Greetings, and welcome to the Northern Oil and Gas Second Quarter 2023 Conference Call. Please note that this conference is being recorded. It is now my pleasure to introduce your host, Evelyn Infurna, Vice President of Investor Relations. Thank you, Evelyn. You may begin.

Thank you, operator. Good morning, and 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'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 our recent accomplishments, then 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 obligation 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.

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 capital, 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 for investors over time and through the 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 in 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 drilling and completion list today is materially more complete and 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 in free cash flow in the back half of the year. Number three, growth. Our growth continues at 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 15 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% to 30% greater amounts of cash flow than today with materially less debt than we just reported. And 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-plus percent 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 four, 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 tenth 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 But 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 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 want to bring a personal matter to our investors' attention. As you may have seen, the 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'm 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. So with that out of the way, thanks for taking the time to listen today and 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.

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 continue to find ways to optimize our development programs, maintain capital efficiency and enhance returns. Turned 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 interest 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, namely Midland-Petro and our Mascot project to adjust development schedules, which should drive long-term returns and reduce both shutting 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 '23 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 continue to build as we added 8.7 net wells quarter-over-quarter, which excludes the pending Novo transaction. As 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 two-thirds 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 nonoperated 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 in the 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, and 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 the 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.

Thanks, Adam. I'll start by reviewing second quarter results and provide additional color on the operating update we released on July 25. 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. Natural gas realizations were 137% of benchmark prices for the second quarter. However, 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 to $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 1.34x 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 and as we organically delever. As we announced yesterday, the elective 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 to 100,000 BOE per day and are anticipating production for the third quarter in the range of 99,000 to 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% to 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 to 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 tighten 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% to 95% and have tightened oil differentials to a range of $3.25 to $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 noncash 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 to $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. So we gave a fairly detailed operations and guidance update; we did not discuss taxes, and we are frequently asked about the timing of the expected amount. We continue to expect to be a cash taxpayer in 2024 and our preliminary estimates as of today is the expectation of a $10 million to $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. So we'll keep you informed as time goes on. With that, I'll turn the call back over to the operator for Q&A.

Our first question is from Scott Hanold with RBC.

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

Scott, I mean, I think I also in my prepared comments talked a lot about capital allocation, right? I mean I think we want to do what's right for the business, and we weigh all these decisions against each other. I would agree that as we pointed out, I think the large-scale M&A landscape for the moment looks less exciting to us. But Adam also pointed out that, that can change over time, and we get phone calls every day from things that may or may not be on the market. We'll take those in stride. I think that being said, I think when we look at this and these dollars are fighting, and I mean, I think the outage 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 want to have no debt. And so we think about it the same way, which is that the extent we're focused on improving returns to stockholders and allocating capital in stride. And so 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. And so for the moment, I don't think we see a lot of compelling large-scale M&A opportunities and the default case in which is to repay debt and then ultimately, as we reach our targets, you start to pivot. I mean I think we have a slide, I think it's Slide 13 in our presentation that you should say 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? And I think that, that in and of itself should kind of give you the governors of how we're going to look at this going forward.

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

Scott, I believe the deferrals we mentioned in our pre-release regarding the Bakken reflect the situation of perhaps one or two operators where we hold significant working interests and are more impacted by commodity pricing. We are currently in discussions with these operators about the current status. The necessary commodity thresholds are being met, so we anticipate completions in the fourth quarter, although this will depend on logistics and other factors that could potentially alter the timeline. As for Texas and New Mexico, things are generally steady. We have provided some insights on the Mascot project, which is quite specific due to the stacked pay and the core completion activities we’re handling with Midland Petro and their team, but overall, operations remain stable. Additionally, regarding the game opportunities, we continue to receive various prospects daily, each differing in size and scope, allowing us to be selective in how we allocate our capital.

Our next question is from John Freeman with Raymond James.

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

I want to clarify that our perspective, which has been validated over time, is that oil prices and service costs tend to move together from a margin standpoint. Over the past year, we've experienced a unique situation where oil and natural gas prices have significantly decreased, leading to reduced activity, while the costs have been slower to adapt. As oil prices have begun to recover, I want to emphasize that any significant reduction in completion costs will largely depend on whether the rig count remains low. If prices increase, I expect the rig count to increase modestly, which would likely diminish the potential for substantial savings. Therefore, as I have advised our investors, the direction of service costs can largely be anticipated by monitoring oil prices. For details on any leading-edge changes related to the $9 million figure, I will turn it over to Jim or Adam.

Yes. And I think antidotally, the conversations that we've had with our operators, we've generally seen it in more of the tangible casing, for example, even some of our smaller operators have seen reduction anywhere from, call it, 20% to 40% based on some of the conversations that we were having earlier in the year. And so 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 larger operators that we've been talking to have been laying down rigs, and some of that is strategic and going back to the service providers in order to kind of cut better deals, drilling rates seem to be coming down marginally as well. But to next point, I think we're going to stay relatively conservative, especially with the volatility that we're seeing in the commodity market.

Great. I have another question regarding the leverage slide that you mentioned, specifically Slide 13, which outlines your perspective on leverage in the range of 0 to 1.5x. You talked about the possibility of adjusting leverage in the near term to capitalize on certain growth opportunities, which you've certainly done recently with several large transactions. The slide indicates that at the lower end, you are in harvest mode near zero leverage, while the upper end is for investment. Nick, you also used the term harvest in your prepared remarks. Therefore, I have two questions: first, should we interpret this as you targeting the lower end due to your comments on significant M&A activities and the concept of harvest? Second, what's not included in that slide is how the commodity environment influences this chart. If we were to operate in a $90 per barrel scenario, I would assume your view of acceptable leverage would differ from that in a $60 environment.

Yes. Generally speaking, we are not managing our leverage in a traditional way. One thing that this may not clearly indicate is that we are considering this with a normalized ratio in mind. We are not assuming we will stay at a $80 price point forever if we are at a 1.5x or 1x leverage. Instead, we are working with a discounted price and thinking about a mid-cycle price. To directly answer your question, one important point to note is that when we consider the uses of cash flow as we reach our targets, share repurchases are obviously a priority. Our lack of recent share repurchases does not mean we believe our equity is not reasonably priced. In fact, we've been purchasing assets at a significant discount, similar to an already discounted stock price. Referring back to my car loan analogy, we think that providing better returns for investors is important. However, if the environment changes, we will have to assess the risk metrics, cyclical oil prices, and overall leverage before making decisions. We must ensure that we believe it is a wise use of capital since there is the option of holding cash and waiting for more favorable conditions. I hope that addresses your question, John, but I’m not entirely sure if I covered everything.

Our next question is from Neal Dingmann with Truist Securities.

My question is about the activity in the second half of this year and possibly in 2024. It seems, from your prepared remarks and a particular slide, that you have a significant number of wells in progress and are confident that your TILs will increase throughout 2024. Can you provide more details on the extent of this and indicate which areas will experience the most activity?

Neil, I think as far as kind of the areas that you referenced, I think it's going to be largely split kind of 50-50. Maybe that gets pushed and fold in your goalposts are kind of 40-60, depending on what's going on in the Permian versus the Williston and maybe some of the larger working interest pads or units that we have, I guess, drilling down in that regard. I think you'll see some activity on the Texas, Delaware side as well as the Midland Basin. We've also got the majority of our Delaware wells in process are weighted towards Eddy and Lea County. And so to the extent that we see any sort of acceleration there, you could certainly see some additional exposure there. From the Bakken standpoint, it's the big four counties: McKenzie, Mountrail, Dunn, and Williams, and that hasn't changed for years.

Awesome. And then just a follow-up, maybe for you or Nick, I ask you guys this in a while. I just wondered, it seems like now on M&A, you guys continue to now really just a number of different types of deals versus early years when you just take sort of a minimal interest in 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 see?

All of the above, Neal. I believe we are driven by economics and aim to achieve the best outcomes. It may sound clichéd, but it's all about risk-adjusted returns. There’s the raw return that any engineering team will analyze, but it must be adjusted for the specific risks tied to the assets, sometimes involving necessary governance. Adam mentioned this earlier, and I want to emphasize this to our investors: just because we have formed several partnerships and pursued buy-down structures recently doesn’t mean we are not actively engaged in our traditional non-operated markets. In fact, I believe there may be a preference one way or another. The key takeaway is that our capabilities have significantly expanded compared to the past, which may explain why you've noticed this shift, alongside the variations in the quality of assets that are available. This year, we have seen several traditional non-operated assets come to market, but unfortunately, they tend to be of lower quality. I anticipate that higher quality assets will emerge, but this won’t happen every day. Therefore, I don’t see it as a matter of preferred structure; rather, we adjust our return expectations and governance requirements based on the concentration and specific risks associated with the asset.

It's building on that. It's definitely going to be asset specific, especially when you get into the drilling partnerships and some of the co-buying stuff, right? And so you kind of need to understand what the runway is 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? And so that is going to boil down to the social issues and how those discussions are going with a particular operator. We've had operators come to us and propose buying an asset, and it's something where they're going to be renting the asset for a period of time. And so is that the right partner for us? Maybe, maybe not, depending on what we can put in those joint operating agreements and what everybody can kind of live with. So it's as much the social issues when we're talking about some of these partnerships as it is the assets themselves.

Our next question is from Charles Meade with Johnson Rice.

Nick, Adam, Chad, and the entire NOG team, I have a question regarding Slide 10. First, thank you for providing the details on how the actual results compare to your acquisition case. My question is about the difference between your acquisition case and the new completion plan. It appears that we've observed some of this in Q2, but most of it seems to be ahead of us. If this is correct, does the fact that your actuals were ahead of the plan at the end of Q2 suggest that this gap will increase in the second half of '23?

Certainly, as long as it continues at its current pace, I believe we are taking it one well at a time. We've been quite conservative, and I give Jim and his team all the credit for that. However, I’ll also take a bit of credit myself. We really strive to maintain a conservative approach regarding performance and timing because timing can fluctuate frequently. That said, we have been encouraged by the well performance throughout every producing period, despite some minor issues that inevitably arise. The saying in real estate is that it’s all about location, and I feel the same applies here; this is a prime asset located in the heart of Midland County, with virtually no vertical penetrations on the properties. The rock quality is exceptional. So, while we’re not surprised by the well performance, it's also a sizable project with many logistical considerations that we are managing as we go along, learning and seeking ways to enhance returns. Overall, from a well performance standpoint, I'm optimistic about continued success with the assets, and I’ll let Jim add anything he wishes.

Yes. I would just add 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. So what you see on that graph there for the daily production is ramping, that's kind of the last batch of wells for this year. So even though it's exceeding the original forecast, you kind of expect that to switch as you get that kind of towards Q3, Q4, where we recently thought there would be another batch of wells that 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 capital efficiency going into 2024.

Our next question is from Donovan Schafer with Northland Capital Markets.

I’d like to discuss well costs and their relationship with service providers. Operators typically negotiate pricing in advance, often before you receive the AFEs. Given your role in developing a non-operator business model at scale and the mentioned tail advantages, I’m wondering if there’s potential for you to achieve better pricing with service providers. While operators have direct dealings with them, your broader interest across numerous wells could potentially give you more negotiating power collectively than a single operator has. Are you able to engage in discussions for better pricing with service providers? If this isn’t currently possible, is it something you aspire to in the future? Could this be a viable evolution in your business model?

I think the short answer is no. I want to emphasize that the AFE is not necessarily directly tied to the latest service contractor costs, especially when a company like Exxon is drilling a well for us. The AFE is simply an estimate. We can sometimes take it at face value, assuming that in today's environment, we might see savings later on or in a situation like last year where our cost assumptions were different from the AFE. They try to include contingency pieces in the AFE, but they may not always reflect the latest costs accurately. In the first quarter, for instance, we didn't see significant changes to those AFE costs. However, there was an expectation that the costs of those wells would come in under budget as they were completed. As for aggregating our interests and negotiating with service providers, the answer is no. In instances where we are significant non-operators, our credit profile sometimes aids operating groups in securing better terms, as we are a creditworthy counterparty. We have leveraged our position to an extent, particularly with smaller groups. However, I don't believe we can currently claim ownership of a 10% interest across all your wells and approach neighbors to reduce rig rates. We aren't there yet.

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, a situational specific. But if we put together a drilling program with an operator and kind of have those guardrails as to how many wells are going to be drilled and those such things. A lot of times, what we'll build into those contracts. Our covenants for cooperation with the service company. And so the operator is obviously taking the lead on that. But when we're getting into water and takeaway and other midstream contracts, they've got a covenant with us that they need to provide those contracts to us will provide our input compare that to our underwriting and move things along accordingly.

Okay. Just to clarify, are there instances where you discuss how your credit plays a role? Are there cases where it's treated as joint or several liabilities, which would enhance your credit's value because, in certain contracts, if the operator were to face a worst-case scenario like default, you would step in to provide support? Or is it generally the case that your credit's value is limited to your minority interest?

Yes. Everything is separate. None of these operators like going development agreements or anything like that or joint ventures, everything is...

The XYZ operator undergoes a contract, we're not liable if they default.

That's right.

Sure. Okay. As a follow-up regarding the Marcellus, it appears that your company has had strong production there, as Adam mentioned. I'm interested in the recent Mountain Valley pipeline approval following the debt ceiling agreement at the end of May. I understand there have been some delays at the Fourth Circuit Court, but just yesterday, the U.S. Supreme Court made a decisive move. The Fourth Circuit Court attempted to impose a temporary hold, but the U.S. Supreme Court ruled against that, allowing progress to continue. It seems that both the courts and Congress are aligning to support the Mountain Valley pipeline project servicing the Appalachian Basin. I wonder if you have any insights or thoughts on these developments and how they might impact your interest, both current and future, in the Marcellus.

Not really, Donovan. I think you asked something similar last quarter. If there is a long-term improvement for basis differentials, that would be great. We will likely see more development on our lands. We don’t typically make purchases anticipating such events, but it would certainly improve the entire basin. I feel the same now as I have in the past about the possibility of getting the infrastructure built without special interests in this country, although that is a longer discussion.

It just takes Congress in the Supreme Court.

A similar situation with access to the pipeline, right? It was all fits and starts. So, I don't think we're going to be planning on anything. While we're obviously optimistic, we are not making any business decisions based on this.

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.

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

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