Granite Ridge Resources, Inc (GRNT) Q2 2026 Earnings Report, Transcript and Summary

Good day, and welcome to the Granite Ridge Resources second quarter 2026 earnings conference call. [Operator Instructions] Please note, this call is being recorded. I would now like to turn the call over to James Masters, Vice President, Investor Relations. Please go ahead.

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. We'll then turn the call over to Kyle Kettler, our Chief Financial Officer, to review our financial results in greater detail. Kyle 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. 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. Let me start with the most important takeaway. 2026 is the last year we plan to invest ahead of our free cash flow, and every dollar we are putting to work is building towards the free cash flow inflection we have laid out for 2027. This quarter advanced that plan on the fronts that matter most. We brought new wells online. We added high-return inventory to feed our growth. We kept our balance sheet strong while maintaining our dividend. The quarter's numbers reflect that progress. Production was 32,044 barrels of oil equivalent per day, 51% oil, and we generated $79.6 million of Adjusted EBITDAX with strong early results from the 7.2 net wells we turned in line late in the quarter. But the real story is not the quarter, it's the trajectory. We are getting closer to that inflection, and we are executing the plan to get there. Our Operated Partnership platform continues to be the standout. The advantage starts with how the deals are sourced. Through Admiral Permian Resources and our other operating partners, we fund development on acreage that is captured through our partners' own leasing, ground game, and operator relationships, rather than competing for it in broadly marketed packages where prices get bid up. Because we bring the capital and our partners bring the operational footprint and the local deal flow, we see opportunities that never reach an auction, and we underwrite each one directly to our return threshold before we ever commit a dollar. That is what lets us add inventory at entry costs well below what marketed deals command. And unlike a traditional non-operator, we control the pace and the capital. We're not simply along for the ride on someone else's drilling schedule. We capture operator level economics and inventory without carrying a full standalone operating cost structure. That combination, proprietary sourcing plus real control, is what separates us from a passive non-op and is difficult for others to replicate. During the quarter, we closed 27 transactions, primarily across the Permian and Utica, for $28 million, including future carry obligations. We added 21.9 net undeveloped locations to our inventory. We ended the period with 175 gross or 14 net wells in process. Let me put one of those deals in context because it really shows what our flagship operating partner Admiral actually does. Large public producers in the Permian regularly end up with development work that must get done well and on a firm timeline, but that does not fit neatly into their own rig schedule or capital plans. Rather than pull their rigs and crews off other priorities, they hand the work to a partner who can execute it for them. Admiral is that partner, and we provide the capital behind it. In the first half of the year, Admiral took on a project for a large Permian operator that called for 9 long lateral wells, each stretching 10,000 to 15,000 feet or roughly 2 to 3 miles, all of which had to be drilled, completed, and producing by the end of 2026. That's a very aggressive schedule. Using 2 rigs Admiral already had running, they folded the project into their existing program, built the facility and infrastructure plan to hit the deadline. We believe that ability, taking on a large, complex development and delivering it quickly and reliably, is what makes operators want to work with Admiral, and it is a differentiated strength of the partnership. This is exactly the repeatable high-graded deal flow the platform was built to generate. Our sourcing funnel did exactly what it was built to do in the first half of 2026. We reviewed 363 opportunities, advanced 84 to underwriting, and closed 44, a conversion of about 12% that shows we are holding our screening discipline in the face of abundant deal flow. Our operator partnerships did the heavy lifting, driving about 78% of our first half deal capital, led by Admiral in the Delaware, alongside a steady non-operated ground game that layered in smaller, high-return interest in the Utica. This is the low-cost inventory replacement we have built this company around. We are adding high-quality locations faster than we drill them at entry costs that support returns above our 25% threshold at the strip. 2 items worth addressing directly, and both are ones we understand and are actively managing. First, lease operating expense. For the second quarter in a row, LOE ran above plan, driven primarily by water handling in the Permian and by higher early life costs on our newer pads. We are resetting our full year LOE guidance higher. Kyle will take you through the new range and the path we see toward lower per unit costs as second half volumes come online and our newer areas mature. Second, natural gas. Permian realization stayed soft this quarter on continued Waha Basis weakness we expected. The more important point is what is happening underneath. New takeaway is finally catching up to Permian gas supply. The Hugh Brinson pipeline began moving gas mid-year and continues to ramp towards full service, with additional large-scale capacity falling behind it. And Waha prices have already firmed off their lows as these projects have come online. Supply also keeps growing, so we're not calling the problem solved, but Permian takeaway is clearly improving, and as that basis firms, we expect our natural gas revenue to strengthen throughout the back half of the year. We have hedged our basis through the first quarter of 2028, protecting our downside risk. Neither item changes our trajectory, and both are moving in the right direction. Let me also give you our read on the macro because it frames how we are built to compete. Public markets are largely pricing oil to revert to a lower long-term level, and energy equities broadly reflect that skepticism. We do not need to win that debate to win. We underwrite every acquisition and every operator partnership well at the strip to a full cycle return above 25%. So if prices simply hold near current levels longer than the market expects, that is upside embedded in our portfolio that we did not pay for. And if prices fall, our hedge book protects our cash flow, our balance sheet, and our dividend. Beyond our hedges, the program itself is built to flex in both directions. And given the macro uncertainty, we believe this flexibility is critically important. If oil were to weaken and hold below roughly $65, we could pull back an estimated 40% to 50% of our development budget while protecting our base business and our dividend. And if conditions warranted leaning in, we have the ability to accelerate. Every incremental well still has to clear our full cycle return hurdle at the strip before we fund it. That discipline is what lets us stay on offense through a volatile tape instead of reacting to it. Stepping back, our strategy is working. Our traditional non-operated business continues to generate steady cash flow from an asset base that affords diversification and optionality, while our operator partnerships are compounding our inventory and our growth. We are in a position of strength, and every dollar we are deploying is building that base that carries us towards our 2027 framework of durable growth, double-digit free cash flow yield, and a sustainable dividend. Let me be specific about why 2027 is the term. The capital we are investing this year builds a production base that steps up meaningfully next year. As those volumes come online, recovering gas realizations and lower per unit costs widen our cash margins. Our free cash flow grows faster than our capital program. That combination, more production at wider margins against a roughly steady level of investment is what converts this year's outspend into sustainable free cash flow in 2027. That is the inflection. Everything we did this quarter advanced it. As our free cash flow builds, we expect to keep our balance sheet strong with leverage trending lower as our cash flow grows while continuing to deploy capital into high-return acquisitions. And with that, I'll turn it over to Kyle.

Thank you, Tyler, and good morning, everyone. We had a solid quarter financially, with strong cash generation and a balance sheet that gives us real flexibility. Oil and natural gas sales were $149.3 million. On a GAAP basis, net income was $30 million, or $0.23 per diluted share, up from $0.19 a year ago. Adjusted net income was $11.1 million, or $0.09 per diluted share. Adjusted EBITDAX was $79.6 million, up from $75.4 million a year ago, and we generated $55.6 million of cash flow from operations, or $69.5 million before working capital changes. Our unhedged realized price was $51.19 per BOE and $43.39 per BOE, including hedged settled derivatives. LOE was $30 million, or $10.27 per BOE. This compares with $9.57 per BOE during the first quarter. Combined for the first half of 2026, LOE was $9.91 per BOE. We're focused on our operating cost structure and working closely with our operating partners on the details. We're seeing operating costs decline on wells that were turned to production during the end of the quarter, and as a result, we expect per unit costs to trend lower over the second half. However, based on what we've seen so far, we're increasing our LOE guidance for the year to $8.25 to $9.25 per BOE. Looking further out, we expect lower per unit costs as we scale into 2027, which is a contributing factor to the free cash flow inflection Tyler mentioned. Production and ad valorem taxes were $9.3 million, or 6% of sales, in line with guidance, and G&A was $9.2 million, or $3.14 per BOE, including $1.3 million of non-cash stock-based compensation. We invested $78.5 million in drilling and completions capital and $16.7 million of acquisition capital during the quarter. That $16.7 million reflects the cash we deployed to close 27 transactions, primarily in the Permian and Utica. Including roughly $11 million of associated carry we expect to fund as these wells are developed, our total committed capital is about $28 million, which added 21.9 net undeveloped locations to our inventory. All of it sourced through our operating partners and our ongoing ground game, and underwritten to our full cycle return threshold at the strip. Simply put, we're replacing and extending high-quality inventory as we develop it, which is how we sustain growth without paying up and warehousing long-dated drilling inventory. We ended the quarter with $44.1 million of cash, $125 million drawn on our revolving credit facility, and $350 million of principal debt outstanding on our 8.875% senior unsecured notes. For net debt of $418 million, leverage remains conservative at approximately 1.4x. Before I hand it back, let me offer some color on the second half. On volumes, we expect production to step up modestly in the third quarter and more meaningfully in the fourth, as the wells from our first half of the program come online, with oil rounding out at about 52% of the mix. For the year, we expect volumes within the guidance range, but trending towards the lower end due to shifts in timing, providing a large positive impact to the first quarter of 2027 than initially expected. On costs, we expect per unit LOE to improve sequentially as new volumes dilute our fixed base. Finally, the third quarter will be the heaviest spending quarter of the year, reflecting the pace of our operating development and continued inventory additions before moderating in the fourth quarter. As it relates to pricing, Waha Basis was the weakest we've seen it on record. And that is what you see in our $1.12 per Mcf realization. We believe the second quarter is a low point. And all things being equal, we expect gas will be a big swing factor in the second half. Gas sales were $9.6 million in the second quarter. If Basis holds where it is today, we expect to be north of $30 million in the third quarter before hedged settlements. The fourth quarter is even better. Our Basis hedges improved materially, and we have less volume hedged than in the third quarter. Altogether, ramping production and healthy price realizations set the stage for a compelling 2027. With that, I'll turn it back to you, Tyler.

Thanks, Kyle. Let me close with 3 points. First, our Operated Partnership platform is delivering. It is giving us proprietary access to high-return inventory and executing it well and is the engine of our growth. Second, we are well positioned to execute the remainder of our 2026 plan. Our leverage remains within our target range. Our liquidity is ample. We have paid a dividend every quarter since becoming a public company. Everything we are doing this year is building towards our 2027 framework of attractive growth, a double-digit free cash flow yield, and sustainable dividend coverage. We expect strong exit production approaching 40,000 BOE per day, continued improvement in our per unit costs, and steady progress toward the point where this platform funds itself. We are confident in where we are headed and we are looking forward to delivering. Third, Grey Rock has advised us that it intends to distribute a portion of its Granite Ridge shares to its limited partners in the third quarter. If that distribution is completed, Grey Rock's ownership will fall below 50% and Granite Ridge will no longer be a controlled company. We view that as a positive development. It broadens our shareholder base, increases our public float and trading liquidity, and completes our transition to a fully independent governance structure. We will provide additional details on size and timing as those are finalized. With that, operator, we'll open the line for questions.

[Operator Instructions] Our first question comes from John Annis with Texas Capital.

For my first one, you've reaffirmed that 2026 should be the final outspend year before a free cash flow inflection in 2027. I wanted to ask, what are the most important assumptions underlying that outlook and what commodity prices do you need to generate that double-digit free cash flow yield outlined in the presentation?

Yes. Morning, John. Thanks for the question. So, '27, the way we're thinking about '27 from a commodity perspective is $65 oil. So, we're north of that now. 2027 is in the low $70s right now. So we've got some cushion there. So $65 oil to be able to deliver what we've laid out, which is a 10% free cash flow yield, 1.25 coverage on our dividend, leverage in the 1.25x range, and production growth in the high single digits.

I'll add in, the high single-digit production growth couples with -- we have substantial hedge losses in 2026. We expect those to go away in 2027. So that should be a pickup there. And then as you probably saw in the results, the Waha Basis differential has been pretty rough in the first half of the year. That's subsiding and it looks like that's going to stay about the same through 2027, expanding gas revenues.

I appreciate the color. Maybe for my follow-up. Digging more into your prepared remarks, one of the advantages you've highlighted with the operated partnership strategy is greater control of capital allocation and development timing. If commodity prices were to move materially higher or lower, how quickly and maybe to what extent could you flex activity levels up or down within the operated portfolio?

Yes, I think very quickly. So we have additional inventory on the upside. There's additional inventory that we have scheduled out for out years that we can pull forward, add a rig, pull forward some inventory. I think that's an exercise that could happen very quickly. It's obviously harder to slow down activity, but what we've looked at so far, at least for 2027, we have plenty of capacity to be able to pull down our inventory and our spend rate below our maintenance capital level of $250 million. So I think there's flexibility on both sides, and it's something we keep an eye on, especially with all the volatility right now on the commodity price.

Our next question comes from Jeff Grampp with Northland Capital Markets.

With the transition to free cash flow expected next year, how do you anticipate that affecting the inventory capture strategy that you guys have been so successful at? Does that kind of artificially put a ceiling on the amount of capital you guys would be willing to put to work in that market? Or should we view that as kind of a secondary discretionary bucket of capital allocation outside of the free cash flow that's maybe more tied to development-oriented CapEx?

Yes, no, I mean, it's certainly -- there's somewhat of a ceiling that gets put on it. But right now, we've been very successful on that front. We've added inventory at about a 2:1 rate versus what we're developing. So it's been very successful. I'd continue to expect that we'd be spending on extending our inventory. We probably have 5 to 6 years of inventory right now. That's a pretty good level for us. I don't really want to get too long inventory and have to warehouse that on the balance sheet. But if we did add another couple of years of inventory, I think that would be great for the business. So I do -- we had a big spend on acquisition activity in 2025. We spent over $125 million in '25. This year we'll probably spend about $50 million. Next year I'd probably expect to spend on a similar level.

Got it. That's really helpful. I appreciate that. And I guess sticking on the acreage capture opportunity, it seems like you guys continue to be really active in the Utica kind of backstopping the operated partnership model. Can you talk about the runway there in terms of, I guess, continued opportunities at prices that make sense for you guys? Is that an area we should continue to expect to be a focus?

Yes, absolutely. So that's our #1 spot for our traditional non-op spending. So 90% of our business capital spending-wise has been going into operative partnerships over the past few quarters. The rest of that has almost been exclusively going to Utica. That's been tremendous for us over the past 18 months. I think we're close to 6,000 net acres now in that basin across that 18-month build. And it's a spot where we're continuing to see lots of deal flow. We closed -- we kind of look at them in groups of closings. We had 4 separate closings in the second quarter that included multiple transactions in each one of those closings. We're still seeing tons of deal flow in Utica. We added a couple net wells, a few hundred net acres. Those economics look great. The well performance has been great. We now have, I think, over 80 wells online in our portfolio up there with at least a year and a half of data. And everything is looking good from the productivity standpoint. So yes, it's an area where we'd like to continue to spend dollars in the non-op business and where we expect to have continuing success.

Our next question comes from Phillips Johnston with Capital One.

Appreciate the details on slide 9 about your lower entry prices in the Permian. It's pretty compelling. Just 1 question for me as a follow-up on the uptick in LOE that Kyle went through. The updated guidance implies the run rate should tick down to around $7.50 to $8.50 per BOE in the back half of the year from around $10 or so in the first half. You've obviously cited a few factors for the uptake, and you've referenced that production is expected to ramp in the second half, which should obviously help on the fixed cost component. But what gives you the confidence that those unit costs should moderate for the remainder of the year? And then can you also maybe talk about which regions specifically drove the elevated costs in the first half of the year?

Sure, of course. We're seeing a few things. I think, first of all, just to be open with you, we are seeing elevated costs. So we've increased guidance over the course of the year by $1.50 per BOE, which is about 20%, a little over 20%. So we are seeing some increased costs on the lease operating expense front. But we're seeing a couple of other things which give us confidence that, that run rate we saw in the first half will come off. We've been working pretty close with our operating partners to understand the intricacies of the cost structure there. And we're already seeing lease operating costs on a barrel equivalent coming down. On top of that, there's a denominator issue in the first half of the year. Waha went significantly negative. We saw some shut-ins for high GOR areas and some gas-oriented areas. And so that's created a bit of a denominator effect, which we've seen and we're pulling that out and thinking about what it looks like for the second half of the year. So those 2 items give us comfort that we'll see it coming off sequentially.

Okay, great. That makes sense. And I think last quarter you guys referenced some non-recurring recognition of MVC delinquencies. How big of a factor was that?

That is in our first quarter numbers, yes. There was a write-off of an MVC that impacted LOE. It flowed through LOE.

Okay, so that was the first quarter of that and it didn't affect Q2?

That's correct.

Our next question comes from Michael Scialla with Stephens.

There is a lot of really good detail on Admiral in the slide deck. I wanted to see if you could talk to whatever extent you could on the third and fourth partnerships, where those are, and when we might learn a little bit more about them.

Yes, I think probably later this year we'll be in a position to share a lot more information on those partners. We've generally talked about what they're doing, so I can kind of walk you through the strategy at least for each one of them. So they're both Permian based or Permian focused. One of the teams is an emerging play, geo-led team, looking at things in the Permian Basin, emerging [indiscernible] in the basin. So they've put together a pretty nice acreage block. They're doing some appraisal work on that acreage block now. So we hope to have some results for you later this year on that team. Team 4, we added in Q4 of 2025. So they're brand new, roughly 6 to 9 months in. They are an inventory aggregation development play team very similar to what Admiral is. They're focused mainly on the Midland Basin, but they are looking across the Permian, but should be mainly Midland-based activity. I'd say they're actually ahead of where we expected from an inventory capture standpoint. Some of the deals that we closed this quarter were actually with that Team 4. We typically like to see a year to 18 months' worth of inventory ahead of the team, before we want to really talk about them in the public domain. And also, that's kind of the minimum threshold that we'd need to see in order to think about picking up a rig with a team so that they can keep it continuously running for a year. So I think that typically, depending on the teams, can take up to a year. But our Team 4 seems to be ahead of that schedule. So hopefully we'll have some information on them later this year and what we have potentially planned for them from a development standpoint in 2027.

I appreciate that detail. I want to ask on, Tyler, if the free cash flow inflection plays out next year as you expect, how you're thinking you would prioritize that free cash flow for next year?

Yes. So continue to pay our dividend. So we paid our dividend every quarter since we've been public, so 14 quarters now. Then balance sheet, we're going to maintain the balance sheet at roughly 1.25. That's our long-term target range. And then beyond that, we'd look to either expand the business through additional inventory acquisitions. That's opportunistic. That's market-based. So depending on what the market looks like at the time, some could go to asset expansion, and then, depending on the commodity price, development activity to either accelerate the business or continue at the current pace.

Our next question comes from Chris Baker with Evercore ISI.

Tyler, just another follow-up question on '27. I guess just as you guys think about that CapEx envelope, I'm curious, as you all have progressed these operated partnerships, how much of that spend is for third-party versus the controlled piece?

So how much is inside of Operator Partnerships do we expect next year?

Yes, what's the rough split? I'm just curious in terms of what you can control.

It'll probably be north of 75%. So right now it's been, I think this most recent quarter, we were something like 93% of our development capital went into operator partners. The balance of it was traditional non-op and Utica. I expect it to maybe not be that high, but certainly higher than 75% would be going into Operated Partnerships next year.

Okay, so the vast majority. Okay, that's great. As a follow-up, I would love to get any thoughts you're able to share on the Grey Rock distribution in kind. Anything you can share in terms of cost basis, ability to support the stock? I mean, it looks like, just on some simple math, that the amount of shares being distributed would be upwards of 40% of value traded between now and the end of April. So just any color there would be helpful. Thanks.

Yes, you bet. I can share what I can. This is obviously a Grey Rock decision, Grey Rock partnership decision. So we don't control that here at the company, but from what we understand, their fund life is up in the next 6 to 9 months. So this will be a methodical distribution of shares over that 6 to 9 months. We're excited about it from a Granite perspective. It increases daily trading volume. Liquidity removes the overhang. So we're excited to get these shares into the public's hands. Grey Rock has distributed shares before. They made a large distribution in 2023 to these same LPs that will be getting shares over the next 6 to 9 months. So the LPs are used to getting these shares, have received these shares in the past. I think something like 40% of the fund, this remaining fund, has already been distributed. So yes, we're excited to get started and get these shares moving into the market. And we think this will be done in a methodical manner, multi-distributions over the next 6 to 9 months.

Okay, and just any sense on cost basis, is it above where the stock's trading today?

No, I don't know exactly. I know these have been very successful funds, so their cost basis, I know, is low. I don't know exactly where it is, if it's above or below where we're trading now, but it is a low number.

Thank you. I'm showing no further questions at this time. This concludes the question-and-answer session, and you may now disconnect. Thank you for your participation. Good day.