Northern Oil and Gas - Q2 2023

Transcript

Evelyn Infurna (VP of Investor Relations)

Thank you, operator. Good morning, welcome to NOG's second quarter 2023 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. Our Form 10-Q will be filed with the SEC within the next few days. I am 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 our recent accomplishments. Adam will give you an overview of our operations, followed by Chad, who'll review our second quarter financials and walk through our updated 2023 guidance. After our prepared remarks, the executive team will be available to answer any questions.

Before we go any further, though, 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 we have described in our earnings release as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligations to update those 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. Reconciliations of these measures to the closest GAAP measure can be found in our earnings release.

With that, I'll turn the call over to Nick.

Nick O'Grady (CEO)

Thank you, Evelyn. Welcome, and good morning, everyone, and thank you for your interest in our company. As usual, I'll get right to it with four key points. Number one, our investment philosophy is driving tangible results. Our second quarter adjusted EBITDA was up 16% year-over-year. Our quarterly cash flow from operations, excluding working cap, was up 11% year-over-year. Over this same period, our weighted average, fully diluted share count was up only 3%. Oil prices were down 32%, and natural gas prices were down 69%. Also, this quarter's results included the impact from our recent share offering, with no financial benefit from the acquisitions that it funded. Suffice it to say, we've grown materially on a per-share basis while prices were down materially.

The point I am driving here is that our company is focused on a fairly simple philosophy: finding ways to grow profits per share to investors over time and through cycle. We believe that is the path to driving sustainable share price outperformance. While oil and gas prices go through down periods that can and will affect our profits, it is our job to find ways to grow the business through such times. We are actively investing, hedging, and looking to drive consistent long-term growth to profits and cash returns. This has driven and will drive future dividend growth and share performance. Number two, our investment cycle is pivoting to harvest mode. As we entered 2023, we highlighted we would be spending approximately 60% of our capital in the first half of the year, even though the completion activity was somewhat back-end loaded.

Our DNC list today is materially more complete, meaning paid for, than typical. This means even as the number of wells turned online rises in the coming quarters, we have front-end loaded much of the spending, and we should see a marked increase to free cash flow in the back half of the year. Number three, growth. Our growth continues on a strong pace, turbocharged by the bolt-on acquisitions of Forge and Novo, which will come into play in the second half of 2023. As we previously communicated, Novo is expected to close on August 15th and will be financed with cash on hand and borrowings on our revolver. We anticipate an acceleration of free cash flow for the back half of 2023 and continuing on into 2024.

Importantly, as oil prices have improved in the third quarter at today's strip, we believe that NOG can fully repay our revolving credit facility by mid-2024, materially earlier than our internal expectations when we made the acquisitions. We have added hedges recently and completed our targets for Novo as oil prices have rallied, locking in higher levels than we underwrote. To put the acquisition and subsequent financing into perspective, by around this time next year, based on our projections, we could have a business producing 20%-30% greater amounts of cash flow than today, with materially less debt than we just reported. This is at a backwardated pricing strip, mind you.

This would imply, from a total return perspective, when including our dividend yield, we could deliver up to a 30%+ total return on our business, which compares favorably to the high-payout, low-growth strategies we've observed from some competitors, and quite favorably with the long-term returns of the stock market, which brings me to number fou. Capital allocation. Our goal is to provide our shareholders with the highest possible total return over the long term. We say this every quarter, but it's important to us, and we believe it bears repeating. We recently announced a 3% increase in our common stock dividend for the third quarter of 2023, our 10th straight increase. Our view at NOG is that our scale should help us build a shareholder return program that can grow over time.

As a result, we're instituting a policy of annual reviews of the dividend, with the potential for interim changes should we experience significant sustained commodity repricing, or if we execute on substantially accretive corporate actions. As always, we'll be mindful of risk and leverage, while also providing an attractive risk-adjusted total return. Our capital allocation is about maximizing potential returns, making our dollars go the farthest they can from a value creation perspective. The data overwhelmingly suggests NOG has thus far created more value and more long-term dividend growth by acquiring assets at a significant discount to what we already view as a discounted value for our stock, as you saw in the second quarter. This is Capital Allocation 101. There have been and will be times when these paradigms shift, allowing us to create more value by pouncing on undervalued securities.

We are continually evaluating all options and executing on what we believe to be the best path for the company and our shareholders. We're truly excited to have executed on two large-scale joint development projects in the second quarter, specifically Forge and Novo. These two acquisitions are indicative of striking while the iron is hot. On prior conference calls, we shared that the opportunity set for NOG was the largest we had been presented with. In both cases, Forge and Novo were attractive, and we're excited to be working with Novo and Earthstone to create more value. We believe NOG is very well positioned from an asset and balance sheet perspective for the remainder of 2023, as well as for the year ahead. Before I turn the call over to Adam, I did wanna bring a personal matter to our investors' attention.

As you may have seen, a 10b5-1 plan I entered into about a year ago got executed last week, and additionally, I've entered into a modest monthly 10b5-1 plan to sell some shares over the next year to address some personal needs. Over my 5.5 year tenure here with NOG, I had never sold a share of stock and had only been a net buyer with 15,000 shares purchased with my own personal funds. NOG is and will remain the vast majority of my net worth. I believe in the company, and by that fact, it should ensure to all of you that I am aligned with you all and highly motivated to deliver results and stock performance.

I pride myself on always being direct and honest with you, so I don't want anyone to think that me selling some shares means something about my views on the company's future or trajectory. Quite the contrary, our executive compensation incentive structures are driven by all the right things: corporate return on capital targets, making more money for our shareholders, and driving the stock price higher over time. A large proportion of our future compensation is directly achieved only through significant, absolute long-term upside in the stock, so it should be clear that we are as hungry and motivated as ever to find ways to drive share prices higher. I just don't want this to be confused with personal decisions I may make from time to time.

With that out of the way, thanks for taking the time to listen today. A special thanks to the entire NOG team from top to bottom. NOG is on an incredible upward path with a bright future ahead, driven by our unique investment-focused culture. I will close by reminding you, as I always do, that we are a company run by investors, for investors, and with that, I'll turn the call over to Adam.

Adam Dirlam (President)

Thanks, Nick. I'd like to start by reviewing our quarterly operations, and then we'll turn to our business development efforts in the M&A market. Second quarter operations were down the fairway as we continued to find ways to optimize our development programs, maintain capital efficiency, and enhance returns. Turning lines for the quarter were as expected, adding approximately 13.8 net wells to production, on par with first quarter's well additions. The Williston made up approximately two-thirds of the organic activity, driven by larger working interests with several of our top operators. We exited the quarter with over 9,000 producing wells, and we will continue to leverage our proprietary information to make well-informed capital allocation decisions.

Looking forward, we have been working with our operating partners, mainly Midland-Petro, in our Mascot project, to adjust development schedules, which should drive long-term returns and reduce both shut-in times and costs as we prosecute the program. This means that we will be deferring some of our completions into early 2024, that were originally scheduled to turn in line during the back half of 2023. The new plan, which contemplates drilling and completing an increased quantity of wells in a single batch, will set up a more capital-efficient 2024 as we incur a substantial portion of the development costs in 2023 and reduce future costs related to shutting in wells for offset fracs.... Even more encouraging are the well results and outperformance that we have been seeing, not only with our Mascot project, but across all of our active basins.

Despite some curtailments in production and deferments of completions in the Bakken related to lower commodity prices during the quarter, NOG saw record production levels in the Williston. We continue to actively manage our positions in North Dakota and Montana, resulting in some of the highest well productivity we have seen out of the basin to date. In the Marcellus, we continue to see strong well performance, with Q2 production exceeding our internal expectations by 6%. Our wells in process continued to build as we added 8.7 net wells quarter-over-quarter, which excludes the pending Novo transaction. We look to close Novo in the middle of August, we expect to add an additional 6.1 net wells to our in-process list.

The activity across our scaled position in the Permian has been accelerating, where 50% of NOG's activity now comes from, up from just 18% of our oil-weighted activity at the beginning of the year. This has driven our in-process list to all-time highs with an average working interest that is nearly 20% higher than that of our average working interest related to our producing wells. This means that we can do more regardless of rig levels and provides us a seat at the table with our operating partners, giving us additional transparency as we prosecute our business. Turning to well costs, we continue to have discussions with both our large and small operators regarding a cooling of inflationary pressures, which has been encouraging. Regardless of size, each has seen green shoots in reducing overall well costs.

Quarter over quarter, we saw average well costs down 6% on an absolute basis and down 9% normalized for lateral length. This was driven both from longer laterals and a stronger deceleration in inflation across the Williston. Notwithstanding a further material upward move in commodity prices, we would expect to see the benefits begin to translate as we move into 2024, but remain conservative in our estimates given the overall market volatility. During the quarter, we elected the 9.4 net wells, with about 2/3 of those weighted towards the Williston, 30% to the Permian, and the remainder to the Marcellus. Quality remains high as the consent rate held above 90%.

On the business development front, we alluded to the record backlog of M&A opportunities we were seeing on our Q1 call and executed on some of the highest quality opportunities that were in the market during the first half of the year. Our size and scale create a competitive advantage in the non-op space, where we now have a myriad of ways to allocate capital to M&A. Our ability to contribute meaningful capital alongside our operating partners has opened the door to an expanded set of opportunities, which we've now shown we can thoughtfully execute on. By partnering to co-buy an operated asset or buying down a minority interest from our operators, we build alignment, long data transparency, and can take an active role as operational decisions are made.

This is by no means a shift in our acquisition strategy as we continue to review non-operated packages, drilling ventures, and our ground game opportunities. Simply put, we have more opportunities to deploy capital than others, which gives us the ability to be more discerning. As we look at the assets that are in the market today, the current mix is robust, albeit limited in quality. That said, things can change quickly as we continue to source multiple off-market opportunities and others are brought to market. Regardless, we will remain disciplined in both our approach and underwriting as we navigate the rest of the year. While our major acquisitions were taking the headlines, we remained extremely busy with our ground game during the second quarter.

We closed on 13 transactions through various structures that will set up for the drilling of an additional 16.7 net wells through 2024. We're also able to add an additional 942 net acres. Four of those transactions during the quarter were through drilling partnerships in the Delaware, as operators continue to search for capital to fund their drilling projects and manage capital outlay. These capital management situations are not limited to smaller operators either, as three-quarters of the drilling partnerships signed during the quarter were with our large cap operators. All in all, we remain extremely busy on the business development front, with asset opportunities available to NOG remaining at all-time highs. Regardless of the opportunity set, our focus remains on asset quality with resilience in any commodity market and generating meaningful returns for our shareholders. With that, I'll turn it over to Chad.

Chad Allen (CFO)

Thanks, Adam. I'll start by reviewing second quarter results and provide additional color on the operating update we released on July 25th. Our Q2 average daily production topped the high end of our recently released estimates at 90,878 BOE per day, a 25% increase compared to Q2 of 2022. Oil volumes were up slightly over Q1 as we experienced better well performance across all basins, which was partially offset by deferments in the Williston as a result of the volatile commodity price backdrop during the quarter. Our adjusted EBITDA was $315.5 million in Q2, up 16% over the same period last year, and our second quarter free cash flow was $47.6 million, despite continued elevated levels of organic and inorganic investment, TIL deferrals, and commodity price volatility.

Adjusted EPS was $1.49 per share. Oil realizations continue to be better than internally expected, as Q2 differentials came in at $2.65 per barrel due to continued strong in-basin pricing and having more barrels weighted towards the Permian, which are typically priced tighter. NGL prices weakened as we moved throughout the quarter, and we are currently seeing realizations more in line with our stated guidance. As expected, LOE came in at $10.20 per BOE as a result of our firm transport charge that occurs in Q2 of every year from our Marcellus properties. We expect the firm transport program will expire in 2025 based on current estimates. Budgeted CapEx cadence is on track with our expectations.

We have incurred $445 million year to date, or roughly 60% of our initial total budget, and we have updated guidance to reflect development plan changes and deferrals discussed earlier, as well as incremental CapEx for Forge and Novo. For the year, we anticipate budgeted CapEx to be in the range of $764 million-$800 million. As we previously announced, we anticipate CapEx cadence for the second half of the year to be equally weighted in the third and fourth quarters. The balance sheet was further enhanced in the quarter, reflecting an active M&A season, with a $500 million senior notes offering to term out a portion of our revolver, followed by a $225 million equity offering in between announcing Forge and Novo acquisitions.

Leverage at the end of the quarter was 1.34 times net debt to annualized second quarter EBITDA. At the end of the quarter, we had zero borrowings on our revolver, with ample liquidity of over $1 billion to support our business. We will finance Novo with borrowings on our revolver, so we are likely to see our leverage ratio tick up again in the third quarter. That being said, we expect to return to our stated leverage targets in the next 12 months ahead of our initial forecast. With the contribution of Forge and Novo, as well as the current strip, we expect the revolver to be undrawn by the start of the third quarter of 2024 as we organically delever.

As we announced yesterday, the elected commitment amount and the borrowing base will be upsized on our revolving credit facility to $1.25 billion and $1.8 billion, respectively, once we close the Novo acquisition. Turning to our revised annual guidance, we have adjusted our 2023 production guidance to a range of 96,000-100,000 BOE per day, and are anticipating production for the third quarter in the range of 99,000-103,000 BOE per day, which contemplates a mid-August closing for Novo. We have tightened expectations for our oil cut to a range of 62%-63%, reflecting year-to-date pricing and adjusting for recent M&A, particularly Novo.

Our TIL estimates for 2023 were reset to a range of 75-78 net wells, reflecting changes to the Mascot drilling plan and previously discussed deferrals experienced in the second quarter. We made modest guidance revisions to LOE, G&A, and realizations, mostly related to anticipated contribution and the lower cost structure associated with our increased exposure to the Permian. We have tightened the range for LOE, keeping the low end at $9.35, and tightened the high end to $9.55 for anticipated production expenses associated with Forge and Novo. On differentials, we're upping our gas realizations to 85%-95% and have tightened oil differentials to a range of $3.25-$4.25, reflecting better pricing year to date.

The increased gas realizations are tied to processing costs embedded within our LOE. Our expected cash and non-cash G&A ranges were tightened by bringing down the high end of the respective ranges by $0.05 per BOE. In an effort to provide better transparency to our adjusted EPS calculation, we introduced guidance on our DD&A rate per BOE for 2023 in the range of $13.00-$13.80. In the second quarter, DD&A was $12.87, which reflects the addition of Forge to our asset base with no corresponding production volumes. The higher rate for the year reflects the addition of Forge and Novo to our asset base.

Jim Evans (CTO)

... Though we gave a fairly detailed operations and guidance update, we did not discuss taxes. We are frequently asked about the timing and the expected amount. We continue to expect to be a cash taxpayer in 2024. Our preliminary estimates as of today is the expectation of a $10 million-$15 million 2024 tax outlay, with a more fulsome tax outlay in the following years. Changes in oil and gas prices could have a substantive impact on this estimate. We'll keep you informed as time goes on. With that, I'll turn the call back over to the operator for Q&A.

Operator (participant)

Thank you. We'll now be conducting a question-and-answer session. If you'd like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you'd like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star key. One moment please, while we poll for questions. Thank you. Our first question is from Scott Hanold with RBC. Please proceed with your question.

Scott Hanold (Managing Director, Senior Energy Analyst)

Yeah, thanks. Hey, I was wondering if you could discuss, you know, how, how you think about, like, the M&A landscape going forward. I know, Nick, you had said you strike when the iron's hot, but I guess from, from Adam's commentary, it looks like the quality has made it cooling a little bit. As you kind of think about that, you know, relative to, you know, that free cash flow being deployed to debt reduction and/or buybacks, can you, can you just give us your view of the landscape of M&A and, and, you know, kind of managing the balance sheet over the next year?

Nick O'Grady (CEO)

Morning, Scott. Yeah, I mean, I think, you know, I think I also, in my prepared comments, talked a lot about capital allocation, right? I mean, I think we wanna do what's right for the business, and we weigh all these decisions against each other. I, I would agree that, you know, as we pointed out, I think the large scale M&A landscape for the moment, you know, looks, looks less exciting to us. Adam also pointed out that, you know, that can change over time, and we get phone calls every day from things that may or may not be on the market, and we'll take those in stride.

I think that being said, you know, I think when we look at this and, and, and these dollars are, are fighting, and, I mean, I think the, the adage I would give you is, if you have a car loan at 2% and you're earning 5% in your savings account, it makes no sense to pay off that loan, even if you wanna have no debt. We think about it the same way, which is that the extent we're, we're focused on improving returns to stockholders and allocating capital in stride. To that point, we have allocated obviously to M&A because it's provided a higher return to our stockholders than almost anything else. That does change, though, right? That paradigm can shift.

For the moment, I don't think we see a lot of compelling large-scale M&A opportunities. The default case in which is, is to, to repay debt, and then ultimately, as we reach our targets, you know, you start to pivot. I mean, I think we have a slide, I think it's slide 13 in our presentation that should say it pretty succinctly. I think we're willing to take leverage to about 1.5 turns for the right opportunities, and I think when we really get below 1x, it tends to lead to accelerated shareholder returns, right? I think that in and of itself should kind of give you the governors of how we're gonna look at this going forward.

Scott Hanold (Managing Director, Senior Energy Analyst)

Yeah, that, that's, that's pretty clear. Thanks for that. You know, my follow-up, you know, just if you can give me just a view of, you know, what you're seeing out there from operators in, in the Bakken and, and Permian. I think there may have been some, you know, modest deferrals in, in terms of, you know, your operators', you know, completions in, in, in the Bakken. Are you still seeing that? You know, how, how is the Permian setting up in terms of, like, just the, the normal non-op opportunities outside of Mascot?

Jim Evans (CTO)

Hey, Scott. I, I think the Bakken, you know, some of the deferrals that we alluded to in our pre-release is really representative of maybe one or two operators where, you know, we've got some outsized working interests, you know, maybe more sensitive from a commodity pricing standpoint. We're having those conversations with the operators right now. Where we stand today, you know, those commodity thresholds are, are being met, so, you know, as far as, you know, anticipated completions and whatnot, we've got that couched, call it Q4 timing, but that's also gonna be dependent on logistics and, and everything else. So, you know, that could get pulled, it could potentially get pushed depending on kind of that volatility. Then, you know, as far as, as Texas and New Mexico goes, it's, it's steady as it goes.

Obviously, we had some commentary around the Mascot Project that's obviously very specific, just given the stacked pay and, and the overall kind of co-completion activities that, that we're running aground with, you know, Midland-Petro and, and that group. Everything else is generally steady as it goes. Then, you know, I think you might have alluded to the ground game opportunities. You know, we continue to see, you know, those coming in the door every single day. And, you know, the size and, and the scope of what those look like are all very different, and I think that gives us the ability to, to get picky, in terms of where we're gonna deploy our capital dollars.

Scott Hanold (Managing Director, Senior Energy Analyst)

Appreciate the color. Thanks.

Evelyn Infurna (VP of Investor Relations)

Thank you. Our next question is from John Freeman with Raymond James. Please proceed with your question.

John Freeman (Managing Director)

Yeah. Good morning, guys.

Nick O'Grady (CEO)

Hey, John.

John Freeman (Managing Director)

First question. You all mentioned on the AFEs, how we went from, you know, the $9.6 million in the first quarter down to $9 million in the second quarter, and we're sort of seeing some deflation starting to kick in. Is there any color y'all can give on just where we stand on AFEs, maybe on a leading-edge basis?

Nick O'Grady (CEO)

Yeah, I mean, I, I think I would just caveat all this. I mean, I think that our view, and I think it's one that's been proven by the test of time, is that, you know, oil prices and service costs will, will move in sync with each other, right? From a margin perspective. You've had a kind of unique environment over the last year where you've seen, oil prices go down pretty materially, natural gas prices go down materially, and activity has been coming down, but costs were taking some time to come down to meet that. On the leading edge, you're starting to see that. That's also juxtaposed against a, a period where we've started to see oil prices rally.

I think as we look forward, I just I wanna caveat it and say that I the last shoot of fall, really, where you're gonna see where you would see a material change to savings is gonna be completions. The completion cost is only going to materially come down to the extent that the rig count ultimately stays down. If prices rise, I would anticipate you're gonna see the rig count come up modestly. Thus, with that, I think your chances of seeing material savings from here are gonna be reduced. I would say, as I've said to a lot of our investors, you know, you don't need to look really any farther than to the price of oil to think ultimately where the direction of service costs are gonna go.

More specifically I'll let Jim or Adam talk specifically to any leading edge changes versus that $9 million.

Jim Evans (CTO)

Yeah, I think anecdotally, you know, the conversations that we've had with our operators, we've generally seen it in more of the tangible casing, for example. You know, even some of our smaller operators have seen, you know, a reduction anywhere from, call it, 20%-40%, you know, based on some of the conversations that we were having earlier in the year. You know, I think some of that's got a little bit of room to give. Some of that also has to do with logistics and some of the issues that we're running into from a sourcing standpoint last year.

Some of the other, you know, larger operators that we've been talking to, have been, you know, laying down rigs, and some of that is strategic, and, you know, going back to the service providers in order to kind of cut better deals. Drilling rates seem to be coming down marginally as well. To Nick's point, I think, you know, we're gonna stay relatively conservative, especially with the volatility that we're seeing in the commodity market.

John Freeman (Managing Director)

Great. Then, just my other question on the leverage slide, that you referenced, Nick, that slide 13.

Jim Evans (CTO)

Yeah.

John Freeman (Managing Director)

- where you basically show, of where y'all sort of view leverage in that zero to 1.5x range, and, and how you talk about kind of flexing leverage in the near term, if needed, for certain growth opportunities, which obviously y'all, y'all have done in spades here recently with, with a, a number of big transactions. You know, you, in that slide, talks about on the lower end, it's kind of harvest mode towards a zero leverage. Upper end is invest. And, and, you know, Nick, you used the word harvest in your, your prepared remarks. So I guess I have kind of two parts. It's A, I guess, should we assume that that means you start targeting the, the lower end, just given what you said about large scale MA, et cetera, your comments about harvest?

Then also, what's not on that slide is, is how does just the commodity, you know, environment kind of overlay on this chart? If you're in a, you know, 90-dollar world, I assume that your leverage, what you view as acceptable leverage, is probably different than if you're in a 60-dollar world.

Nick O'Grady (CEO)

Yeah. I mean, I would say that generally speaking, we don't we're not running, you know, our leverage kind of this the one thing that this doesn't really point out to, which it probably should, is that we're not thinking we're thinking about this on a normalized ratio, right? We're not running, you know, spot $80 through and making the assumption if we're 1.5 times or 1 time levered at $80 forever, right? We're, we're, we're using a, a discounted price to that. We're kind of using a mid-cycle price in our mind.

I mean, I think that to answer your question is, like, the, you know, the one thing I, I would point out to, you know, and it, it's specifically like, I think when you think about the uses of cash flow as you kind of reach those, those, those targets is, is obviously, you know, share repurchases, right? Share repurchases to us, it's not to suggest, because we haven't done them recently, that we don't think our equity is inexpensive at all, right? I think that that's not the case. The reality has been that we've been able to buy assets at a material discount to, like I said in my call, an already discounted stock price value.

going back to my car loan analogy, whether or not that, you're just, you're just getting a better return for the investors by doing so. Obviously, to the extent that the environment winds up being less so, that's an obvious default. We can't afford it, but I think you need to have the risk metrics and kind of at a, both a cyclical and oil price perspective, as well as an aggregate leverage perspective, to a point where you really want to do that. Obviously, that we have to have a view internally that that is a good use of that capital, because there is also the default, always, of just piling cash and waiting for a better day. I don't think we're afraid to do that either.

I don't know if that answers it specifically, John, but stop me if I didn't get there.

John Freeman (Managing Director)

It, it does. No, I appreciate it. Thanks a lot, Nick.

Operator (participant)

In the interest of time, we ask that participants limit themselves to one question and one follow-up. Our next question is from Neal Dingmann with Truist Securities. Please proceed with your question.

Neal Dingmann (Managing Director, Energy Research)

Morning, guys. My question's on the, the second half and possibly 2024 activity. It sounds like, I forget which slide this is on, but it sounds like based on your prepared remarks and looking at the slide, you all have a number of-- a material number of wells in progress, and so you have confidence that your TILs will ramp through the remainder of 2024. I'm just wondering, you know, it sounds like this is the case, but can you give us an idea of, you know, just the degree of that and which areas will see the most activity?

Jim Evans (CTO)

Yeah. Hey, Neal. I think as far as kind of the areas that, that you reference, it, you know, I think it's gonna be largely split kind of 50/50. It, you know, maybe that gets pushed and pulled, and your goalposts are kind of 40/60, depending on what's going on in the Permian versus the Williston. And, you know, maybe some of the larger working interest pads or, or units that we have. I guess, drilling down in, in that regard, I think you'll, you'll see some activity on the Texas-Delaware side, as well as the Midland Basin.

We've also got, you know, the majority of our, you know, Delaware wells in process are, are weighted towards, you know, Eddy and Lee County, and so to the extent that we see any sort of acceleration there, you could certainly see some, some additional exposure there. From a Bakken standpoint, it's the big four counties, McKenzie, Mountrail, Dunn, and Williams, and that hasn't changed for, for years.

Neal Dingmann (Managing Director, Energy Research)

Awesome. Just to follow up, maybe, Adam, for you or Nick, I haven't asked you guys this in a while, just wondering. It seems like now on M&A, you, you know, you guys continue now really just a, a number of different types of deals versus, you know, early years when you just take sort of a minimal interest in a well. I'm just wondering, going forward now, do you all have a preferred structure on M&A, or is it just a matter of what type of deal you all receive? Thanks a lot.

Nick O'Grady (CEO)

All, all of the above, Neal. I think we're economic creatures. I think we want to extract the best. I know it sounds corny, but risk-adjusted return, right? There's the raw return that obviously any engineering deck is gonna run through, but then you have to adjust that for the specific risks to the assets. Sometimes it requires governance. I think Adam talked about this in his comments, and I think this is something that I would wanna, you know, reiterate to our investors, which is that just because, you know, we've done several partnerships and sort of buy down structures of late, doesn't mean that we're not still very active in our traditional non-op markets. In fact, I think that I wouldn't say there's a preference, one way or the other.

I'd say that the key things are that our capabilities are a lot larger than they were, and that might be why, from a happenstance perspective, that you've seen that, as well as the ebbs and flows of the quality of assets that come to market. I mean, we've seen several, you know, traditional non-operated assets come to market this year, and they just happen to be pretty poor quality, and we've passed on them. I think that it's gonna come, but that's not gonna be the case every day. I don't think there's a preferred structure. I think we adjust, our return thresholds and, you know, needs for governance or, or other things, depending on the concentration and the specific risks to the assets. I don't know.

Jim Evans (CTO)

Yeah, it's building on that. It, you know, it's definitely gonna be asset specific, especially when you get into, you know, the drilling partnerships and, and some of the co-buying stuff, right? So you kinda need to understand, you know, what the runway is of, and on a prospective basis, right? You can buy an asset in time, but then what kind of governors do you have in place in order to maintain that alignment? So that's gonna boil down to the social issues and, and how those discussions are going with the particular operator. It, you know, we've had operators come to us and, and, you know, propose, you know, buying an asset, and it's something where, you know, they're gonna be renting the asset for a period of time. So is that the right partner for us?

Maybe, maybe not, depending on, you know, what we can put in those joint operating agreements and, and what everybody can kinda live with. It's as much, you know, the social issues when we're talking about some of these partner, partnerships as, as it is the assets themselves.

Operator (participant)

Thank you. Our next question is from Charles Meade with Johnson Rice. Please proceed with your question.

Charles Meade (Research Analyst)

Good morning, Nick, Adam, and Chad, and to the whole NOG crew there. I think I have just one question, and it's on slide 10. First off, I wanna say, thank you for giving us this detail about, you know, about how the, you know, the actuals are comparing to your, your acquisition case. My question is this, how much... It, it seems to me that most of the delta between your acquisition case and this new, and the new, I guess, completion plan, that it seems like we've seen some of it in Q2, but most of it is still in front of us.

And if that's the case, is there anything that we can is there anything that, that the way that, you know, at the end of Q2, your actuals were ahead of the plan, does that suggest that, we're gonna see that, we're gonna see that gap grow in the back half of '23?

Nick O'Grady (CEO)

Certainly to, I mean, to the extent that it continues at the pace it has, of course. I mean, I think we take it, you know, 1 well at a time, Charles. I think we've, we've been pretty conservative, and, well, when I say we, I'll give Jim 100% credit and his team. So well, maybe I'll take credit on top of that. But, but seriously, I think the answer is that we try really hard to take a conservative tact on performance, you know, and, and, and timing for that matter, because timing does move all along, moves all around, all the time.

I, I do think that we've been really encouraged, really, through every producing period on these assets of how the wells have performed, even when there have been issues here and there, like there always are on these things. Really, I think, you know, the, the, the old adage is, you know, in real estate is location, location, location, and I think it's the same thing when it-- as it pertains to this asset, which is, this is just a, you know, this is a Ferrari, asset sitting right in the, the heart of Midland County, you know, no-- virtually no vertical penetrations on the properties. It is just incredible rock, so the well performance, are we surprised? Not really.

Also it's a large project, and there's a lot of logistical things going on, as you've noticed, and that's why we've had to move some stuff around and learn as we go and try to find better ways to, to improve the returns. Overall, from a well performance perspective, I certainly think, and I'll, I'll let Jim add anything he wants, but I certainly think that we're optimistic that we can see continued performance on the assets.

Adam Dirlam (President)

Yeah, I would just add, you know, the original expectation was that there was going to be another batch of wells getting completed in the third quarter, coming online kind of towards the end of the third quarter. What you see on that graph there, where the daily production is, is ramping, that's kind of the last batch of wells for this year. Even though it's exceeding, you know, the original forecast, you kind of expect that to, to switch as you get to kind of towards Q3, Q4, where we originally thought there would be another batch of wells that would ramp production further.

We'll continue to see the production kind of decline, until we get to the end of 2023, and then that next big batch of wells will start coming online in Q1 and Q2 of next year, which will drive the, the capital efficiency going into 2024.

Jim Evans (CTO)

That's helpful color, Jim. Thanks, Nick.

Operator (participant)

Thank you. Our next question is from Donovan Schafer with Northland Capital Markets. Please proceed with your question.

Donovan Schafer (Managing Director, Senior Analyst)

Hey, guys. Thanks for taking the questions. First, I want to ask, talking about, you know, well costs. I know for operators, they have the real direct relationship with the service providers, and a lot of times they negotiate that pricing ahead of time before you guys would even get the AFEs from them. I am curious, you know, being that you guys are, are really kind of charting the path on the non-operator business model and, you know, and, and reaching such large scale, and you, you've talked a lot about scale advantages that you get.

I'm curious if, you know, as things stand today, or, or maybe it's the case where this is a potential thing in the future, could there be an evolution here, or, or, again, maybe you're already here, where you're able to get better pricing with service providers as, as far as what ends up flowing through the AFE? You know, you can imagine a case where maybe an operator is dealing directly with the service providers, but if you add up, you know, your smaller minority interests, across all of your, your wells and your, your huge footprint, you could have a service provider that actually has more exposure to you in aggregate than they do to a single specific operator.

I'm just wondering, are you ever able to bring that to bear and get involved in that kind of level of conversation in negotiating pricing with the service providers? If maybe not yet, is that something you would ever aspire to? Is there a way where that ever makes sense in kind of evolving the business model?

Nick O'Grady (CEO)

I mean, Donovan, an interesting concept. The answer, the short answer is no. I mean, I think the one thing I want to tell you is that the AFE is not necessarily like the, you know, if, if Exxon is drilling a well for us, for example, the AFE is just an estimate, right? It's not always tied directly to their latest service contract or cost, which is why oftentimes, you know, we can take the AFE at face value with the assumption that maybe in today's environment, that we'll see savings on the back end, or in a period like last year, where we might have a different assumption of where that well is ultimately going to cost versus the AFE. It is really an estimate, and these...

You know, they try to have contingency pieces in them and all those things, but they're not necessarily always leading edge. Just like, you know, we didn't really see in the first quarter that we-- you know, a big change to those AFE costs, but there was an assumption that perhaps while those wells were being completed, they would come in under budget effectively. As to whether we could aggregate our interests and go tell the service providers to do something, the answer is no. I will tell you, where we're significant non-operators, oftentimes our credit profile is used to help the operating groups get a better term, just because obviously we're a credit-worthy counterparty, we're a rated entity and stuff like that.

In that respect, we have kind of flexed our muscle at times, especially with some of our smaller groups. I don't know if we could sit there and say, "Hey, we own 10% interest across all your wells," and go to Nabors and tell them to lower the rig rates. I don't know if we're there yet.

Jim Evans (CTO)

No, I mean, I think the more realistic concept has to do with kind of the drilling partnerships that we have in place, and it's all going to be, again, you know, situational specific. You know, if we put together a, you know, drilling program with an operator and kind of have those guardrails as to how many wells are going to be drilled and those types of things, a lot of times what we'll build into those contracts are covenants for cooperation with the service company. So the operator is obviously taking the lead on that. When we're getting into water and takeaway and other midstream contracts, they've got, you know, a covenant with us that they need to provide those contracts to us. We'll provide our input, compare that to our underwriting, and, you know, move things along accordingly.

Donovan Schafer (Managing Director, Senior Analyst)

Okay, and just to be clear on that, are there some cases where you talk about the, the benefit of your credit kind of being brought into the picture? Are there some cases where it's sort of a joint and sever, you know, what are they called? Joint and severed or several liability so that, you know, that gives added weight to your credit, because under certain contracts or something, if the operator were to, for whatever reason, you know, worst case scenario, default, then you guys, you know, provide some of that support? Or, or is it pretty much always like a joint and separate liability, where your, your, the, the value of your credit goes just as far as your, your minority interest?

Jim Evans (CTO)

yeah, everything is several...

Donovan Schafer (Managing Director, Senior Analyst)

Okay.

Jim Evans (CTO)

None of these operates like joint development agreements or anything like that, are two joint ventures. Everything is-

Donovan Schafer (Managing Director, Senior Analyst)

Got it. Got it.

Jim Evans (CTO)

Several.

Donovan Schafer (Managing Director, Senior Analyst)

Okay.

Jim Evans (CTO)

So it-

Donovan Schafer (Managing Director, Senior Analyst)

And then my-

Nick O'Grady (CEO)

Well, hang on. If the XYZ operator undergoes a contract, we're not liable if they default.

Jim Evans (CTO)

That, that's right.

Nick O'Grady (CEO)

Right.

Donovan Schafer (Managing Director, Senior Analyst)

Sure.

Jim Evans (CTO)

But as a joint-

Donovan Schafer (Managing Director, Senior Analyst)

Yeah

Jim Evans (CTO)

-working interest owner and who's gonna be paying, you know, a sizable chunk of the joint interest billings, you know, having that kind of qualitative information is something that helps, you know, facilitate the process.

Donovan Schafer (Managing Director, Senior Analyst)

Sure. Okay. Then as a follow-up, with the Marcellus, you know, it looks like you guys had strong production there, that, Adam, I think you talked about. I'm curious, with the Mountain Valley Pipeline approval happening with the debt ceiling, you know, that happened at the end of May. I know there's been some hold ups with, like, the Fourth Circuit Court, but it looks like just yesterday, the U.S. Supreme Court, you know, this stuff gets all contentious, and so the Fourth Circuit Court tried to, you know, put a temporary hold on things. U.S. Supreme Court, I guess, yesterday said, "Nope, you can't even do a temporary hold. We're gonna give these guys the benefit of the doubt and let them proceed with everything." It seems like the weight of the courts and everything is...

You know, Congress, at this point, is really getting thrown behind getting the Mountain Valley Pipeline done, to service the Appalachian Basin. I'm just curious if that's, if any of these news events, if you have any color or commentary or thoughts related to that and your interest, current interest and, you know, potentially prospective interest in the Marcellus?

Nick O'Grady (CEO)

Not really, Donovan. I mean, I think that the, you know, look, I think you asked something similar last quarter. To the extent that it has a long-term improvement for basis differential, it's awesome. We'll probably see, you know, more development on our lands. We don't really buy things in anticipation of events like this. Obviously, that it would have some improvement on, on the basin as a whole.

Donovan Schafer (Managing Director, Senior Analyst)

Mm

Nick O'Grady (CEO)

optimistic more now than I have been in the past, that maybe we can actually get infrastructure built without, you know, kowtowing to special interests in this country, but that's a longer conversation.

Jim Evans (CTO)

Yeah.

Donovan Schafer (Managing Director, Senior Analyst)

It just takes Congress, it just takes Congress and the Supreme Court.

Jim Evans (CTO)

We went through a similar situation with the Dakota Access Pipeline, right? I mean, it was all fits and starts, and so I don't think we're gonna be planning on anything. To Nick's point, obviously optimistic, but we're not making any business decisions around it.

Donovan Schafer (Managing Director, Senior Analyst)

Okay. All right. Thank you, guys. Appreciate it.

Nick O'Grady (CEO)

Yep.

Donovan Schafer (Managing Director, Senior Analyst)

All right.

Operator (participant)

Thank you. There are no further questions at this time. I'd like to pass the floor back over to Mr. O'Grady for any closing remarks.

Nick O'Grady (CEO)

Thank you all for your interest in our company and listening today. We'll see you on the next quarter.

Operator (participant)

This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.