital in the oil and gas space after a 70% decline in upstream private equity fundraising since 2018. The private capital that remains is focused on mega deals with concentrated portfolios. This altered supply and demand dynamic has lowered the entry cost and increased the resulting economic returns on smaller development projects.

Add to this that the core of the Delaware Basin, for example, is largely held by 7 operators overseeing massive asset packages, and it sets up remarkable opportunities for nimble and aggressive teams to piece together smaller deals at attractive prices. And that suits the traditional Granite Ridge model to [indiscernible]. For over a decade, our team's daily pursuit has been uncovering value in oil and gas through smart value-add investments, small deal after small deals, utilizing a huge proprietary data set to accurately underwrite hitting singles and doubles in the Permian basins across the United States.

We've done this successfully, enjoying the compounding effect of consistently investing to full cycle returns that comfortably exceed our cost of capital. The operator partnership strategy is not all that different. We still evaluate every deal with our partners and underwrite those with the highest risk-adjusted returns. From a macro perspective, volatility persists with oil and natural gas prices softening. Our diversified production mix, roughly balanced between oil and gas, provides a natural balance in our hedging program, covering approximately 75% of current production protects our cash flows.

Looking ahead, our priorities for the rest of 2025 are clear. First, we'll advance our operator partnership program, which will account for approximately 65% of our development capital spend this year. With 3 rigs currently running in the Permian, we have the flexibility to adjust activity based on market conditions. Second, we'll maintain a balance between growth and returns, supporting our 10% production increase while preserving our $0.11 per share quarterly dividend, which offers an attractive yield at current prices. Finally, we'll safeguard our financial flexibility.

Our balance sheet remains strong with a leverage ratio of 0.8x net debt to adjusted EBITDA. We enhanced liquidity following our borrowing base increase to $375 million in the second quarter, and we'll continue to bolster our liquidity by exploring the credit markets in the fall. Before I hand it over to Kim, I want to underscore my confidence in Granite Ridge's future. We have a proven strategy, a high-quality asset base and a talented team ready to execute. I'm excited to lead us through this next phase of growth and deliver value for our shareholders.

Thank you, Tyler, and good morning, everyone. I'll provide a detailed overview of our Q2 2025 financial results, which highlights our operational strength and disciplined financial management. In Q2, we generated total oil and gas sales revenue of $109.2 million, an increase of 20% compared to Q2 2024. This growth was driven by a 37% increase in production to 31,576 BOE per day. Oil revenues rose by $12 million, reflecting a 46% jump in oil production to 16,009 barrels per day, though partially offset by a 21% decline in realized prices from $77.84 per barrel in the prior year period to $61.41 this quarter.

Natural gas revenues increased by $6.6 million supported by a 28% rise in production to 93,404 Mcf per day and a 17% incline in realized prices from $1.98 per Mcf to $2.32 per Mcf. Net income for the quarter was $25.1 million or $0.19 per share, reflecting our strong operational performance. Operating cash flow before working capital changes was $69.5 million, providing robust liquidity to fund our capital program and dividends.

For the first half of 2025, net cash from operating activities totaled $154.1 million, up from $132.8 million in the prior year. On the cost side, lease operating expenses were $20.1 million or $7 per BOE compared to $13.7 million or $6.50 per BOE in Q2 2024. The increase reflects elevated service costs and higher saltwater disposal costs as the percentage of our production from the Delaware Basin has increased.

So we continue to optimize efficiency as we scale. General and administrative expenses rose by $1.9 million year-over-year to $8.5 million or $2.96 per BOE, driven by certain nonrecurring general and administrative expenses, including $1.7 million in severance expense tied to the leadership transition and $1.1 million related to capital markets activities. Excluding these nonrecurring items, G&A remains well controlled.

Capital allocation remains opportunistic. Development capital expenditures for the 6 months ended June 30 totaled $148.6 million, in line with our base case, while acquisition CapEx was $44.4 million, adding 17.5 net locations in the Permian and Appalachian basins. These deals enhance our inventory and position us for sustained growth. Total capital for the first half, including acquisitions, was $193 million. Our balance sheet continues to be a strength.

While long-term debt increased by $25 million this quarter to $275 million, reflecting opportunistic investments in inventory, our leverage ratio remains conservative at 0.8x net debt to adjusted EBITDA. We recorded a $23.9 million gain on derivatives, primarily unrealized due primarily to the decline in oil prices during the period. We also incurred a net loss on equity investments from the sale of Vital shares.

Looking forward, we're raising our full year production guidance to 31,000 to 33,000 BOE per day and our capital expenditure guidance to $400 million to $420 million. For Q3, we expect production to modestly grow above Q2 levels with further growth in Q4 as new wells come online. Capital spending will peak for the year in Q3 with a significant component of acquisition capital before moderating in the fourth quarter in both D&C and acquisitions.

Back to you, Tyler.

Thank you, Kim. In closing, I want to thank our team for their hard work and dedication, which has been critical to delivering these strong results. I also appreciate the continued support of our shareholders. As we move forward, I'm confident that Granite Ridge is well positioned to navigate market volatility and create long-term value. Our strategy is proven, our assets are exceptional, and our team is best in class. We remain committed to executing our plan, driving growth and returning capital to shareholders.

With that, operator, please open the line for questions.

[Operator Instructions]

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

I appreciate the color on the quarterly cadence in production. It sounds like up a little bit and then the significant growth really occurs in Q4. If you look at your guidance, it implies the oil mix is going to tick up around 53% in the back half of the year versus around 51% in the first half of the year. So I just kind of wanted to get a sense of what's driving that oil mix higher.

Yes. Thanks, Phillips. On oil cut, we actually were -- we think we'll be more like 52%. So we're slightly lower than what you have. So we are seeing some gas acceleration on some new projects from folks that are Haynesville that [indiscernible] focused. But predominantly where the growth is coming from is in the Permian, which is obviously an oilier mix than the existing asset.

Okay. That makes sense. And then the company's net debt increased to $270 million from around $195 million at the end of 2024. The updated guidance suggests that the outspend of cash flow this year is going to be a little bit wider than it would have been based on prior guidance. You have a strong balance sheet. You mentioned the leverage ratio is solid at 0.8x. You've got plenty of liquidity. So I guess with that backdrop, I just wanted to get a sense of the Board's appetite to continue adding to the net debt balance as we sort of look out beyond this year into 2026 and beyond.

Yes. So nothing's changed there on that front. So we've repeatedly said that we're comfortable in a 1 to 1.25x band. We ended the quarter 2Q at 0.8x. So we still have some capacity there. With what we're seeing in the acquisition market right now, we're really focused on leaning in on adding inventory, adding duration to the business. We think that's a really attractive investment at this point. So I think you'll continue to see us outspend cash flow until we get to where we're comfortable with leverage. And I think you could see us outspend again next year, particularly in an acquisition environment such as we're in now.

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

For my first one, I just wanted to get your thoughts on what you're seeing that has given you the confidence to lean into growth and acquisitions at this time, whether it's the macro current dynamics with PE funding that you highlighted in the slides or something else? Just some more color on that would be great.

Sure. Yes. Great question. So this is the most constructive environment that we've seen on the A&D front in quite some time. And I think a big component of that is just the lack of private equity capital in the space and the private equity capital that is left in the space is focused on much larger format transactions. So that's really left a pretty attractive space for us that fits our model well where we're able to just continue to aggregate smaller transactions at really attractive prices.

The other thing that's helping us now is we're adding operated partner teams. So we have 4 teams now that tremendously expands our opportunity set, our deal flow. This year, we're seeing A&D activity that we've evaluated up 15% versus where we were last year. So I think this setup really fits our model well. And then I think from a macro perspective, with the weakness on oil prices recently, we've seen a lot of the larger operators looking to rationalize their development capital spend, and that really leaves us an opportunity to help folks solve those issues that they have on CapEx efficiency.

Makes sense. And for my follow-up, maybe for you, Tyler, I wanted to get your views on how you see balancing adding inventory, adding growth and managing leverage. You've clearly been successful balancing the 3, but I just wanted to get a sense of how you're viewing these priorities in your new role.

Yes. That's exactly what we're thinking about every day, those 3 things. So I think right now, we're leaning into growth. We're leaning into scale. We think that added duration to our inventory is going to pay dividends down the road. And we're finding that A&D market very attractive right now to allow us to do that. So since the balance sheet is still in great shape right now, we're choosing to lean in there. That comes at the expense of free cash flow. But we believe over time, we'll get to a point where we will be more free cash flow neutral. But this market environment is really conducive to us adding scale and increasing our inventory.

And your next question comes from the line of Michael Scialla with Stephens.

Tyler, you mentioned you could outspend again next year. It sounds like you probably will. If you get all the acreage you anticipate with these acquisitions and the macro holds together, I guess trying to get your sense of where the '26 program could go with the operated partnerships. Would the 4 rigs be possible? Or what are you thinking at this point?

Absolutely. Yes, 4 rigs. We're running 3 now. I could see a scenario definitely where we're with a fourth rig. We just added 2 new partners. They're aggregating inventory now. That will take them a little bit of time. But at some point in 2026, I do expect that we'd be running at least 1 rig on one of those 2 new partners that we added. So from a phasing standpoint, from an outlook standpoint, I think that CapEx spend in 2026 will look pretty similar, if not more, compared to what we're doing this year, especially if the A&D environment remains strong.

And would the mix change if you go to at least 4 rigs, kind of 65% operated, 35% nonoperated, do you see that operated piece going higher next year?

Yes, it might tick up, but we're still seeing a ton of opportunity on the non-op front, particularly in Appalachia. Most of the non-op deals that we've done this year have been in the Utica windows. So we still expect to see a pretty good clip of non-op opportunities even as we move into '27 and '28. So yes, I think that the percent of capital going to operator partners might tick up, but we'll still have a pretty healthy component from non-op.

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

For my first question here, you guys are growing over 24% this year. I mean how can we think about the growth trajectory of the company moving forward? Is that a level that you like -- a level of growth that you'd like to see? Or would you maybe want to moderate that kind of back to the original plan of what was mid-teens growth?

Yes. So production growth isn't a target. We don't set a target and then try to achieve the target. Again, it's driven by where we are on leverage, where we are on scale, what free cash flow look like. So I think right now, given this environment and where the balance sheet is, I would expect quite a bit of growth into 2026. It's a bit early for us to talk about what that looks like. But I think it might not be as strong as this year, but would be mid-teens type growth given what we're buying now. A lot of that inventory is '26, '27. So right now, we're prioritizing growth. I would expect that to continue with where we are with our balance sheet.

That's helpful. And then for my second question here, you guys mentioned exploring the credit markets or looking to explore the credit markets in fall of '25. How can we -- could you just add some color around what you're thinking there is? Are you thinking about increasing your RBL size, potentially going to the high-yield market to term out some debt? Just thoughts there.

Yes. It's kind of all of the above, right? So the -- we increased the RBL by $50 million in the spring. Given this level of activity here in 2025, I'd expect us to be able to get a pretty healthy increase again in the fall. So that's certainly on the table and something that we're pursuing now. And then yes, I think we're also looking at options that would help us term out some of that RBL balance. So that could either be traditional high-yield market or some sort of private credit option as well. So those are all on the table, and those are things that we'll evaluate here as we head into the fall.

[Operator Instructions] Your next question comes from the line of Phillips Johnston with Capital One.

Sorry for the follow-up. Just wanted to ask if these partnerships are structured like earn-outs to where your working interest is reduced after certain payout targets are met? Or are they generally more of like a heads-up type of arrangement?

So there is a -- after a return hurdle is achieved, there is a reversion of some of our interest to the operator partnership teams. There is no upfront promote in any way. So there's nothing on the front end, but there is after the return thresholds are met, a back-end part of our interest.

And there are no further questions at this time. Thank you all for attending. This does conclude today's conference call. You may now disconnect.