Northern Oil and Gas, Inc. (NOG) Q2 2023 Earnings Call Transcript

Northern Oil and Gas, Inc. (NYSE:NOG) Q2 2023 Earnings Conference Call August 3, 2023 8:30 AM ET

Company Participants

Evelyn Infurna – VP, IR

Nicholas O’Grady – CEO

Adam Dirlam – President

Chad Allen – CFO

James Evans – Chief Technical Officer

Conference Call Participants

Scott Hanold – RBC Capital Markets

John Freeman – CIMB Research

Neal Dingmann – Truist Securities

Charles Meade – Johnson Rice & Company

Donovan Schafer – Northland Capital Markets

Operator

Greetings, and welcome to the Northern Oil and Gas Second Quarter 2023 Conference Call. [Operator Instructions]. As a reminder, 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.

Evelyn Infurna

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.

Nicholas O’Grady

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 4 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 D&C 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 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 2 large-scale joint development projects in the second quarter, specifically Forge and Novo. These 2 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.

Adam Dirlam

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. 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 2/3 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, NLG 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 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 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 are market. Regardless, we will remain disciplined in both our approach and underwriting as we navigate the rest of the year. While our major acquisitions, we’re 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 3/4 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

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 0 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 additional 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.

Question-and-Answer Session

Operator

[Operator Instructions]. Our first question is from Scott Hanold with RBC.

Scott Hanold

I was wondering if you could discuss how you think about like 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?

Nicholas O’Grady

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.

Scott Hanold

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?

Adam Dirlam

Scott, I think the Bakken — some of the deferrals that we alluded to in our pre-release is really representative of maybe 1 or 2 operators where we’ve got some outsized working interest, maybe more sensitive from a commodity pricing standpoint. We’re having those conversations with the operators right now, where we stand today. Those commodity thresholds are being met and so as far as anticipated completions and whatnot, we’ve got that couched, call it, Q4 timing, but that’s also going to be dependent on logistics and everything else. And so that could get pulled. It could potentially get pushed depending on kind of that volatility.

And then as far as Texas and New Mexico goes, it’s steady as it goes. Obviously, we have some commentary around the Mascot project. That’s obviously very specific, just given the stack pay and the overall kind of core completion activities that were running the ground with Midland Petro in that group, but everything else is generally steady as it goes. And then I think you might have alluded to the game opportunities, we continue to see those coming in the door every single day and the size and the scope of what those look like are all very different. And I think that gives us the ability to get picky in terms of where we’re going to apply our capital dollars.

Operator

Our next question is from John Freeman with Raymond James.

John Freeman

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?

Nicholas O’Grady

Yes. I mean 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 time is that oil prices and service costs will move in sync with each other, right, from a margin perspective. And 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 going down materially. And activity has been coming down, but costs were taking some time to come down to meet that. And on believing it, you started to see that, that’s also juxtaposed against a period where we’ve started to see oil prices rally.

And so I think as we look forward, I just want to caveat it and say that well the last shoot of fall really where you’re going to see — where you would see a material change to savings is going to be completions. And 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 going to see the rig count come up modestly. And thus, with that, I think your chances of seeing material savings from here are going to be reduced. So I would say — as I’ve said to a lot of our investors, 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 going to go. But more specifically to your — I’ll let Jim or Adam talk specifically to any leading-edge changes versus that $9 million.

Adam Dirlam

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.

John Freeman

Great. And then just my other question on the leverage slide that you referenced, Nick, that Slide 13, we basically show of where you all sort of view leverage in that 0 to 1.5x range and how you talked about kind of flexing leverage in the near term if needed for certain growth opportunities, which obviously you have done in speeds here recently with a number of big transactions. So you — in that slide, it talks about on the lower end, it’s kind of harvest mode towards the 0 leverage, upper end is invest. And Nick, you used the word harvest in your prepared remarks.

So I guess I have kind of 2 parts: a, I guess, should we assume that, that means you start targeting the lower end just given what you said about large-scale M&A, et cetera, your comments on harvest, but then also what’s not on that slide is how does just a commodity environment kind of overlay on this chart. If you were at a $90 world, I assume that your leverage, what you view as acceptable leverage is probably different than if you’re in a $60 world?

Nicholas O’Grady

Yes. I mean I would say that generally speaking, we’re not running our leverage kind of — just the one thing that this doesn’t really point out to, which probably should is that we’re not thinking — we’re thinking about this on a normalized ratio, right? We’re not running spot $80 through and making the assumption if we’re 1.5x at 1x lever at $80 forever, right? We’re using a discounted price to that. We’re kind of using a mid-cycle price in our mind.

But — so I mean, I think to answer your question is like the one thing I would point out to, specifically, look, I think when you think about the uses of cash flow as you kind of reach those targets is obviously share repurchases, right? And 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. So like I said in my call, an already discounted stock price.

So going back to my car loan analogy, whether or not that you’re just getting a better return for the investors by doing so. But obviously, to the extent that the environment winds up being less so, that’s an obvious default, we can afford it, but I think you need to have the risk metrics and kind of both a cyclical and oil price perspective as well as an aggregate leverage perspective to a point where you really want to do that. And 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 if there’s 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 not me, but didn’t get there.

Operator

[Operator Instructions]. Our next question is from Neal Dingmann with Truist Securities.

Neal Dingmann

My question is on the second half and possibly ’24 activity. It sounds like — I forget what 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 you have confidence that your TILs will ramp through the remainder of 2024. I’m just wondering it sounds like this is the case, can you give us an idea of just the degree of that and which areas we’ll see the most activity.

Adam Dirlam

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 4 counties, McKenzie, Mountrail, Dunn and Williams, and that hasn’t changed for years.

Neal Dingmann

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?

Nicholas O’Grady

All of the above, Neal. I think we’re economic creatures. I think we want to extract the best. I know it’s sounds corny, but risk-adjusted return, right? So there’s the raw return that obviously, any engineering deck is going to run through, but then you have to adjust that for the specific risks to the assets, so sometimes a required governance. I think Adam talked about this in his comments, and I think this is something that I would want to reiterate to our investors, which is that just because 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 would 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 traditional non-operated assets come to market this year, and they just happen to be pretty poor quality and [indiscernible]. And so I think that it’s going to come, but that’s not going to be the case every day. And so I don’t think there’s a preferred structure. I think we adjust our return thresholds and needs for governance or other things, depending on the concentration and the specific risks of the asset center.

Adam Dirlam

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.

Operator

Our next question is from Charles Meade with Johnson Rice.

Charles Meade

Nick, Adam and Chad and to the whole NOG crew there. I think I have just one question. And on Slide 10, and first of all, I want to say thank you for giving us this detail about how the actuals are comparing to your acquisition case. But my question is this, how much — it seems to me that most of the delta between your acquisition case and this new — and the new, I guess, completion plan. 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 the way that at the end of Q2, your actuals were ahead of the plan? Does that suggest that we’re going to see that gap grow in the back half of ’23?

Nicholas O’Grady

Certainly, I mean to the extent that it continues at the pace it has, of course, I mean, I think we take it 1 well at a time, Charles. So I think we’ve been pretty conservative. And when I say we, I’ll give Jim 100% credit and his team. But — so well, maybe I’ll take credit on top of that on — but seriously, I think the answer is that we try really hard to take a conservative tact on performance and timing for that matter because timing does move all along — moves all around all the time. But 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 the old adage is in real estate, it’s location, location, location. And I think it’s the same thing as it pertains to this asset, which is this is just a — this is a Ferrari assets sitting right in the heart of Midland County, no — virtually no vertical penetrations on the properties. It is just virgin incredible rock. And so the well performance, are we surprised? Not really, but 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 improve the returns. But overall, from a well performance perspective, I certainly think — 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.

James Evans

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.

Operator

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

Donovan Schafer

First, I want to ask talking about 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. But I am curious, being that you guys are really kind of charting the path on the non-operator business model and reaching such large scale. And you’ve talked a lot about tail advantages that you get. I’m curious if — as things stand today or maybe it’s the case where this is a potential thing in the future, could there be an evolution here? Or again, maybe you already hear where you’re able to get better pricing with service providers, as far as what ends up flowing through the AFE?

You can imagine a case where maybe an operator is dealing directly with the service providers. But if you add up your smaller minority interest, across all of your wells and 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. So I’m just wondering, are you ever able to bring that to bear and get involved in that kind of level of conversation and negotiating pricing with the service providers. And 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?

Nicholas O’Grady

I mean, Don, 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 — if Exxon is drilling a well for us, for example, the AFE is just an estimate, right? So it’s not always tied directly to their latest service contractor costs, which is why oftentimes, 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.

So it is really an estimate in the — they try to have contingency pieces in them and all those things, but they’re not necessarily always leading edge, just like we didn’t really see in the first quarter that — a big change to those AFE costs, but there was an assumption that perhaps while those wells being completed, they would come in under budget effectively. As to whether we could aggregate our interest 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 creditworthy counterparty or a rated entity and stuff like that. So in that respect, we have kind of flexed our muscle at time, especially with some of our smaller groups. But I don’t know if we could sit there and say, hey, we own 10% interest across all your wells and go to neighbors and help lower the rig rates. I don’t know if we’re there yet. But…

Adam Dirlam

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.

Donovan Schafer

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

Adam Dirlam

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

Nicholas O’Grady

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

Adam Dirlam

That’s right. [indiscernible] joint working interest owner and was going to be paying a sizable chunk of the joint interest billing, having that kind of qualitative information is something that helps facilitate the process.

Donovan Schafer

Sure. Okay. And then as a follow-up, with the Marcellus, 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 that happened at the end of May. And I know there’s been some holdups at like the Fourth Circuit Court, but it looks like just yesterday, the U.S. Supreme Court, the stuff gets felt contentious. And so the Fourth Circuit Court tried to put a temporary hold on things.

U.S. Supreme Court, I guess, yesterday said, no, you can’t even do a temporary hold. We’re going to give these guys the benefit of the and let them proceed with everything. So it seems like the weights of the courts and everything is — and 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 potentially prospective interest in the Marcellus?

Nicholas O’Grady

Not really, Donovan. I mean I think the — look, I think you asked something similar last quarter, the extent that it has a long-term improvement for basis differentials, awesome. We’ll probably see 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 the basin as a whole. I think I’m not [indiscernible] more now than I have been in the past that maybe we can actually get the infrastructure built without [indiscernible] special interest in this country, but that’s a longer conversation.

Unidentified Company Representative

It just takes Congress — it just takes Congress in the Supreme Court.

Adam Dirlam

A similar situation with [indiscernible] access pipeline, right? I mean it was all fits and starts. And so I don’t think we’re going to be planning on anything to Nick’s point, obviously optimistic, but we’re not making any business decisions around this.

Operator

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.

Nicholas O’Grady

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

Operator

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