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.

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.

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…

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…

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…

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

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?

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?

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.

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.

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?

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.

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.

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

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?

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.

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

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.

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.

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

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?

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

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.

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.

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

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.

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.

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

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?

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.

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

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?

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.

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

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?

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.

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.

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

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?

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.

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.

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

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...?

They can't charges us overhead.

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

They can't charge us overhead. They do not, but...

Cannot, okay.

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.

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

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.

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.

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

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

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