Northern Oil and Gas, Inc. (NYSE:NOG) Q2 2024 Earnings Call Transcript

Northern Oil and Gas, Inc. (NYSE:NOG) Q2 2024 Earnings Call Transcript July 31, 2024

Operator: Greetings and welcome to the NOG’s Second Quarter 2024 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation [Operator Instructions] As a reminder, this call is being recorded. It is now my pleasure to introduce your host Evelyn Infurna, Vice President, Investor Relations. Thank you. You may begin.

Evelyn Infurna: Good morning. Welcome to NOG’s second quarter 2024 earnings conference call. Yesterday after the market closed, we released our financial results for the second quarter. You can access our earnings release and presentation on our Investor Relations’ website at noginc.com and our 10-Q will be filed with the SEC within the next few days. I’m joined this morning by our Chief Executive Officer, Nick O’Grady; our President, Adam Dirlam, our Chief Financial Officer, Chad Allen and our Chief Technical Officer, Jim Evans. Our agenda for today’s call is as follows; Nick will provide his remarks on the quarter and on our recent accomplishments; then Adam will give you an overview of operations and business development activities; and Chad will review our financial results and walk through updates to our 2024 guidance.

After our prepared remarks, the team will be available to answer any questions. Before we begin, let me cover our Safe Harbor language. Please be advised that our remarks today including the answers to your questions may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by our forward-looking statements. Those risks include, among others, matters that have been described in our earnings release as well as our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements.

During today’s call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA, adjusted net income, and free cash flow. Reconciliation of these measures to the closest GAAP measures can be found in our earnings release. With that, I’ll turn the call over to Nick.

Nick O’Grady: Thanks Evelyn. Welcome and good morning everyone and thank you for your interest in our company. I’m going to change things up this quarter by answering five key questions. Number one, so how has it been going? On our fourth quarter call and several before that, I have spoken about the importance of delivering growth and profitability over time. I’d like to use that framework once again and put the results from the second quarter into context. Our second quarter adjusted EBITDA was up 31% year-over-year and 52% versus two years ago. Our quarterly cash flow from operations, excluding working capital, was up 33% year-over-year and about 48% versus two years ago. We achieved outsized growth per share despite commodity prices that fluctuate.

Oil prices were a bit higher and gas prices a bit lower than a year ago, but two years ago, oil prices were over $20 higher and gas prices over triple the current price. Even more impressive is the fact that despite our growth in a volatile commodity price environment, our LQA debt ratios have stayed in check in the low 1.1 range. This range is actually lower than a year ago. So, in summary, our per share metrics continue to rise throughout the cycle, supported by a low leverage and strong balance sheet. While growth is important, returns and capital efficiency are paramount. Our return on capital this quarter was approximately 25%, impressive when taking into account the step-up in capitalization we experience every time we make a significant acquisition.

In the last year, our return on capital employed was over 28%. That was 14% higher than the average of our 16 company peer set, and for business context, double that of the average public nonoperators in our peer set. Within our broader peer set, it shows that our business model allows for superior capital allocation, but I bring other nonoperators to show that from a managerial and asset perspective, we’re also doing it better than others within our own niche. Our company continues to be focused on the same simple philosophy, finding ways to sustainably grow profits per share through cycle and over time for our investors. We believe that is the path to driving long-term share price outperformance. While oil and gas prices go through cycles that can and will affect our profits, again, it is our job, and we will find ways to grow the business through such times.

With our assets performing well, solid organic growth in the pipeline and recently announced acquisitions, our business is poised to grow profits and cash flow further. Number two. So, what does that mean for you? We haven’t even closed on our XCL or DuPont transactions. But based on where the business is year-to-date and our confidence in the outlook, we will be recommending a midyear bump to the dividend. Additionally, we’ve been active in the first half, repurchasing shares, and have renewed our share repurchase plan. We are very discerning about when we repurchase shares and have had a track record of entering the market during periods of value compression and when we believe the market has understated our growth potential. And hence, we’ve had the opportunity in the first half of 2024.

We prioritized that over dividend growth in the short-term, but that won’t always be the case as our increased recommendation should also show our investors. Let me be explicitly clear, we believe there is additional capacity for growth, either in dividends or in future buyback capacity, but we are also remaining conservative and dedicated to managing leverage carefully as we have done meticulously over the past six-plus years. We will sit down with the Board during our regular review in Q1 2025 to discuss a further increase to the dividend, additional buyback capacity, and obviously, ensuring that our balance sheet remains strong and is on a path to getting stronger after the outlay of the capital for DuPont and XCL acquisitions. Number three, what’s behind the Uinta?

In June, we announced our largest transaction ever, the co-purchase of SCO Resources Uinta Basin assets with SM Energy. For many investors, the Uinta is less well known than the Marquee shale play. In the past four years, however, it’s been amongst the fastest-growing oil play in the country. I won’t mince words when I say that personally, I have never been more excited about a transaction during my tenure here at NOG. The benefits of this asset will pay huge dividends for our investors over the next decade. The facts are simple. You have a multi-stacked pay asset where, unlike the Permian, much of the aspiration was not allocated value in our acquisition, providing upside for our investors even as many of these benches have been proven out by other operators.

When planning with SM, we put forth very conservative cost spacing and pricing assumptions. The economics of the wells are very similar and competitive with those in the Delaware Basin in terms of productivity, but with the cost structure of Midland wells and an extremely high oil cut with high-quality crude that is exceptionally valuable. And while the one knock on the play is the higher cost of oil takeaway, the logistical changes that have taken place over the past few years are less well known. Whereas once the oil was captive to a handful of local refiners, there is now easily expandable rail capacity could take oil away from the basin to the Gulf Coast where the crude is in high demand. Over the longer term, we believe project by project, there will be ways to cut the transport costs further as well even when accounting for the higher transport costs, the economics compete favorably with anything in our portfolio.

And over the next several years, I think our investors will come to appreciate this asset more and more, and we believe it will pay dividends in the years to come, both figuratively and literally. Number four, how is the future looking? We find the business in the catbird seat as we hit midyear. We have come through some of the heaviest spend periods over the past few quarters, which has required some patience from our investors. And as you see in the results today, that’s converting into significant free cash flow now. Our balance sheet debt ratios are ahead of schedule and more than half of Q2’s turn-in-line activity will actually have more impact on Q3 volumes. So, we see a very strong outlook for the base business as the year progresses, even as our capital commitments stabilize.

Organic activity on our acreage has also been very healthy and as you’ve seen, we’ve had success in all facets of our business, including the ground game and significant bolt-ons. We’re seeing a renaissance of sorts in the Williston with longer laterals and a notable increase in refrac activity as operators are finding ways to maintain and even grow in our legacy basin. In 2023, we raised equity without announcing an acquisition for the first time in my tenure here at NOG, something we didn’t take lightly. In marketing our offering, I told investors, “We were getting ahead of the opportunities in front of us and believe it sets the stage for over $1 billion worth of acquisitions on the balance sheet in just the next year.” Here we are nine months later, and we have deployed $900 million through two Delaware transactions, one Utica transaction within our Marquee Uinta transaction.

Our balance sheet remains in great shape, and we still have capacity within our framework to do more if the right opportunity arises. We are people that believe in doing what we say and when we raise that capital, first of all, we believe we have the opportunity set to put it to good work. And secondly, we wanted to be in a position to deliver accretive growth to our investors on the other side. And I’m proud to say I believe we’ve done just that. These transactions, combined with our other organic projects have us poised for year-over-year per share growth in 2024 and in 2025, regardless of the commodity strip, something few companies can match in the space. Number five. So, what’s next? In an era of substantial industry consolidation, we’ve been at the forefront of the trend in our niche.

And what we’ve created in just the past few years is incredibly valuable and not always fully appreciated by our investors. An example would be EQT’s recent non-operated asset sale in Appalachia, it implies a 3 times to 5 times or even greater value for what we purchased in the Marcellus just a few short years ago. We’re proud of what we’ve accomplished. We believe we’ve been superior capital allocators and been ahead of the curve in terms of strategy. But as I mentioned earlier this year, we also believe the best is yet to come. people then ask us what is the endgame? As a fiduciary, we don’t get to answer that question. There is no end. Our goal is to never stop growing our profits and ultimately, the value of the stock for you. Maximizing value is the main goal, however, that can be achieved.

That’s how our Board motivates us and that’s how we’re aligned. From a competitive landscape, we would continue to reiterate what we have said at [Indiscernible] quarter-after-quarter, which is at scale to get scale and that we stand on our own. Basic business rules apply in our line of work, barriers to entry are wheel, and those focused on small deals, on small assets, with small capital commitments, face significant competition. But the transactions you have seen us participating in the creative, complex and customized solutions are largely those where we simply stand alone and those ones where return potential is much higher, where long-term upside with our operating partners is higher. And where you’ll see us focus our efforts in the long term to the benefit of our stakeholders.

That concludes my prepared remarks. So, I’ll close out, as I always do, by thanking NOG engineering, land, BD, finance, and planning teams and everyone else on board, our investors and covering analysts for listening, and our operators and partners for all the hard work they do in the field. We hit midyear 2024 in great shape. And as always, our team is laser-focused on delivering optimal total return. That’s because we’re a company run by investors for investors. With that, I’ll turn it over to Adam.

Adam Dirlam: Thanks Nick. As usual, I will kick this off with a review of our operational highlights and then turn to our business development efforts on the current M&A landscape. During the second quarter, we saw production increase to over 123,000 BOE per day, driven by steady turn-in-line activity and some increased Permian, Utica, and Marcellus activity. We turned in line 30.1 net wells with the Permian making up more than two-thirds of the activity during the quarter. The most important comment I would make in terms of Q2 TILs is that over half of them occurred in the month of June and the bulk of those wells were cleaning up and contributed very little to volumes. They will have a much larger impact on Q3 oil and total volumes, and this bodes very well as we continue on track through the year.

Thus far in 2024, we have seen steady activity, including robust organic activity, increased refrac proposals, and continued production momentum from our various JV projects as a significant portion of the capital we deployed in the past nine months converts into sales. Overall, we expect a relatively consistent cadence in terms of TILs for the balance of 2024, though Q3 will likely be lower because of the pull forward late in Q2. This will not have an effect on production as many of those wells are still ramping. We see robust activity in Q4, both in terms of TILs and additional refrac AFEs in the Williston. In the second quarter, we consent to another 16.7 net wells, a 46% increase from Q1 on a net basis and a 20% increase on a gross basis with 197 total consents.

This points out that we saw a larger average working interest in Q2 as well proposals, almost doubling the average working interest from Q1. Our economics remain strong as we consented to 94% of our well proposals on a net basis, while we continue to manage the portfolio non-consenting those that do not meet our hurdle rate requirements. It’s worth noting that the working interest average in our non-consents is roughly tapped that of our consented average, which is a testament to our active management. We focus on purchasing more lands in the best areas and our lower working interest in low-value areas tend to be the areas where we non-consent. In terms of costs, while we have enjoyed cost reductions from prior levels on some of our major joint ventures, we are seeing stable costs portfolio-wide.

Absent any major changes to commodity prices, we are not anticipating any meaningful changes to development costs going forward. The acquisitions we completed in the past few years continued to shine and the capital efficiency is beginning to bear fruit as our free cash flow more than doubled in the quarter and should remain strong as we turn to the back half of the year. At the same time, we continue to see strong AFE activity on our acreage that should keep our production stable over time. Shifting gears to business development and the M&A landscape, the second quarter highlighted another banner quarter for NOG, both on our ground game and in larger M&A. And a shift from Q1, our ground game in the second quarter saw a market pickup as we focused on bespoke [ph] larger working interests.

By doing so, we’ve been able to maintain our full-cycle hurdle rates and avoid the more commoditized, smaller-scale market with lower barriers to entry. In total, we spent approximately $25 million in capital underground game, just under $11 million of which was acquisition capital, acquiring 6.1 net wells, and approximately 1,800 net acres. Year-to-date, that brings us to approximately 6.7 net wells and almost 3,500 net acres in total. During the quarter, we also signed our largest transaction ever expanding into the Uinta Basin and our joint acquisition of the XCL Resources assets with SM Energy. Similar to our approach with Noble and Forge, we partnered with SM to purchase a large-scale operated asset, coupled with a long-term joint development agreement and area of mutual interest.

This asset has a very long life, tremendous upside, economics that compete with anything in our existing portfolio, and we see significant operational upside from SM’s stewardship as well as future exploration potential from the multi-stacked benches. Specific to XCL, within our AMI, we are already working on acquisition opportunities, which would create additional optionality and future upside. Subsequent to the closing of the quarter, we have continued the momentum, partnering once again with our friends at Vital agreeing to purchase the Ward County Delaware assets, Point Energy Partners for $220 million net to NOG. Similar to XCL and our past transactions, we also have a long-term joint operating agreement in place with Vital and look forward to many years of development on the asset.

As we have seen with our Forge JV, we think [Indiscernible] bring significant improvements to go-forward performance on the point assets. As all these transactions detail, we continue to build scale, but scale combined with a key focus on returns. As Nick noted, our return on capital continues to be best-in-class, all the more impressive given how acquisitive we have been. It’s a testament to the rigor of our acquisition underwriting, our capital allocation methodology, and the quality of the properties that we seek and ultimately acquired. The overall landscape continues to be robust and we see another wave of divestitures coming on the back end of the large-scale M&A that has transpired over the past 18 months. Many large operators are looking to clean up their portfolios or in some cases, their balance sheets, and we expect NOG may find some significant opportunities as these processes emerge.

Some of these parties have reached out directly to us seeking our customized solutions and we’ll continue to have those conversations. As I’ve described before, these of market transactions can be tailor-made for both parties and with our growth in size and liquidity could be as large or larger than any of our recent transactions. Simply put, the options to deploy capital on top-tier assets is in no way slowing down for NOG. Depending on the needs and the wants of the operator, the solutions could include simple non-op portfolio cleanups, joint development agreements, co-buying operated properties, minority interest carve-outs of operator positions, or any combination thereof. At NOG, we continue to demonstrate unmatched execution with win-win solutions through creativity and alignment with our current and prospective operating partners.

By focusing on returns first, growth has become a natural output as we continue to compound capital for our investors and remain singularly focused on putting our stakeholders first. With that, I’ll turn it over to Chad.

Chad Allen: Thanks Adam. Our second quarter results did not disappoint and were one for the record books. Average daily production in the quarter was more than 123,000 BOE per day, up nearly 4,000 BOE per day compared to Q1 and up 36% compared to Q2 of 2023, establishing a new NOG record. We continue to see outperformance on our recent Utica acquisition as well as our Marcellus assets that helped drive the beat on production. Oil production came in at just over 69,600 barrels per day. Even over half of our Q2 net well adds occurred in June and contributed only modestly to our Q2 volumes, including our higher oil cut Mascot Project, which is still filling up, but bodes well as we enter the third quarter. Adjusted EBITDA in the quarter was $413 million, up 7% sequentially and a record for NOG due to stronger well performance, lower cost, and better oil utilizations.

Free cash flow of $134 million in the quarter was higher sequentially and nearly tripled from the same period last year due to the strength of our underlying assets and the pull-forward activity in the prior quarter, which kept capital in check. We anticipate free cash flow to continue to stay elevated in Q3 and remain elevated for the balance of 2024 as the remainder of our TILs come online and begin to contribute to production and revenue. Oil differentials were better than our expectations at an average of $3.55 per barrel below the lower end of our guidance. Williston differentials trended down in the second quarter as we anticipated, and Permian differentials were also improved, normalizing for winter months. We also saw better realizations from our joint development projects.

Natural gas realizations are also ahead of schedule at 107% of benchmark prices for the quarter, materially ahead of our forecast due to better-than-anticipated natural gas prices in Q2 and higher NGL price realizations. This was partially offset by weaker Appalachia differentials and negative Waha gas for most of the quarter. Overall, for the year, however, we believe differentials will trend towards our revised guidance range, especially now that gas has returned to lower levels. LOE was down 7% sequentially to $8.99 per BOE, reflected the continued shift of our production to the Permian, which carried a lower LOE compared to the Williston. And we also benefited from the easing of weather-related show-ins from the prior quarter. As we previously discussed, we anticipate LOE per BOE to gradually decline as production ramps from our joint development projects.

Additionally, our recently announced acquisitions will add more production with materially lower LOE. These assets are resilient and low cost, and the XCL asset also brings very high oil cuts. Production taxes were 8.7%, slightly below our guidance as gas production ramps in all basins as gas typically carries a lower production tax rate. We anticipate production taxes to trend even lower after the addition of XCL as the winter comes with a lower tax rate. On the CapEx front, we invested $237 million inclusive the ground gain in the quarter. Of the $237 million, 59% was allocated to Permian, 37% of the Williston, and 4% to Appalachia. We continue to experience a pull-forward of organic activity driven by the strength in oil prices. However, given the level of completion in our D&C list, the higher to come in Q2 did not have a material impact on total CapEx for the quarter.

With that said, if the strength in oil prices persist, CapEx may trend towards the higher end of our revised guidance range for the year. Some of this capital will be driven potentially by 2025 turn-in lines that could be accelerated into 2024 and by additional E&P activity for 2025 turn-in lines we anticipate in the back half of the year. This will obviously be dependent on commodity price environment, materially weaker oil prices were, of course, slow operator activity. With that said, if we did see higher CapEx who will be accompanied by higher production as our D&C list is actively converting to TILs and spuds and drawing down our working capital. Specifically, on the working capital front, excluding the impact of derivatives, we have seen an improvement of approximately $65 million year-to-date.

As a result of the improvement in working capital, we reduced our borrowings to our volume credit facility by $65 million during the quarter. As of June 30th, we had $1.3 billion of liquidity comprised of $33 million of cash on hand, including the deposit for XCL and $1.3 billion available on our revolving credit facility. At quarter end, net debt to LQA EBITDA was 1.1 times. We expect the ratio to tick up modestly upon the closing of our recently announced transactions, but trend down throughout 2025 solidly to our stated target. As Nick discussed earlier, we actively repurchased shares in the first half of the year. Year-to-date, we repurchased 1.4 million shares or approximately $55 million of our common equity at an average price of $37.99.

We are committed to allocating capital to share repurchases where there is a mark diverge between our absolute and relative performance. However, given we are funding our announced acquisitions with the revolver, we will be mindful of getting leverage back to our stated target. Given the outperformance of our wells year-to-date and the anticipated closings of our pending acquisitions, I’d like to address our adjustments to guidance. Note, this guidance assumes an October 1st close of both acquisitions and the actual closing dates could change. So, this guidance is somewhat preliminary in nature. We will give an update on our third quarter call, if anything changes materially during the closing processes. We are raising total production guidance by 4% at the midpoint to a range of 120,000 to 124,000 BOE per day.

Obviously, we only get around one quarter of benefit from our new deals, so this reflects some of the outperformance we’ve seen year-to-date, particularly on gas production. We have also increased guidance on oil production at the midpoint by 4% to a range of 73,000 to 76,000 barrels per day, reflecting the higher oil cut of the Uinta and DuPont relative to our corporate average. Our turn-in-line guidance moves up to a range of 93 to 98 net wells with spuds going into a range of 73 to 78 net wells. With respect to unit costs, given the unique nature of the Uinta, we are lowering LOE by 3% at the midpoint of the range of $9.15 to $9.40 per BOE. Production taxes should also trend lower to a range of 9% to 9.5%, and we are raising the high end of our oil differential to $4.85 per BOE to reflect higher transportation costs in Uinta, and we are increasing our gas realizations to a range of 87.5% to 92.5% to reflect better NGL and natural gas pricing.

With respect to DD&A, we are tagging the range to $16.50 to $17.50 per BOE. Our overall cash and non-cash G&A per DOA [ph] should both decline demonstrating the benefits of increased scale and the inherent operating leverage of our unique business model. That concludes our prepared remarks. I’d like to open the call up to questions.

Q&A Session

Operator: Thank you. [Operator Instructions] Your first question comes from the line of Neal Dingmann with Truist Securities. Your line is open.

Neal Dingmann: Good morning, guys. Nice quarter and outlook. Nick, my first question maybe for you, Adam, is just on deal parameters, specifically, I’m just wondering maybe how things have changed now with these larger deals. Could you talk about how your requirements when you think about sort of payback periods, PUD value under location value, all that sort of thing, how that sort of shakes out today versus maybe a year or two ago?

Nick O’Grady: I don’t think anything has really changed. I mean, I think in general, over the last three years, we have raised our hurdle rates materially just, I would say, as the cost of capital grows, we’ve generally increased our hurdle rates, and that’s been something we’ve consistently done since, call it, 2020. But otherwise, I think we generally look for a balanced portfolio, which is that we want we look forward at a package level self-funding assets where we can, but we will look for — there are specific things where if it is an asset which is in development that can be okay, too. I don’t know if you want to comment to that?

Adam Dirlam: Yes. I think it also dovetails into the governance trite asset specifics in that regard. And so if there’s ways that we can get comfortable with the underwriting with kind of the go-forward governance in order to maintain alignment and get that transparency, that’s all going to come into play, not only with the quantitative but the qualitative review.

Nick O’Grady: Yes. And I think one of the questions we’ve gotten from our investors is just the difference between sort of the co purchase of assets with operators versus a traditional non-operated asset and how you win. And I think it’s just there are different paradigms to earning super normal returns, right, versus how you underwrite, which is that on a non-operated asset, how you win is ultimately that we — the undeveloped asset is you try to pay as little as possible on that undeveloped piece and ultimately be surprised by the future development, right, which is the PUD value and what you’re paying for, ultimately, you get future development costs at a discount, right? And that’s the benefit of buying non-operated assets at that discount.

And what we’ve observed on the co-purchase of those assets is that we’ve seen huge synergies from the vitals and from the Permian Resources in which as they’ve taken possession of these assets, they’ve become much superior operators, and they cut costs and drill better wells. And so we’ve seen huge upside in performance on those assets as they’ve been able to do better. And so we’ve seen increases in returns in a different way. So it’s different ways to create the same types of upside.

Neal Dingmann: Well said. And then my second, just on capital allocation. Specifically, you have maintained an active ground game to say the lease and while continuing to even recently boosting the dividend and talked about shareholder return again. I’m just wondering, could you talk about — I know they’re not exclusive, but maybe just talk about how those two sort of play together?

Nick O’Grady: Yeah. I mean I think in terms of the ground game, I mean, I think you had ebbs and flows, obviously, there is a seasonality to it. I would expect as we get towards the end of the year, it tends to get a bit busier. I would imagine we see a bit of a — it may start to get active towards the end of the third quarter, potentially as budgets start to get tighter. And our ground game has evolved somewhat, which it has become a bit more bespoke and more — generally more concentrated in the last few years in terms of how it has happened. It’s been a little bit chunkier in terms of the interest. But ultimately, in terms of shareholder returns, I don’t think we view them as mutually exclusive, Neal. And I think as we mentioned in our prepared remarks, I think we’ll sit down with the Board at the beginning of the year. We really do believe that the business has the capacity for additional shareholder returns, particularly on the dividend side.

Adam Dirlam: The only other thing I’d add on the ground game is that it’s also going to depend on kind of what the organic asset is pulling, right? So we’re looking at that on a monthly basis and understanding exactly what the working interests are coming in, and that will also dictate whether or not we’re leaning in on any particular opportunities on the ground game, one way or another.

Operator: Your next question comes from the line of John Freeman with Raymond James. Your line is open.

John Freeman: Good morning, guys. The first question I had, I saw that XCL recently closed on the Altamont acquisition. Just can you all provide any color on how that potentially impacts the original HCL purchase price kind of any pro forma estimates, things like that?

Nick O’Grady: Yeah. So you’re correct, John. So the FTC granted approval to XCL to acquire Altamont. And as part of that, that is within the AMI for SM and us. And so we will have the option to purchase those assets. What I can tell you is that we are under — we are currently doing our analysis and review of those assets. And what I will say is we’re very encouraged by what we see. And obviously, if we choose to exercise that option, respectively, obviously, it would be 80-20. It would be a material add in terms of acreage to our position, but very immaterial in terms of capital.

Adam Dirlam: Yeah. And there’s a number of DSPs that are directly offsetting the position, and that’s kind of where the focus is.

John Freeman: Got it. And then my follow-up question. When we think about the timing on those TILs coming on over half of them come on June and then specifically on the mascot wells that are taking a while to clean up. Now that we’re basically through July. I’m just trying to get a sense on the Mascot wells? Are they like fully cleaned up? Are we still going through that process? I’m just trying to get a sense of whether you’re going to get the full 3Q benefit from those Mascot wells or it kind of drag a little bit more into the quarter.

Nick O’Grady: Well, I mean you put 10 million — 10 million barrels of water into the ground, right? So it takes several months in a cube development to take it. So I would imagine by the end of the third quarter, you’re going to be pretty — I mean, Jim tell me I’m wrong, but probably by the end of the third quarter, they’ll be pretty much fully going. So you’ll get I would imagine by the end of August or September, there will be at full capacity, but it takes what it takes your pumping out, call it, like 30,000 barrels a day of water out of them. So it’s going to take some time, but everything is going according to plan. You’re not going to get all that water out, John, but it just — in a cube development like this, where you’re doing all the zones, it’s a massive project, right? So, everything is going about the way it’s expected.

Operator: Your next question comes from the line of Scott Hanold with RBC. Your line is open.

Scott Hanold: Thanks. I have a question on M&A. Obviously, you guys have done a number of deals here over the last few years, and it sounds like there’s still some pretty decent visibility. You’ve got Ultimate other things in the Uinta. Can you give us a sense of how you think about the balance sheet? I know I think it was Nick or Chad mentioned some of the stuff you felt like you pre-funded coming into earlier this year, but can you think about like as you think about moving forward in the balance sheet, any incremental transactions, how do you look at funding? And where do you kind of like to see that balance sheet leverage at on a go-forward basis?

Nick O’Grady: Yeah. I mean, Scott, certainly within our framework, we have the capacity currently to do a significant amount more before we would bust out of our kind of self-described framework, which is really kind of 1.5 times. I mean, I think could we go slightly over that for a period of time if we were comfortable, sure. Would we like to do that? No. But I think from a liquidity perspective, you could always bond out that capital, if we really needed to. I don’t think we feel compelled to do that at all just given the cash generation of the business at current. But I think, look, the fact of the matter is with M&A, the timing is very unpredictable. So unless something was to come in the immediacy, if we roll the clock for nine months from now, as the business generates cash flow, quite frankly, we’ll be able to handle more M&A on balance sheet without worrying about these types of things, right?

Because ultimately, it’s more a function of timing than anything else, right? I don’t know if I could say it any differently than that, meaning like the way we model this out within a few quarters, we’re right back to target. And so therefore, I don’t really — unless M&A becomes so substantial you’d really have to capitalize it in some other way. So it really — it’s more about the acute moment in time than it is absolute leverage…

Operator: [Operator Instructions] Your next question comes from the line of Donovan Schafer with Northland Capital Markets. Your line is open.

Donovan Schafer: Hey, guys. Thanks for taking the question. So first, I just want to dig into the Uinta play a little bit. I’m not as familiar with that one in the more like current shale revolution type context. I know from a more historical standpoint. So the different benches and things being developed there, is it more of — is it really like a true sort of shale play? Or is it kind of a statistical play where as long as you put enough holes in the ground, you can feel good about the returns? Or is it going into something more conventional, but having an opportunity to exploit it with horizontal drilling, fracking and so forth. Just any clarification there would be helpful.

Jim Evans: Hey, Donovan, this is Jim. Yeah, I would just attribute it similar to shale play, very similar to the Permian, where you’ve got 4,000 feet of all these stacked zones. We do see that there is true separation. If you look at the oil that comes out of the different benches, they are different color, different grades. So you can tell that they are true stand-alone different zones. All of them have been proven from a vertical standpoint. It’s just recently that they’ve switched to horizontal. The main target is what they call the lower cube. That’s the primary upper was set that has been targeted most recently. They’re now starting to target the upper cube, which is going to be your garden bulge, Douglas Creek. That’s a little bit earlier in the stages.

But those are the primary zones that are being targeted. You’ve also got deeper zones as well that are kind of early stages proven vertically, but not yet horizontally. We’re giving no value to that. But that’s kind of what we’re seeing here from a geologic standpoint.

Operator: Your next question comes from the line of Charles Meade with Johnson Rice. Your line is open.

Charles Meade: Good morning. The whole energy team there. I want to actually pick up on where you just left off with that discussion of the Uinta. As I’ve tried to come up to speed on the play, some of the big players there, let’s just say that there may be emphasized in other parts of their portfolio, but it looks like XCL and SM have been the most — I have given the most disclosure in — or maybe the most aggressive in identifying the upside. So, my impression is most of the development has been in that Uinta Butte [ph] — and I’m wondering if you could kind of say, if that’s your plan going forward for the next 12 months, if that’s what you’re going to target and what any time line is to target some of these other horizons with horizontal wells that have been historically proven productive and vertical wells.

Jim Evans: Yeah. So the plan is primarily focused on the lower and upper Cube. It’s going to be a mix of both. We’re not just drilling Uinta Butte Wasatch. We’re mixing in the Douglas Creek as well. So we plan to co-develop the upper and lower cube together. The deeper stuff is farther down the road. We’ll develop that as we kind of see how these first couple of cubes turn out, and then we’ll go from there.

Operator: Your next question comes from the line of Phillips Johnston with Capital One. Your line is open.

Phillips Johnston: Hey. Thanks for taking the question. I wanted to ask about your implied natural gas production guidance for the back half of the year. It sort of suggests that volumes will decline by more than 15% from the second quarter. I know you had some EQT wells that led to some pretty strong growth in Q2, but it seems like the decline for the rest of the year is pretty steep, I guess, especially considering you’ve got some incremental gas in the door from these two acquisitions?

Nick O’Grady: Yeah, that’s right, Philip. So it’s really a function that our planned EQT development really came on. We had some deferred production from Q1 that came back on Q2, plus our EQT wells for the year were completed as well as some other Marcellus wells and our Utica project came online in 2Q. So, that was as flush as will be. So that will — that really peaked out in Q2. So obviously, that’s over 100 million a day of our production, which will be in decline. Obviously, you’ll get the benefit of the other assets. And so you will have growth in the other basins, but that will really be the peak of the gas production for the year. So that is the drive. So that’s correct. So our Appalachian production tends to go in waves.

So, it tends to be, especially on our Marcellus asset where the development tends to be in the spring every year. And so there’ll be another wave of development next year around the spring. So you’ll have another search next spring, but we’re sort of done for the year.

Operator: Your next question comes from the line of Paul Diamond with Citi. Your line is open.

Paul Diamond : Good morning. Thanks for taking the time. Just a quick one on kind of timing cadence. The last few quarters have seen kind of a pull forward of activity? I know you talked about a possibility that, that could continue to occur. Look like literally this year potentially pulling some 2025 activity forward. I just wanted to know if you could talk about kind of if you see that as a more of a permanent compression or just a function of current market dynamics? Or I guess, how should we be thinking about that going forward?

Nick O’Grady: Yes. Paul, I mean, I think we’re a little gun shy. And so I think that’s kind of where our heads are right now. I think — I guess what’s the term once bitten twice shy. And so I think as we’ve kind of pointed people to the sort of kind of post the midpoint of our guidance, it’s with the assumption that we’ll see based on the AFE activity, we’ve seen year-to-date that we’ll continue to see robust AFE activity and the possibility of continued pull forwards. Now, those pull forwards don’t always account for additional accruals, but they can. And so the concept was that we would see potentially in the fourth quarter, a combination of both pull forward of TILs and potentially 2025 activity being pulled forward. And so that’s kind of where our heads are.

Now it’s not a given per se. And so that’s why the band is slightly wider. But we have seen that, and it will be price dependent. So obviously, if we were to see commodity prices take a nose dive, it’s unlikely that, that would happen. And that’s why we really do want to see why we keep that band there, but that’s correct. It could. But I do think if we see high 70s and low 80s, it is more likely to happen than not because that’s the trend we’ve been seeing for the last 18 months.

Operator: Your next question comes from the line of Noah Hungness with BofA Securities. Your line is open.

Noah Hungness: Good morning all. I just wanted to ask on the refrac opportunities that you’re seeing today and really what’s driving that increase there? And how you guys compare the refracs to maybe new drills in a similar place in the basin?

Nick O’Grady: Yes. I mean, I think it’s been notable. I think we view refracs as locational, right, which is that not all refracs are good. And it’s important to understand that, which is that they are significant in cost, right? They can be 60% or 70% of the cost of a new well. But we have seen a pickup, specifically in the Williston in the last few years. Historically, we have literally just budgeted in our workover budget. And as our analysts have been asking us why our workover budget kept going up, we realized that we had to start to break it out because it is productive capital. But I’ll let Jim talk a little bit more about it.

Jim Evans : Yes, I can jump in here. We’ve got the stats in front of us. I mean I think year-to-date, we’ve received roughly around 30 gross refrac proposals. And the bulk of that work is going to be done in the third and the fourth quarters. It’s also going to depend on whether or not it’s an offensive or a defensive frac, meaning a defensive frac is coupled alongside new drills. So they’re refracing legacy wells while they’re drilling the new drills. And then you’ve also got kind of the offensive refracs and that’s going to be effectively going into pretty much a fully developed legacy unit and then refracing those. That’s going to depend on the depletion as well as the completion methodology. And so it’s very intensive in terms of what our technical team is underwriting.

But I’d say that probably two-thirds of the refrac proposals that we’ve received in the Williston have been kind of through Grayson Mill and now, ultimately, Devon, and you’ve seen some of their commentary there. So I think we’re relatively encouraged and we continue to kind of tweak and refine things.

Operator: Your next question comes from the line of Noel Parks with Tuohy Brothers. Your line is open.

Noel Parks : Hi. Good morning. Just looking at the — this announcement you just had with Vital and taking additional position in the Permian. I’m just curious in the M&A landscape of what you’ve seen, the potential deals coming to you and so forth. Just wondering what your thoughts on sort of sort of prolific, but still gassier parts of the Delaware somewhat further south. Just wondering how much you’re seeing out there in the market and whether you’re — kind of what your appetite is in that part of the plan, all things being equal?

Nick O’Grady : Yes. I mean as you go south in the Delaware, the — it doesn’t mean it’s all bad, but the geology becomes very complex, right? You have a lot of faulting specifically in Reeves County. And as you get into bait’s a very challenging geology. So there are people who know how to do it. It’s operator by operator. And so it can be done. But I would say, it is definitely something you wouldn’t go with, as you would say, not with a hammer, but with a scalpel. And so I think it’s not something that’s out of the question. It’s just something that requires more of a fine-tune home. Certainly, it’s a different paradigm. But what I would tell you is that we’re focused on quality, but I would also tell you that inventory in general in the country is changing, and some people would tell you that they’re looking for the next wave of inventory, and that is something that we have to adapt in the world, which is that ultimately, we have to recognize in the United States that sticks are becoming more and more scarce.

And so this may be what is the new paradigm in a few years. And so will evolve as the market does.

Jim Evans : Dovetailing off of that, and I think it’s evidenced in terms of what we’ve seen in Williston with operators refining completion techniques and stepping out. And if we’re focused on rate of return, we need to continue to monitor the dynamics and the changes there. We’ve obviously looked in Southern Delaware before. And there’s have been a number of opportunities that haven’t necessarily fit the bill. But as operations change hands, using forage as an example, we’ve seen a 13% reduction in well costs, and we’ve seen early performance on underwritten type curve that have exceeded by roughly 20%, right? And so if we start rolling those types of changes into acreage that otherwise didn’t necessarily pass our hurdle rates, then maybe that changes in the future.

And so that’s why we’re continuing to do our look backs, both with our operating partners as well as the folks that were participating on a heads-up basis. And if those things continue to change, and we’ve got conviction in that, then that’s something that will honor.

Operator: Your next question is a follow-up from Charles Meade with Johnson Rice. Your line is open.

Charles Meade : Thanks for back in the queue there. Nick, I wanted to ask a question about the — on these co-purchase deals, the dynamics and the motivations of your partners. When I think about what they would look for or the advantages they get from partnering with you? I think about — well, first off, they can kind of get the size of the deal where they want it. But truthfully, if you’re taking a 20% cut, that’s not maybe that big a delta. I think that I don’t imagine that you’re bringing a lower cost of capital or like significantly low cost of capital to the deal. And I think that perhaps from the operator’s point of view, they’re using their LOE a bit by charging you some overhead. But what are the — what do you think — when you sit down with these guys, what is the…?

Nick O’Grady : They can’t charges us overhead.

Charles Meade : What do you bring to the table for them? Say again.

Nick O’Grady : They can’t charge us overhead. They do not, but…

Charles Meade : Cannot, okay.

Nick O’Grady : Yes. I mean you pay — we paid a typical — we pay LOE straight. It’s just — it’s an undivided interest. But the answer is you hit it the same thing, which is that if it’s cost of capital, it’s very simple, which is that if you’re a company and you are looking — I mean, I can’t answer the motivations for every company. So, I mean, you’re asking me to answer somebody else’s question, but what I would tell you is that we’re an oil and gas company, right? At the end of the day, we are certainly a financial owner in many ways, but we’re not a financial entity. We’re a permanent owner of the assets, right? We’re not turning it into a security. So our cost of capital in some ways is higher, right? But if you’re a private equity firm, your main goal is to own it for five years and then flip it, right, and you require a lot of maintenance.

And so your cost of capital might be lower than ours. But then at the end of the day, it’s heads or tails, I win, because I needed to be a security and then I need you to buy me out at the end, and I need you to manage it and do all these things and then turn it around. Whereas for us, we’re true oil and gas concern — so from the operator’s perspective, we’re a great “silent” partner” because we understand and we can underwrite alongside them. We have our own engineering team. We literally can sit down with them and we do our own underwriting, right? Number one, our technical team become a great sounding board, because they can sit there and say they know that we agree with them when we go through this process when we’re going to purchase these things, but — and so that we know we all agree.

But number two, for those partners, they can understand that when they’re going to size these transactions, they’re not stretching themselves financially, right? And — but if they take on more debt, or they take on another financial partner, they have to deal with that party at some point, whereas we own it forever, right? And they don’t have to worry about what we’re going to do with the other end or buying us out or if something goes wrong in the case of the security in which that person says they have to be paid or that a VPP where in a VPP, I’m not sure you’re aware, but if the volumes disappoint you have to give them more volumes, right? So no matter what happens, you pay the man, right? And so ultimately, we wind up being a much better partner where we take risk alongside with an undivided interest means we share in the benefits and if things go wrong.

Operator: Your next question is a follow-up from Phillips Johnston with Capital One. Your line is open.

Phillips Johnston : Hey, thanks for the follow-up. It’s early to talk 2025, I know. But just from a directional standpoint, it looks like consensus CapEx next year is around 975 [ph], which is pretty similar to this year. Just wondering if you guys would potentially envision a higher spend next year, considering your implied capital efficiency for this year’s program is helped by about 20 more net TILs than what you have plans for net spuds.

Nick O’Grady: Yes. Philips, it’s a little early, but I would just say this, like looking at consensus so far, we haven’t seen anything we really object to. But again, I don’t want to — it’s too early to truly opine on it. But so far, we haven’t seen anything that is terribly scared us.

Operator: This concludes the question-and-answer session. I’ll turn the call to Nick O’Grady for closing remarks.

Nick O’Grady: Thank you for joining us today. We appreciate your continued support and look forward to touching base with you in the coming weeks.

Operator: This concludes today’s conference call. We thank you for joining. You may now disconnect.