Granite Ridge Resources, Inc (NYSE:GRNT) Q4 2025 Earnings Call Transcript

Granite Ridge Resources, Inc (NYSE:GRNT) Q4 2025 Earnings Call Transcript March 6, 2026

Operator: Good morning, and welcome, everyone, to Granite Ridge Resources, Inc. Fourth Quarter and Full Year 2025 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. If you would like to ask a question, please press star 1 on your telephone keypad. To withdraw your question, press star 1 again. I will now turn the call over to James Masters, Vice President, Investor Relations.

James Masters: Thank you, operator. Good morning, everyone. We appreciate your interest in Granite Ridge Resources, Inc. We will begin our call with comments from Tyler Parkinson, our President and Chief Executive Officer, who will review the quarter’s results and company strategy along with an overview of 2026 financial and operating guidance, and introduce our newly announced Chief Financial Officer, Kyle Kettler. He will then turn the call over to Kyle to review our financial results in greater detail. Tyler will then return to provide closing comments before we open the call for questions. Today’s conference call contains certain projections and other forward-looking statements within the meaning of federal securities laws.

These statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied. We ask that you review the cautionary statement in our earnings release. Granite Ridge Resources, Inc. disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. Accordingly, you should not place undue reliance on these statements. These and other risks are described in yesterday’s press release and our filings with the Securities and Exchange Commission. This call also includes references to certain non-GAAP financial measures. Information reconciling these measures to the most directly comparable GAAP measures is available in our earnings release on our website.

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

Tyler Parkinson: Thank you, James, and good morning, everyone. We are proud to report results for our third full year as a public company. While much has changed since the company went public in 2022, our commitment to pursuing the highest risk-adjusted rate of return projects and creating durable shareholder value remains the same. It is that commitment that drove our evolution from a traditional nonoperated company pursuing a diversified investment strategy to a capital allocator focused on the Permian Basin, backing proven management teams to acquire and develop high-quality assets, a strategy shift that is the driving force behind our results. For the fourth quarter and full year 2025, average daily production increased 27% year over year to 35,100 barrels of oil equivalent per day.

Total production for the year increased similarly to 32,000 barrels of oil equivalent per day. Adjusted EBITDAX for the quarter was approximately $70,000,000 and $315,000,000 for the full year. Capital expenditures for the fourth quarter were $127,500,000, split approximately half to development and half to inventory acquisitions. Our full year capital expenditures were $401,000,000. Finally, we maintained our quarterly dividend of $0.11 per share, which continues to demonstrate our commitment to return meaningful capital to shareholders. Since going public, we have significantly increased production while maintaining a conservative balance sheet. That capital-efficient growth is a result of consistently hitting our underwriting targets and increasing our capital allocation to operator projects thanks to a structural opportunity we identified in the market.

Over the past decade, private capital retreated from the natural resources sector in a major way, fundamentally changing the landscape for energy development. Private equity fundraising declined dramatically, and the remaining capital focused on fewer teams chasing larger opportunities. This left a scarcity of capital and competition in the unit-by-unit operated segment. At the same time, proven operating teams who had built and sold successful companies increasingly lacked access to aligned capital partners. Granite Ridge Resources, Inc. recognized the opportunity and stepped into the gap by developing our operative partnership model. We first partnered with Admiral Permian Resources, a Midland-based operator with multiple successful exits and deep ties in the community.

Central to our strategy was that the Delaware Basin, containing some of the highest quality shale resource in the world, is now controlled by a small number of large asset managers overseeing vast overlapping land positions. These land positions come with a variety of complications like lease expirations, fragmented working interest, and inventory management issues that can turn into high-return drilling opportunities for the right partner. Granite Ridge Resources, Inc., through Admiral, has become that partner. Over the past three years, we have executed over 50 transactions in the Permian Basin and have grown net production to nearly 10,000 BOE per day. Granite Ridge Resources, Inc. and Admiral have become preferred counterparties, and inventory additions continue to outpace our two-rig development program.

We have also signed up three additional operator partners, each pursuing a different strategy in the Permian. We have been deliberate about limiting public disclosure of these partners to preserve their competitive positioning. Each team has successfully built and exited private equity-backed companies in the Permian and have significant personal capital invested alongside us, creating meaningful alignment. We look forward to sharing their progress and demonstrating the scalability of the operator partnership strategy. These partnerships greatly expanded our proprietary deal flow, which was already a competitive strength. Last year, we reviewed nearly 700 opportunities with a capture rate of just 15%. In 2025, we invested $122,000,000 across 107 transactions, securing approximately 20,500 net acres and 331 gross, or 77.2 net, locations, almost exclusively split between two buckets: nonoperated in the Utica Shale and operated partnerships in the Permian.

Because we focus on short-cycle opportunities underwritten at strip pricing, our entry costs remain notably low relative to large-format transaction comps. In the Permian, our average acquisition cost per net location was just $1,400,000, far below recent public market transactions. This is a through-cycle strategy. We target 25% full-cycle returns at strip pricing, compound production and cash flow growth, and protect downside through disciplined leverage. Since our first operator partnership investment with At Home, we have fundamentally transformed our business from passive non-op to controlled capital with scale, growing production and high-quality near-term inventory, the results of which are becoming clear in our financials and outlook.

Granite Ridge Resources, Inc. came public with cash on the balance sheet and no debt, but subscale. In the years since, we deliberately used leverage to achieve sufficient scale to support our next evolution: sustainable free cash flow. We are getting close. We see 2026 as a year of transition. Production growth is moderating, and development capital expenditures are aligning more closely with expected cash flow. At current strip prices, we expect to achieve free cash flow from operations in 2027. The midpoints of guidance for production and capital for this year are as follows. We expect annual production to average 35,000 barrels of oil equivalent per day, representing a 9% increase over 2025, and we expect our exit in 2026 to be essentially flat or modestly up from exit in 2025.

We forecast oil volumes to be approximately 51% of total production. Development capital expenditures are projected at $315,000,000, with an additional $20,000,000 to $30,000,000 for acquisitions that we currently have in the pipeline. Approximately 90% of the capital invested in 2026 will be focused on operated projects. To summarize, we will spend roughly 15% less than last year to achieve production growth of approximately 9%. At current strip pricing, we anticipate a modest outspend in 2026. One of our expressed goals for the business is to generate alpha through the expansion of cash flow above maintenance capital. We currently estimate maintenance capital of approximately $250,000,000, which provides room for disciplined growth above that level.

We have built our business for capital-efficient growth and free cash flow visibility at $60 oil. In response to the geopolitical shocks of the past week, we have added oil hedges and will continue to closely monitor the market. Recent events aside, we have been encouraged by the market resilience shown to date and remain bullish on the medium-term outlook. Should prices fall below $60 per barrel for a sustained period, we retain flexibility with our partners to adjust the development schedule and moderate capital deployment. Finally, let me expand on two recent announcements. Alongside Diamondback Energy, we partnered with Conduit Power to support the development of 200 megawatts of natural gas-fired power generation scheduled to come online fully in 2027.

This transaction will effectively provide a synthetic hedge to our Permian gas realizations and is expected to enhance value by approximately $1 to $2 per Mcf on our gas exposed to this contract. We think similar opportunities may exist to further improve our gas realizations, and we will be diligent in pursuing them. Second, we recently announced the appointment of Kyle Kettler as our Chief Financial Officer after a six-month search. We went through a thoughtful, diligent process to find the right person that can help guide us through this next season of growth. Our business has matured, and the challenges and opportunities are much different than they were a few years ago. We were looking for an oil and gas professional with tremendous experience in capital markets, but also someone with creativity, a track record of creating value, somebody that could be a thought partner as we grow the business.

We could not be happier that Kyle decided to join us. He brings significant capital markets expertise, an extensive network, and a keen strategic perspective that will be critical as we transition towards sustainable free cash flow, the next phase of Granite Ridge Resources, Inc.’s development. I am thrilled to welcome him to the team in his first earnings conference call. Kyle?

Kyle Kettler: Thank you, Tyler, and good morning, everyone. It is my pleasure to join my first Granite Ridge Resources, Inc. earnings call, and I look forward to spending time with our analysts and investors in the months ahead. Granite Ridge Resources, Inc. is building something truly different, allocating capital and creating value from a platform that is unique in public and private E&P. I am excited to be here. Tyler covered the strategic highlights and 2026 outlook, so I will focus on the fourth quarter and full year financial results and our capital position. For the fourth quarter, oil and natural gas sales totaled $105,500,000. Revenue was essentially flat compared to the prior-year quarter because of commodity pricing; however, production grew an impressive 27% year over year.

In the fourth quarter, our average realized oil price was $55.49 per barrel, compared to $65.53 per barrel in the same period last year. Natural gas averaged $1.81 per Mcf in the quarter, or 48% of Henry Hub. These weak realizations, particularly in the Permian Basin, had a meaningful impact on revenue and, by extension, EBITDAX and operating cash flow. As a result, adjusted EBITDAX for the quarter was $69,500,000, and operating cash flow totaled $64,500,000. For the full year, oil and natural gas sales totaled $450,300,000, with production increasing 28% year over year to 31,984 barrels equivalent per day. Full year adjusted EBITDAX was $315,000,000, and operating cash flow was $296,400,000. The takeaway is straightforward. Our asset base is scaling, oil remains roughly half of the mix, and volume growth is industry leading.

Pricing, especially in the Permian Basin, was a swing factor in fourth quarter revenue and cash flow. That dynamic reinforces the importance of initiatives like the Conduit Power transaction Tyler mentioned, which we expect will help improve Permian gas realizations over time. On the cost side, lease operating expense in the fourth quarter was $7.72 per barrel equivalent. That is higher than last year, driven primarily by our increasing focus on the Permian Basin. Service costs, primarily saltwater disposal, increased, a dynamic that is structural in the basin. For the full year, LOE averaged $7.27 per barrel equivalent. Our 2026 guidance for LOE is $6.75 to $7.75 per barrel equivalent. Production and ad valorem taxes ran just under 6% of revenue in the quarter, and G&A was $8,000,000, including $1,400,000 of noncash stock compensation.

On a full-year basis, cash G&A was what we expected. Annual guidance for these metrics is the same as last year: production taxes of 6% to 7% of revenue and cash G&A of $25,000,000 to $27,000,000. Turning to capital. This is where the strategic shift Tyler described really starts to show up in the numbers. We invested $127,500,000 in the fourth quarter, roughly half into development and half into acquisitions. For the full year, total capital was $401,000,000, including $279,000,000 of drilling and completion capital and $122,000,000 of property acquisitions. That acquisition capital was not large-format M&A. It was nimble, repetitive, unit-by-unit inventory capture, high-graded, and underwritten at strip. Our acquisition strategy gives us control over timing and capital intensity.

We are not locking in multiyear development programs irrespective of commodity price. Operationally, we placed 67 gross wells online during the quarter and 322 gross wells for the year. That activity underpins the 28% annual production growth we delivered in 2025. Now onto the balance sheet. We exited the year with $350,000,000 outstanding on the 2029 senior notes and $50,000,000 drawn on the revolver. Liquidity totaled $339,500,000 at year end. Net debt to adjusted EBITDAX was 1.2 times, inside of our long-term range. Looking ahead to 2026, we are deliberately shifting gears. The plan is to grow production while reducing capital spending. 2026 production is expected to average 34,000 to 36,000 barrels equivalent per day, with oil just under half the mix.

Development capital is projected at $300,000,000 to $330,000,000, and total capital is $320,000,000 to $360,000,000, including acquisitions. The key point is this: growth is moderating, capital intensity is coming down, and development spending is aligning much more closely with expected cash flow. That transition from scale-building to cash flow durability is the financial inflection point for the company. And through the transition, we are maintaining our $0.11 per share quarterly dividend. So, stepping back, the last three years have been about scaling the platform and capturing inventory, while 2026 is about capital efficiency and balance sheet discipline, positioning Granite Ridge Resources, Inc. to generate sustainable free cash flow.

With that, I will turn it back to you, Tyler.

Tyler Parkinson: Thanks, Kyle. Let me close with a few high-level points. First, 2025 was a transformational year for Granite Ridge Resources, Inc. We scaled the operator partnership model, expanded our controlled inventory in the Permian, and grew production 28% year over year. We leaned into an opportunity set that is structurally advantaged and difficult to replicate. Second, we are now shifting from outsized growth to durability. Our 2026 plan reflects a moderation in growth, tighter alignment of development capital with cash flow, and a clear path towards sustainable free cash flow generation in 2027. Third, our competitive advantage is our structure and business development engine. By underwriting unit by unit at strip pricing, partnering with proven operators, and maintaining capital flexibility, we consistently hit our investing underwriting targets, which has resulted in significant growth in production and asset value.

Finally, we remain committed to balanced shareholder returns. The dividend remains a core component of our framework. As we cross into free cash flow, we will have increasing optionality around capital allocation. We appreciate the continued support of our shareholders, partners, and employees and look forward to the year ahead. Operator, we are ready to take questions.

Q&A Session

Operator: We will now begin the question-and-answer session. Please limit yourself to one question and one follow-up. If you would like to ask a question, please press 1 on your telephone keypad. To withdraw your question, please press 1 again. Please pick up your handset when asking a question. If you are muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster. Your first question comes from the line of Phillips Johnston with Capital One. Your line is open. Please proceed with your question.

Phillips Johnston: Hey, thanks for the time. First, a question for Kyle. Your fourth quarter realized oil and gas prices as a percentage of NYMEX were a little bit lower than usual in the fourth quarter, especially on the gas side. I think in your comments, you alluded to weak Waha prices as the driver on the gas side, so that makes sense and is not surprising. But is there anything to call out on the oil side? And as a follow-up, what should we be thinking about for our models in 2026 in terms of both oil and gas differentials?

Kyle Kettler: Yes, thanks. Yes, the fourth quarter was weak on natural gas realization, and that was driven by Waha pricing. We have a substantial portion of natural gas coming from the Permian Basin, and that Waha basis widened out during the quarter on us. Going forward, we have modeled that. You can see the strip. We are utilizing that as a way to predict what Waha prices will be over the next year, and those prices are pretty low early in the year, and they tighten up a little bit towards the back end of the year, and then 2027 going forward. The strip is much better but still negative around a dollar or so. On the oil side of the equation, there is not anything particularly that sticks out. There is a bit of a negative difference between realized and benchmark prices, but we have that in our model going forward as well.

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

Kyle Kettler: You bet. So last year was 38 net wells turned online. Towards the end of the year, it got a little gassier with some Haynesville wells coming on. We see 2026 being about 29 net wells coming online, and the relative mix of gas and oil should tilt back towards oil as the year goes on with more Permian Basin activity.

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

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

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

Derek Whitfield: Good morning, and congrats on the acquisition success you had in 2025. I wanted to start on slide 14. As you think about the business’ transition to sustainable free cash flow in 2027, are you outlining that this morning as a business objective for 2027 based on your desire to lower leverage, or is it based on your current view of the opportunities ahead of you? I am not trying to pin you down as we live in a dynamic environment, just trying to understand the driver and how firm the message is.

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

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

Tyler Parkinson: I would love to fill in some blanks there. We have spoken publicly about our first two. Admiral had the benefit of getting a head start on our other three partners, so they are the most secure and steady state of the four partners. I think the Admiral story is pretty clear to everyone in the public domain. They are focused on Delaware Basin, unit-by-unit inventory capture from some of the larger asset managers in the basin. That story has been successful. We are running a couple of rigs there. We are adding inventory faster than the development base there, so we hope to be able to replicate this same evolution with the other three partners. Partner two is actually PetroLegacy. We have mentioned that before, former EnCap-backed.

That team is focused on the northern Midland Basin Dean play. They have captured a position there in the Dean play. We will probably get started on some selective development of that position this year. That market has gotten extremely competitive, as everyone knows, so I am not sure how much additional running room we will have there. The PetroLegacy team is looking at some other opportunities in the basin and also potentially outside of the basin. We hope to have some drilling results from them this year. Our third team, we have not disclosed who that is, but I can tell you what they are doing. They are another successful team that has exited private equity. They are focused on some of the emerging plays in the Permian Basin—think Woodford, Barnett.

Those transactions will probably look a little more blocky from an acreage perspective—larger chunks of acreage. They will come with some appraisal to figure out what exactly we have, but if that is successful, that will add a lot of medium-term inventory for us and start to fill in some of the development drilling in 2028 and beyond. Team four is our newest team. They are also a Midland-based team, an exit from private equity. They look a lot like the Admiral team, mainly focused on Midland Basin opportunities. I think they will be sourcing opportunity from the larger asset managers out there on a unit-by-unit basis. We are about six months into that one, so that is very new, but they have already started to capture inventory. Typically, it takes us maybe 12 to 18 months to get enough inventory to have about 18 months to two years of inventory in front of the team in order for us to justify picking up a rig.

I probably would not expect a whole lot of development activity from that team this year, but as we move into 2027, I think we will see them start to fill in some development.

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

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

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

Kyle Kettler: I would just add, the growth rates were pretty significant over the last couple of years, and it will still be high single digits going into next year. So it will still be pretty good growth. A lot of the capital spending is through operated partnerships, and that is based on a development plan we have coordinated with them. That puts us in this modeling position where we think we can see into 2026 and 2027 and turn into free cash flow in the 2027 time period.

Jerry Giroux: That is perfect. Thanks for the color. And then one more question about slide nine. Could you give a little more color on that slide? You talked about Granite Ridge Resources, Inc. retains 92% of the ten-year projected cash flows, then also that the Hamburglar wells or pads achieved the hurdle reversion. Could you give a few more details on this case study?

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

Jerry Giroux: That is perfect. Thank you.

Operator: Your next question comes from the line of Noah Hungness with Bank of America. Your line is open. Please proceed with your question.

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

Tyler Parkinson: Good question. That opportunity still exists for us. Our operator teams are still executing on transactions that look exactly like that. We have roughly $25,000,000 of acquisition capital expenditures scheduled right now. That is basically what we have captured or have line of sight to now. If we wanted to continue to add inventory and increase that budget, that opportunity is still available to us. As I said in the remarks, that has been a very good opportunity for us over the past couple of years, and we see the operated partnership inventory captures having a number of years out in front of us. As far as the rest of deal flow, we have seen still very strong deal flow. I think we had a record last year on deal flow that we screened, and that is continuing.

The distributed wellbore market is still very strong. We do not participate in that market very much. Returns there are not something that we would underwrite to, but that is a very strong market. The larger marketed packages are still out there with lots of divestiture targets from a lot of the consolidation. Again, we do not participate in that market either. Lastly, on some of the smaller marketed processes for non-op, we are seeing probably the least amount of deal flow and trending down. That has been a little bit weak, but that is not an area that we typically source opportunity from. Finally, in the Appalachia Utica Shale Basin, we are still seeing a ton of opportunity there. That is a traditional non-op play for us. We have been very successful over the past year and a half leasing there.

We added probably another couple thousand net acres in the Utica play in Q4, and we are continuing to see lots of opportunity there.

Noah Hungness: That is helpful color. And then for my second question, Tyler, could you talk about how we can think about the oil cadence through 2026? And then what does exit-to-exit production growth look like for oil?

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

Operator: There are no further questions at this time. That concludes the conference call for today. We thank you for your participation and ask that you please disconnect your line. Have a great day.