Executive Network Partnering Corp

NYSE:GRNT

Earnings Call Analysis

Granite Ridge Reports Strong Growth and Optimistic Outlook for 2025

In the third quarter, Granite Ridge achieved a 9% increase in average daily production to 25,200 Boe per day. Oil production surged 16%, reaching 12,700 Boe per day, resulting in 50% total oil volume. The company expects modest oil production growth in Q4 and maintains its 2024 production guidance of 23.3 to 25.3 Boe per day. It anticipates mid-teen growth for 2025, driven by controlled capital investments, aiming for a 6.9% dividend yield as they reinforce their commitment to shareholder returns. Adjusted EBITDAX increased 10% to $75.4 million, underscoring strong operational performance amidst fluctuating prices.

Strong Production Results

Granite Ridge Resources reported a 9% increase in average daily production for the third quarter, reaching 25,200 Barrels of Oil Equivalent (Boe) per day. This growth marks a 5% increase year-over-year. Oil production specifically saw a notable rise of 16% sequentially, bringing oil volumes to 12,700 Boe per day and raising the oil mix to 50%. Looking ahead, while the annual production guidance remains steady at 23.3 to 25.3 Boe per day, the company anticipates a stronger oil production mix as it approaches the end of 2024.

Financial Performance Highlights

The company reported a net income of $9.1 million, or $0.07 per share, for the quarter. After adjusting for non-cash charges, the adjusted net income increased to $18.5 million, equating to $0.14 per share. This reflects a 10% rise in adjusted EBITDAX from the prior quarter, totaling $75.4 million, despite facing a 6% decline in pricing per Boe. Year-over-year adjusted EBITDAX decreased by about 9%, mainly influenced by asset divestitures and lower pricing.

Operational Efficiency and Cost Management

Granite Ridge improved its per-unit lease operating costs to $5.62 per Boe, decreasing by 14% from the previous quarter. Further optimization is reflected in the general and administrative expenses, which dropped by 25% per unit, coming in at $2.16 per Boe. Guided annual operating expenses remain unchanged between $23 million and $26 million, underscoring the scalability of their business model.

Development and Capital Expenditures

During the third quarter, the company completed and placed 93 gross wells into production, including 5.2 net wells. Looking to 2024, Granite Ridge expects to continue this pace, predicting 22 to 24 net wells placed online, predominantly within the Permian Basin. Capital expenditures for the development in Q3 reached $77.6 million, closely aligning with expectations, and the total development capital guidance remains at $300 million for the year.

Growth Projections and Strategic Direction

Looking forward, Granite Ridge anticipates mid-teen production growth year-over-year for 2025, with a particular emphasis on oil. The Controlled Capital program, which enhances investment efficiency and production timing, has exceeded initial targets by about 15%. The plan is to allocate nearly 50% of the 2024 CapEx to this program, escalating to around 60% in 2025. This anticipates significant cash flow and production boosts from investments made in 2024 that are expected to materialize in early 2025.

Commitment to Shareholder Returns

Granite Ridge has reaffirmed its commitment to returning value to shareholders, declaring a quarterly cash dividend of $0.11 per share for Q3. This translates to a strong annualized yield of 6.9% based on closing price, illustrating the company’s strategy to deliver consistent returns alongside growth initiatives.

Challenges and Market Adaptations

The company acknowledges some challenges due to anticipated gas production declines of up to 10% in Q4, driven by expected tapering from flush production. However, this decline is expected to be mitigated by a modest increase in oil production. Moreover, Granite Ridge is actively seeking to expand its partnership footprint beyond its current focus areas, exploring opportunities in the Bakken and Eagle Ford regions.

Earnings Call Transcript 2024-Q3

[Operator]

Good morning, and welcome everyone to Granite Ridge Resources Third Quarter 2024 Earnings Conference Call. [Operator Instructions]

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

[James Masters]

Thank you, operator, and good morning, everyone. We appreciate your interest in Granite Ridge Resources. We will begin our call with comments from Luke Brandenberg, our President and Chief Executive Officer, who will provide an overview of key matters for the third quarter and an outlook for the remainder of 2024. We will then turn the call over to Tyler Farquharson, our Chief Financial Officer, who will review our financial results. Luke will then return to provide some closing comments before we open up 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 in these statements. We would ask that you also 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 forward-looking statements. These and other risks are described in yesterday's press release and our filings with the Securities and Exchange Commission.

This conference call also includes references to certain non-GAAP financial measures. Information reconciling non-GAAP financial measures discussed to the most directly comparable GAAP financial measures is available in our earnings release that is posted on our website. Finally, as a reminder, this conference call is being recorded. A replay and transcript will be made available on our website following today's call.

With that, I will now turn the call over to Luke.

[Luke Brandenberg, executive]

Thank you, James, and good morning, everyone. I appreciate you joining us today. I'm pleased to report that our third quarter results have exceeded our internal expectations across the board. This success is a testament to our team's creative deal sourcing and exceptional underwriting and to the operational excellence of our partners. I'm grateful for our team's efforts as we continue to demonstrate our capabilities in the public arena, just as we have done privately for over a decade.

Tyler will provide a detailed overview of the quarter, but I'd like to highlight a few key points. Our Controlled Capital program, which gives us full control over development timing and targets project rates of return in the mid-20s or better, continues to thrive. Though still in its early stages, production to-date has exceeded targets by approximately 15% and CapEx has come in about 15% under budget. We now have an inventory of over 40 net locations in the Permian that we plan to develop over the next 2 to 3 years. Given our early success, we plan to allocate even more resources to Controlled Capital. In 2024, this will account for nearly 50% of our CapEx. And based on current inventory, I anticipate that in 2025, approximately 60% of our CapEx will be dedicated to Controlled Capital.

On the deal front, we successfully closed over a dozen transactions this quarter, adding nearly 16 net locations at a total cost of $31 million. These new locations are projected to require $125 million in future development capital. This aligns with our typical ratio where $1 of entry drives roughly $3 to $4 in the ground. These additional locations are primarily within our Controlled Capital program and includes inventory under our new Midland Basin focused strategic partner where we continue to grow our position and plan to pick-up a rig later this year or early next year.

Turning to production. I mentioned last quarter that we anticipated a 5% to 10% decline in gas production for the third quarter. I'm pleased to report that we were wrong as we actually saw an increase in gas production. This outperformance was primarily driven by our first Controlled Capital pad in Loving County, Texas. Looking ahead to the fourth quarter, we do expect some flush gas production to taper off, potentially leading to a quarter-over-quarter gas production decline of up to 10%. However, this should be partially offset by a modest increase in oil production.

When going through our quarterly results, it stood out to me that 16.2 net wells in process as of September 30 is higher than usual. To add a bit more color, 12 of those net wells are under just 4 operators in the Delaware Basin. Of those 12, 5 are in our Controlled Capital program. We currently expect to put 2 to 4 net wells on production in the fourth quarter, followed by a significant increase in the first quarter.

I'll wrap up with a look ahead to next year. As mentioned on our August call, we anticipate double-digit production growth in 2025 compared to 2024. While we are not providing formal guidance for 2025 at this time, we do expect year-over-year production growth to be in the mid-teens with the oil weighting of 2025 production projected to be in the low-50% range.

On that note, I'll hand it over to Tyler to provide more insights into our results.

[Tyler Farquharson, executive]

Thanks, Luke, and good morning, everyone. For the third quarter, we reported average daily production of 25,200 Boe per day, marking a 9% increase over the second quarter and 5% from the third quarter last year. Notably, our oil volumes increased by 16% from the prior quarter to 12,700 Boe per day, raising our total oil percentage to 50% in the third quarter, up from 47% in the prior quarter. Our annual production guidance range of 23.3 to 25.3 Boe per day remains unchanged. However, we now expect more oil production for the year than originally guided and expect our fourth quarter oil production mix to be in the low-50s as we exit 2024. Overall, we expect our fourth quarter production to decline slightly versus our reported third quarter results.

Net income for the quarter was $9.1 million or $0.07 per share. Excluding non-cash and non-recurring items, adjusted net income was $18.5 million or $0.14 per share. Adjusted EBITDAX for the quarter was $75.4 million, representing a 10% increase from $68.3 million in the prior quarter despite a 6% decline in realized pricing on a Boe basis. Year-over-year, adjusted EBITDAX was down approximately 9%, primarily due to the impact of asset divestitures in Q4 2023 and lower realized pricing.

Per unit lease operating costs improved significantly from the prior quarter, coming in at $5.62 per Boe, a 14% improvement from $6.50 per Boe in the second quarter. Production and ad valorem taxes were 6.7% of sales, down from the 7.6% in 2024 and we feel comfortable reaffirming our full year operating expense guidance. Our per unit G&A expense, excluding non-cash stock-based compensation, improved by 25% to $2.16 per Boe for the quarter. This highlights the scalability of our business model. As production and sales grow, unit overhead costs continue to decline. Our annual guidance range of $23 million to $26 million is unchanged.

During the quarter, our operating partners completed and placed on production a total of 93 gross or 5.2 net wells with activity nearly evenly split between the Permian Basin and the DJ Basin and a handful in the Bakken. As of September 30, we had an additional 6.2 net wells in process. And as Luke mentioned, we expect 2 to 4 of those wells to be placed on production during the fourth quarter. In total, we continue to expect 22 to 24 net wells to be placed online during 2024 with nearly 80% of those wells being in the Permian Basin.

In the third quarter, we closed multiple transactions, adding 15.9 net future drilling locations, primarily in the Permian Basin, for a total cost of $30.9 million. Our acquisition capital guidance for 2024 remains unchanged at $60 million. Our development capital spending during the third quarter was $77.6 million, in line with expectations. We reaffirm our development capital guidance of $300 million at the midpoint of the range.

Notably, a substantial portion of our capital expenditures in the second half of this year have been directed towards our Controlled Capital development programs. We expect these investments to drive significant production and cash flow in the first half of 2025. During our Q4 call, we will provide formal 2025 guidance, which we anticipate will reflect strong year-over-year growth due in part to nearly $150 million worth of capital deployed during 2024 for activity expected to turn to sales during early 2025.

Finally, consistent with Granite Ridge's value proposition, we continued our quarterly cash dividend program, paying $0.11 per share in the third quarter. Subsequent to quarter end, our Board declared another $0.11 per share cash dividend payable on December 16, 2024 to shareholders of record as of November 29, 2024. This annualized dividend represents a 6.9% yield based on Wednesday's closing price, which underscores our commitment to returning differentiated value to our shareholders.

I will now hand it back to Luke for his closing comments. Luke?

[Luke Brandenberg, executive]

As we celebrate our second anniversary as a public company, it is an opportune time to reflect on our journey and future direction. One of my key priorities moving forward is to reshape the narrative around Granite Ridge. We are often categorized with non-controlled companies, but this does not accurately reflect our business. Typically, operators allocate about 75% of their capital expenditure to controlled projects and 25% to non-op. This year, Granite Ridge will allocate nearly 50% to controlled projects, increasing to around 60% next year. This allocation is more characteristic of an operator, yet we do not operate wells.

The value we create at Granite Ridge lies in our capital allocation strategy. We blend our non-op routes with control over development by controlling the purse strings. If we control development, but we do not operate, what are we? Publicly traded private equity. Granite Ridge combines the control of an operator with private equity's agility and capital allocation. By integrating private equity principles into a public entity, we aim to drive long-term value for shareholders in a vehicle with increased liquidity, enhanced visibility and alignment and immediate shareholder returns. This is a unique model and it is proving successful. We invite you to join us in building something special.

Thank you all for joining us this morning. I'm enthusiastic about the future of Granite Ridge. 2025 promises to be an exciting year for us. Our earnings release highlights several upcoming conferences over the next month. I look forward to seeing some of you in person or catching up on a call soon. As the holiday season approaches, I wish you and your families all the best.

Operator, please open the floor for questions.

[Operator]

[Operator Instructions] Your first question comes from the line of Noah Hungness with Bank of America.

[Noah Hungness, analyst]

I just wanted to start off here on your LOE costs. You guys came in pretty well below your guided range for the year. Could you just kind of talk about what drove that? And how we should think about LOE costs moving into 4Q and maybe into early '25?

[Tyler Farquharson, executive]

Yes, sure. So this year we've seen LOE costs come in under where we've been guiding to at least the past couple of quarters. That's mainly due to less workover expense. I think at some point, that will revert back to the mean. But for now, I think our Q4, we're expecting that we'd probably come in towards the lower end of our guidance range, which would put us, again, towards the low end of the guidance range for 2024.

[Noah Hungness, analyst]

Great. And then I kind of was hoping you guys could expand on -- I was looking at your Burgers & Beers, list of kind of basins you have added some leasehold, and it looked like you guys added some in Appalachia. I was hoping you could just give us some color there on where you're looking or is that in the Marcellus or the Utica? And if it's in one of those areas, is it more liquids or dry gas focused?

[Luke Brandenberg, executive]

Yes. Noah, this is Luke. Thanks for the question. Happy to take that. So we are really focused on the Utica condensate window, more Guernsey and Harrison. That's really a neat opportunity for us where we came across a group that has been active in that area and they were coming across really unleased minerals. And we were able to form a partnership with them such that whenever they had unleased, we got a first look at those. And so that's been a really good opportunity. They've been in the Utica since, gosh, I think 2006. They were up there in the very early days of the first wave.

So it's just a cool opportunity for us to really be a capital partner to groups that are finding the opportunities. Again, this is the area. If I had to paint a picture on a map, you got the dry gas stuff to the East, you've got EOG oil window to the West and we're in that radical middle where it's really a condensate -- rich condensate area. We're not putting a ton of capital to work there. There's -- wherever you are, people have figured out the good areas pretty quick. So it's tough to find unleased or stuff at a good deal. But the capital we have put to work, we're very excited about and we frankly would be excited to put more as long as we continue to find opportunities that hit our target returns.

[Operator]

Your next question comes from the line of Michael Scialla with Stephens Inc.

[Michael Scialla, analyst]

Luke, I want to see if you could give a little more color on the controlled CapEx partnerships. You talked about the drilling inventory now is up to 42.6 net locations. You said you might pick-up a rig in the Midland Basin in fourth quarter or first quarter next year. I guess, I want to see how many of those locations are in the Midland Basin partnership? And what will determine when you get that rig? Do you need more inventory there still or is it something else that will determine the timing there?

[Luke Brandenberg, executive]

Yes. Mike, thanks for the question. So if I -- a couple of pieces on that. As you mentioned, we really have 2 partners right now. One is primarily a Delaware Basin focused. The other is primarily Midland Basin focused. The Midland Basin asset, we're really in, I'd say, lease block-up mode right now where they have a nice initial position. But as we did with our initial Delaware Basin partnership, our real goal was to build-up enough inventory such that if we wanted to, we could keep a rig running for full time for a period of time anyways to try to drive some of the efficiencies from keeping one rig going versus going up and going down.

Right now, we have 5 or 6 net locations depending on what working interest shakes out to be in the Midland Basin and the rest is in the Delaware, but we're working on several transactions. I think that we'll block that up and increase that Midland Basin working interest piece. But right now, again, we're targeting probably late this year, early next, more than likely -- I'll say more than likely.

To be honest, one of the cool things about our strategy is we're trying to find the right rig at the right time. And so that's where we can be creative. And we'd rather have a better rig and wait a month than have a rig that's coming out of the yard and do it immediately. So I think late this year, early next, we'll pick-up Midland Basin. We're currently running 1 rig in the Delaware Basin. I'd anticipate that we'd go to 2 rigs in the Delaware Basin probably middle of next year.

[Michael Scialla, analyst]

Sounds good. I wanted to ask on Slide 9, your chart shows your look-back analysis, actual production versus what you've underwritten with your forecast. It looks like you're pretty much dead on production-wise and realize that it's -- with data out there, you can get a pretty good handle on what wells will produce in a given area. But as a non-operator, obviously, timing of development is -- it's a significant risk. So I guess, my question is, is that chart just showing well performance or is that also showing your performance versus -- I guess, does it -- sorry, does it incorporate timing into it as well? And if so, how are you handling the timing risk when you underwrite these acquisitions?

[Luke Brandenberg, executive]

Yes, it's a good question, Mike, and thanks for asking about that slide because it's something that we really are proud of. At the end of the day, if we're a publicly traded private equity firm and our real value is in capital allocation, a core piece of that is, are you any good at underwriting deals? And this slide really goes to demonstrate that that really is a strength and it's a strength that goes back for over a decade that we've been doing this largely on the private side. But this does not incorporate timing. This just takes the -- the engineers made a projection on what a well would do and then track that and saw what actual performance was for over 1,000 wells across multiple basins.

A neat thing about this, and I think a big driver for why this number is so tight is, to your point, the data set that we have, just being in over 3,000 wells. In many and each of these basins, geology can change quite rapidly. But the more data points that you have, the better chance you have of making a good estimate. We've been in the Permian Basin since, gosh, 2013. So we have a strong data set of actuals that really helped this. And I'd say, the neat thing is, Mike, this would continue to improve. I said there's not a whole lot of room for improvement, but just we get more data points every single day and our team continues to incorporate that in their underwriting. So we're very proud of our engineering team, our underwriting capabilities and that is just a true cornerstone of the business and the success we've had to date.

[Operator]

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

[Phillips Johnston, analyst]

Lots of good color in the prepared remarks just about the trajectory of production. Just wanted to make sure I caught everything. So let's talk oil. So your implied fourth quarter guidance suggests about a 3% kind of downtick in oil volumes sort of on the heels of what was pretty outsized growth, obviously, in Q3. Then it sounds like you expect a large sequential increase in Q1, which I think is consistent with what you guys said on the second quarter call. And it seems like that might even be augmented by the 9 Controlled Capital spuds in the Permian. So just wondering what kind of order of magnitude we're talking about in Q1? And then I guess, for the full year, I think you said double-digit growth on a year-over-year basis. I just wanted to clarify if that applies to oil or Boe or both?

[Luke Brandenberg, executive]

Yes. Great questions. And thanks, Phil, I appreciate you dialing in. On the -- I'll hit from third quarter to fourth quarter first. On the gas side, we anticipate what could approach a 10% decline in gas quarter-over-quarter from third to fourth, and that's primarily driven from, frankly, some of these new wells and that rolling off the flush production side.

A big piece of the gas outperformance from second to third quarter was our first Controlled Capital pad there in Loving County. One of the difference makers there is we drilled 8 wells in that pad, 2 in the XY, 2 in the A, 2 in the B, 2 in the C. And the B and the C are gassier zones. And I'd say, we're generally conservative in an area where we do have fewer data points there. We had a lot of XY and As, but fewer approximate data points in the B and C and we were conservative in underwriting the gas side. We saw significant outperformance there. I anticipate that some of that will start to roll off. So again, gas, looking at up to 10% decline from third to fourth quarter.

On the oil side, I actually anticipate that we'll see a slight uptick to mitigate some of that gas decline, but not a significant one, low-single-digits. As we look to next year, Tyler made this point in his comments, which I think was a good one. We anticipate spending probably $150 million in '24 on wells that we will not see any contribution from until next year. And a lot of those wells I think will come online early next year. We mentioned -- like I mentioned, we have just over 16 WIPs at the end of 9/30. And we expect 2 to 4 wells to turn to sales in the fourth quarter. And so a lot of those are going to come on early first quarter. And so I anticipate first quarter, we'll see a pretty significant jump in production. I think you'll see that both on the oil and gas side.

For '25, you are correct. I mentioned double-digit growth last quarter. I mentioned in my remarks earlier, we think that will be mid-teens. So I'm going to narrow that down a little bit. We're looking for mid-teens growth on a Boe basis. I think that you'll see growth year-over-year in both oil and gas, but primarily on the oil side. And so that's going to be the big driver is Controlled Capital program. That's all -- I guess, all Midland Basin focused -- excuse me, all Delaware and Midland Basin focused at this point, but it will be a primary oil-driven growth in '25, which we are very excited about.

[Phillips Johnston, analyst]

Okay, great. That's good color. And then maybe can you talk about where you expect to end the year just in terms of the next 12-month PDP decline rate? And kind of what that might look like relative to kind of where you came end of the year? You guys have had a decent amount of growth. So just wondering if your PDP decline rate has changed significantly?

[Luke Brandenberg, executive]

Yes, I think it's increased a bit. I'd say, we're around 40% right now. If you had asked me this a year ago, actually, I don't know, you may have. But a year ago, I probably would have said it was high-30s, and I would say, it's around 40%. So it has picked up a little bit. And a big piece is, again, the Controlled Capital program, which is the higher working interest wells. So we recognized that by doing that you do increase the treadmill a bit, certainly in the near-term. But that's a big piece of why we wanted to wait to pick-up a rig until we had enough inventory to keep it going. That will help to stabilize that treadmill over time.

[Operator]

Your next question comes from the line of Jeff Robertson with Water Tower Research.

[Jeffrey Robertson, analyst]

Luke, I think you said that all of your or most of your Controlled Capital is currently in the Permian Basin. I'm wondering if you're seeing opportunities in some of the other basins that you operate for Controlled Capital type partnerships?

[Luke Brandenberg, executive]

Yes, that's a great question, Jeff, because right now, we have 2 Controlled Capital partnerships. I'd love to have 3 or 4. And we are looking at other basins. One of the challenges that we see right now, our Controlled Capital program is really focused on near-term development. And so areas that are gas weighted are tough for us. Just given current economics, drilling new gas wells right now is just more challenged. And so there are areas on the gas side that could be compelling from an inventory capture perspective and there are some teams out there that are very high quality, have created a lot of value and I think could be interested in the type of partnership that we have. But gas side is tough.

And so as we do look in other areas, we're, I'd say, in some form of dialogue with a couple of other teams right now. I would think Bakken and Eagle Ford are 2 of the basins that we're looking at pretty hard right now in the sense that we see an opportunity for our existing assets to potentially contribute to building a partnership. The one thing is in all these basins, frankly, is that the treasure maps are well defined in a lot of spots. And so you're not finding unleased acreage. And so a big piece has really become that trading game. So a big advantage that we have and really a way that we can add value to potential partners is, we do have a lot of acreage across these different basins, take the Bakken, for example, that could be used to trade. Sometimes trade is more appealing than cash for a lot of these large operators they want to work with.

So that's a long-winded way of saying, absolutely. We would love to have and see some different basins. I think Eagle Ford and Bakken are very compelling based on the opportunity set that is out there and the data that we have. I'd say, Eagle Ford is a bit tougher just because there's fewer opportunities. But yes, we'll continue to look. We are certainly open for business on that side. And I'd like to allocate more and more capital to that program. We've loved the success to date. I think that we can provide a differentiated solution to some of these proven management teams and we will continue to look. So thank you for asking that.

[Jeffrey Robertson, analyst]

I guess, as a follow-up, it sounds like it would probably be complicated, but you could use some of Granite Ridge's leases in some of these basins to help a control partner solidify acreage in an area that 2 of you would like to participate. Is that fair or is that too complicated to try to put together?

[Luke Brandenberg, executive]

No, it's not too complicated. And we've actually done that on multiple occasions with our Delaware Basin focused partner where we've had acreage in a good area and they were trying to cut a deal with that operator in a different area and we were able to use that acreage as currency to help grease the skids and get the deal done. So no, it's a great point. I think it is a true value-add that we have with our partners in the Delaware and Midland Basin. Day 1 of getting that partnership going, we said, hey, look, here's everything that we have in your area of interest. If there's a way that you can use that to help facilitate capturing inventory in other parts, have at it. That's -- we can easily find a way to make that work for both sides. So it's a great point. I think it is a big differentiator for us as folks are looking for capital partners.

[Operator]

We have no further questions in our queue at this time. And with that, that does conclude today's conference call. Thank you for your participation. And you may now disconnect.