Greetings. Welcome to Northern Oil and Gas's second quarter 2022 earnings call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. Please note this conference is being recorded. I will now turn the conference over to Erik Romslo. Thank you. You may begin.
Good morning. This is Erik Romslo, Chief Legal Officer of NOG, and welcome to our second quarter 2022 earnings conference call. Yesterday, after the market closed, we released our financial results for the second quarter. You can access our earnings release on our investor relations website, and our Form 10-Q will be filed with the SEC in the next few days. We also posted a new investor deck on our website last night. I'm joined here this morning by NOG's Chief Executive Officer, Nick O'Grady, our President, Adam Dirlam, our Chief Financial Officer, Chad Allen, and our EVP and Chief Engineer, Jim Evans. Our agenda for today's call is as follows. Nick will start us off with his comments regarding our second quarter and our business strategy.
After that, Adam will give you an overview of operations, and then Chad will review our second quarter financials and updates to our 2022 guidance. After the conclusion of our prepared remarks, the 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 these 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 these forward-looking statements. During today's call, we may discuss certain non-GAAP financial measures, including Adjusted EBITDA, Adjusted Net Income, and free cash flow. Reconciliations of these measures to the closest GAAP measures can be found in our earnings release. With that, I will turn the call over to our CEO, Nick O'Grady.
Good morning, everyone, and thank you for participating in today's call. I'll get right down to it and focus on five key points. Number one, despite some nasty storms, the second quarter still broke records for NOG. We generated a company record $272.5 million of adjusted EBITDA and approximately $114 million of free cash flow, the highest and second highest in company history, respectively. We produced nearly 73,000 BOE per day in the quarter, and we have already generated over $260 million of free cash flow in the first half of 2022, more than we produced during all of 2021.
We also hit an important milestone of 1x leverage on an LQA basis for the first time in my tenure here at NOG, despite having a working capital surplus of over $85 million, which is additional cash that will come to us over time. Number two, acquisition discipline. The deal we announced in June to acquire additional Williston properties is a testament to our strategy, and we continue to find meaningful ways to add value to our business. We continue to focus on a risk-managed, return-driven strategy that adds inventory and surety to our investments, all with the goal of delivering superior total return for our stakeholders. This means focusing on return on capital employed, which in turn will drive higher long-term dividend and buyback potential. Number three, diversification is key.
Although early spring storms had a temporary but significant effect on the Williston Basin, NOG's diversified model continues to prove itself, where we delivered higher volumes driven by the benefit of having properties in multiple basins. The Williston is now fully back online, and we're benefiting from exceptional in-basin pricing and lower inflation than in our other most active areas. Number four, future growth. Organic activity on our acreage has been accelerating and exceeding our expectations. Larger than typical, meaningful ground game opportunities are at exceptionally high levels. While quality is as variable as ever, there are also an ever-growing number of significant bolt-on opportunities hitting the marketplace today. I'll remind our investors that NOG's balance sheet is built to handle most acquisition targets we're analyzing without external equity financing. NOG is fully on the offensive.
We have the firepower, the scale, and perhaps the broadest set of opportunities in the company's history. With every high commodity cycle comes some newfound competition, but in the end, it will be our discipline, analytical rigor, and balance sheet strength that will set NOG apart more than anything else through the cycles. Number five, shareholder returns. Our goal is to provide our shareholders with the highest possible total return over the long term. We have implemented a multi-pronged approach, including repurchasing common stock and preferred stock, canceling a portion of our common stock warrants, repurchasing our senior notes at a discount, and increasing cash dividends for our common shareholders. During the quarter, we bought back our senior notes at 98% of par, lowering fixed charges, which boosts free cash flow permanently, but also at a discount to face value, which is accreted to the enterprise value.
These notes were issued last fall at nearly 107% of par value and now have been retired at less than we owe. If higher interest rates drive bond values below par value, we are prepared to take advantage of opportunities to continue to repurchase senior notes. B, on the equity side, we've retired $77.5 million year to date, including $20 million of common stock so far, the remainder being preferred stock. As a reminder, we have $130 million of remaining common stock buyback authorization. C, we also cleaned up a large portion of our outstanding warrants during Q2. We did this in a capital efficient manner to reduce future potential dilution and to mitigate associated hedging by our warrant holders that we believe could affect the trading of our common stock.
Investors may have noticed a significant recent reduction in short interest in part derived from this transaction. D, on Monday, we announced a 32% increase to our quarterly common stock dividend to $0.25 per share for Q3, with the goal of providing an attractive yield for our investors. We strongly believe that the consistency of a stable and growing quarterly dividend is more valuable to investors and our equity value over time than special dividend structures, which introduce unpredictability and volatility. E, finally, actions speak louder than words. Our successful execution of acquiring and integrating accretive acquisitions has driven our free cash flow to record levels. We believe there is continued room for expansion. We seek to maximize our long run total shareholder return by providing for a stable, attractive dividend and ongoing free cash flow growth.
While we have outperformed our peer group, we are mindful of the continued attractiveness of the stock and are pleased to have a robust buyback plan authorization, which presents further opportunity for our free cash flow. In closing, I will remind you, as I always do, we are a company run by investors for investors, and I want to thank each and every one of you for taking the time to listen to us today. With that, I'll turn the call over to Adam.
Thanks, Nick. Operationally, the second quarter finished as expected, and we continue to see the year progressing right down the fairway. We maintained a healthy pace of development in the first half of the year, turning in line 10.1 net wells in the second quarter. Permian completions increased, contributing 60% of the additions, while the Williston made up about a third of the activity. We also brought online our latest Marcellus pad, which increased NOG's production in the region by 11%. The new wells have outperformed internal forecasts, and we remain encouraged by the results. Elevated organic activity on our acreage position, as well as the success we've had with our ground game acquisitions, boosted our total wells in process to 57 net wells across 500 gross wells.
The breakdown by basin remains consistent with the first quarter, as the Permian makes up almost half our oil-weighted wells in process, while the two-year high in the Williston rig count is providing for additional activity. The pace of development on our acreage footprint continues to accelerate as we added an additional 16.7 net wells to the drilling and completing list, netting an increase of approximately 8 net wells in the quarter. The increase in CapEx during the quarter was attributable to the pull forward in drilling activity as our D&C list on average, has incurred roughly 50% of the anticipated development spend and is consistent with the ramp in completion activity we are expecting in the second half of the year.
Well costs came in as expected on inbound AFEs in the second quarter and averaged $7.2 million per well, up less than 3% from last quarter. We expect well costs to increase in the second half of the year, but well within our per well estimates, which is already incorporated within our stated annual CapEx guidance. In Q2, we saw 115 well proposals equally balanced between the Permian and the Williston, with the average expected rate of return far north of 100%. We also continue to partner with larger operators who benefit from their leverage with service providers. Our active management of the portfolio on the buy side has provided us with the ability to forgo development opportunities with certain smaller operators who have felt the largest impact of the inflationary pain.
To that end, the M&A market is alive and well in this current environment, and we have been reviewing over $2 billion worth of opportunities. While the bid-ask spread is real, there are a number of sellers with unrealistic expectations. Our attention remains on quality assets and reasonable sellers. We have superior data, scale, and the balance sheet strength to be the preferred counterparty, one that is a reliable executor of acquisitions and that can underwrite with precision to generate a superior return for our investors. From a ground game standpoint, we closed on 4.2 net wells in Q2, and the acquisitions are expected to generate a full cycle return on capital of 52% in 2023. The Williston made up approximately three-quarters of the activity as operators remain focused in the core and have also done a better job of keeping inflation under control.
At a package level, we are slated to close on our recently announced Williston acquisition in the middle of August, and there are currently 13 additional acquisition opportunities that we are evaluating. The focus remains in the Delaware, Midland, and Williston basins, which have provided for some of the most compelling opportunities to date. As NOG has scaled up and diversified over the last 18 months, the breadth of opportunities that we're able to pursue is also expanding. Our ability to move quickly and underwrite assets has provided us with operator partnerships as we co-develop acreage positions, explore asset swaps, look to partner on operated asset packages, and set up various development agreements. Paired with the typical non-op packages that we see on and off market, the addressable market has never been better.
While it may appear to be a seller's market, we continue to source unique opportunities, and we remain disciplined in only pursuing acquisitions that meet or exceed our return thresholds. With that, I'll turn it over to Chad Allen.
Thanks, Adam. I'll start by reviewing some of our key second quarter results, which was again one of the strongest quarters in company history. Our Q2 average daily production increased 2% sequentially over Q1 and increased 33% over Q2 of 2021. Oil volumes were down slightly, driven almost entirely by the spring storms in the Williston Basin, where we have our highest oil cut assets. Our adjusted EBITDA was $272.5 million, which exceeded consensus estimates and was a record for NOG. Our free cash flow was robust at $114.3 million, the second highest in our company's history. Our adjusted EPS was $1.72 per share in Q2, above consensus estimates.
Oil differentials were better than expected in Q2 and came in at $2.33 per barrel due to strong Bakken pricing and having more barrels weighted towards the Permian, which has a sub $2 oil differential. Gas realizations continued to remain strong in Q2, which is leading to the increase in our annual guidance for gas realizations. However, as gas prices have risen, the NGL spread has narrowed, which will lower realizations in the latter half of the year. Combined with the seasonally wider Marcellus differentials in the shoulder season, we expect gas realizations below 100% of NYMEX in the third quarter. These operating costs were $64.6 million in the second quarter or $9.77 per BOE, up on a per unit basis compared to the first quarter.
This was fully expected and factored into our guidance for the year, driven by the second quarter incurrence of our annual firm transport costs in the Marcellus. Gas G&A, adjusted for acquisition costs related to our recent acquisitions, was $0.93 per BOE. We continue to experience elevated G&A costs from costs associated with the highly active period in M&A valuation, and many of those costs are not excluded from those figures. Capital spending for the second quarter was $131.8 million, which was slightly above street expectations as we saw pull-forward drilling activity and additional ground game activity late in the quarter. Our Williston Basin spending made up 38% of the total capital expenditures for the quarter. The Permian made up 56% and the Marcellus made up 5%.
The pace of our CapEx spending ramp for the second half of 2022 will be dictated by tight conditions in the fields, as we've seen both pull forwards and delays. We have a record 57 net wells in process, which means our growth trajectory remains very strong as we head towards 2023. The balance sheet is in great shape. While the revolving borrowings ended only slightly lower quarter-over-quarter as a function of the $17 million deposit on our Williston acquisition, as well as over a $13 million reduction in our 2028 notes. In aggregate, leverage was still down on an absolute and ratio basis with an LQA ratio of 1x. Leverage will tick up slightly next quarter with the Williston acquisition closing, but the ratio should still be well below 1x at year-end.
We are monitoring the interest rate environment as well as our bond levels, and we look to find ways to efficiently reduce leverage if the market opportunity is there. Given the cash flow we expect to generate, we forecast our revolver will be undrawn by mid-next year, despite funding the Williston acquisition this year, although that could certainly move depending on commodity prices, how we use our free cash flow and other factors. As previously announced, in early June, we amended and extended our revolving credit facility with a substantial increase in our borrowing base and elected commitment to $1.3 billion and $850 million, respectively. That, coupled with our free cash flow, means our liquidity remains very strong.
On the hedging front, we opportunistically added hedges north of $80 per barrel since our last report, mostly to fill our targets in 2023 and 2024 and to top off volumes from our recent acquisitions. We continue to target hedging around 60% of production on a rolling 18-month basis with select longer-dated hedging tied to corporate acquisitions. Changes in the shape of the curve have allowed us to add some of our first costless oil collars in 2023, all with a floor of at least $80. With respect to updated 2022 guidance, our production guidance is unchanged from our June update at a range of 73,000-77,000 BOE per day for the year.
We bumped full year LOE guidance modestly by about $0.30, mostly driven by the increase in processing costs associated with higher NGL prices year to date and a slight impact from our pending Williston acquisition. As I mentioned earlier, oil differentials in both the Williston and Permian have been materially better than expected, so we're updating our full year guidance to $4.50-$5.25 per barrel. While we're bumping up our gas realization guidance, we do expect lower realizations in the second half of 2022, as I mentioned earlier. For modeling purposes, North Dakota has raised production taxes to 11% of oil sales and approximately $0.09 per unit for natural gas. This is well within the bounds of our existing production tax guidance through 2022.
All in all, this outlook should generate approximately $500 million of free cash flow for the year, which includes payment of our preferred stock dividends. With that, I'll turn the call back over to the operator for Q&A.
Thank you. If you would 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 would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up the handset before pressing the star keys. Our first question is from Neal Dingmann with Truist Securities. Please proceed.
Morning, all. Nice details. Nick, my first question is on capital allocation, specifically your thoughts on balancing your suggested dividend and other shareholder return plan with what looks to be continued very opportunistic ground game?
Neil, I think it just comes down to capital allocation and, you know, kind of a risk-adjusted return. I think, you know, usually, when you run it at a pure corporate finance perspective, you know, bolt-ons, ground game, you know, still some of the highest returns. You know, as multiples and valuations have compressed overall, obviously our own securities and dividend plans have started to compete with that significantly. And so you've seen us, you know, we designed this plan to have a lot of flexibility. And so we've really been kind of ratcheting that up, especially as the opportunities come. But I think it's really still a multi-pronged kind of all-of-the-above approach.
No, glad to hear that. Second question on competition. Specifically, could you discuss, kind of today's industry competition, such as from maybe SPACs or other players versus what you saw several quarters ago when you took over?
Sure. Yeah. I mean, like any other cycle, you know, we definitely see pockets of competition here or there. In the current environment, we've seen some competition for very small interests. On the larger side of transactions for PDP-heavy properties, that's fine by us, as that's not something we're terribly interested in. The reason for this is that PDP properties are mortgageable, and given how difficult raising equity capital has been, groups are using debt and asset-backed securitizations, which are more readily available to fund these, and much like real estate, trying to arbitrage the quote-unquote "cap rate." This, of course, assumes you have an accurate view of the PDP declines and cost structures to be truly safe investments. On sizable concentrated ground game assets and the larger packages, we always have some competition, but find we remain highly competitive.
Our biggest competition is generally the hold case and/or, you know, unrealistic development expectations. Sometimes we feel like we know too much that we lose assets because buyers may be mismodeling the reserves cost or development timing. You know, we're fine to lose if that's the case. As for SPACs, et cetera, all I would say is that, you know, there's a reason you go through the IPO process, which is to build alignment and create value, not just for the company, but for the new investors as well. It creates sort of a symbiotic relationship where the IPO participant gets assets at a perceived discount. The company then builds trust and over time earns further access to capital. Being public and having access to capital are not the same thing. It's not just a switch you simply pull.
SPACs have an inherent misalignment, which are designed to give free value to the sponsor in the form of a zero-basis promote. For the seller to be able to dictate the price of the sale into the SPAC, rather than let the market and investors decide what those assets are worth. Which begs the question as to why you would choose that path, and I think the answer is obvious, which is that the value you get, at least initially, is self-selected and much higher than the market would bear. When I was a kid, my brother and I would build sandcastles at my grandmother's place in Massachusetts. We were determined to make them strong enough to survive the tide coming in. Every morning, though, we went to the beach and our castle had been wiped clean by the tide.
That's my view of markets. You can financially engineer all the things you want, but in the end, the power of market forces will ultimately be the determinant of value. I don't perceive these as real competition. I think as a team, we've spent nearly five years building a strong investor base, a good reputation with sellers as a forthright and reliable partner, scale, and now oodles of liquidity. I still believe we remain the best and most viable counterparty.
Great details. I always love these analogies.
Every quarter, buddy.
Our next question is from Derrick Whitfield with Stifel. Please proceed.
Thanks, and good morning, all. Nick, I love that analogy.
Thanks.
With my
a new one.
With my first question, I wanted to focus on the production trajectory for Q3 and Q4. In thinking about the production outages in Q2 and the acquisition that will close in Q3, we have oil production increasing about 4,000 barrels in Q3 and then another 3,000 barrels in Q4. Does that seem about right?
I think what we're only gonna have on the Williston acquisition, you know, let's call it 45 days or so, Derrick, right? We're gonna close in mid-August. The effective date goes back, but that'll be in the purchase price settlement. We'll get that cash flow, but it won't be in the form of production. I think we see steady ramp, but I think you're gonna have. In the fourth quarter, you're gonna have a much, depending on the timing of WIPs, you're probably gonna see the largest impact from completions, just because even if we have a very aggressive turn in line schedule in Q3, you're only gonna get a portion of that volume. James, I don't know, you wanna comment towards that?
Yeah, Derrick, hey, it's Jim. We've got some pretty large the Williston right now that are working through. We expect those to be mostly towards late Q3, early Q4. That's when we're kind of expecting our big ramp in production throughout the Williston, which is obviously our highest oil cut area. We kind of expect it be kind of later towards the end of the year that we see that big ramp.
Terrific. As my follow-up, referencing slide 15, could you share your thoughts on what's driving the stronger Bakken well performance in 2022? Is it perhaps longer laterals or tighter spacing?
I think it's a combination of the operator mix and operators, you know, remaining disciplined. We're not seeing necessarily the step-ups that we've seen in full runs in the past. You know, you've got our low cost and, you know, what we would consider some of our best, you know, top three operators contributing to that. I don't know, Jim, you wanna add anything else?
Yeah, obviously a lot of the stuff that, you know, came on in the first half of the year was wells that we elected to in 2020, where oil prices were a little bit lower, so operators were still kind of sticking to that core. You know, as we've gotten into 2022 here, with high prices, we've seen some operators start to step out a little bit. We would expect some well performance degradation towards back half of the year into 2023. So far, we're very pleased with the performance that we're seeing.
Terrific. Very helpful, and thanks for your time.
Our next question is from Austin Aucoin with Johnson Rice. Please proceed.
Good morning, Nick, and to your team. Thank you for taking my questions.
Well-
First question is, Northern seems to be one of the few companies who are not having an increased CapEx outlook due to inflation. Can you provide some color on how you set your inflation expectations at the beginning of the year?
Yeah. I mean, I think the simplest part is that we baked in inflation this year, but we also didn't bake in deflation in 2021. We effectively were running cost structures from pre-pandemic. We never really changed that forecast and then added inflation on top of it. As it stands today, the only cadence frankly, for this quarter in particular, that really can change that is either if you have a pull forward of activity which really is just borrowing from future quarters, or if we've had, you know, the lumpy success that you have in the ground game when you're acquiring. Because when you acquire the acreage and the wellbores, you're accruing immediately for the capital.
If a well is tapped and processed, it might not cost you very much money, but you're booking all the costs of those wells and processing. That's why it can be quite lumpy. Frankly, as it stands today, you know, we're really comfortable with the guidance where it is. You know, if we had a material acceleration of development, it still won't really change that. It just changes the timing of that within the year. You know, we've been right in the middle of the goalposts pretty much all year. I just think that, you know, the thing is that when we've done this, historically speaking, we don't necessarily look. We try to look beyond our nose, and we don't just look at where our cost structure is today and bake some small piece in.
We spent a lot of time, particularly at the end of last year as we were looking towards this, because we had a fairly, you know, grave assessment from what we were seeing in terms of where costs ultimately were gonna go. We do expect costs to continue to increase throughout the year. You know, as you could note from our average AFE cost, you know, we're still nearly $1 million, you know, well below where we've effectively budgeted it. That's our average for the year, but we actually budgeted for higher than that as you go throughout the year.
That's a function of, you know, the operating partners that we actively manage to, you know, participate with, right? So we have an idea of, you know, our operating partners' cost structures, their propensity to overrun. Using that data, you know, in 2020 moving into 2021 and into 2022, you know, you can leverage that and structure around it.
I appreciate the color. As a follow-up, how would you prioritize your cash return to your shareholders? Is the top priority buying back the preferred shares, followed by the increase in the base dividend, then debt reduction, and finally repurchasing common shares?
I don't know if it's that simple, because I think it's really opportunistic. I would say, you know, the preferred stock is in the money, so the delta between the preferred stock and the common stock narrows, especially as our common dividend goes up. The cost of capital difference between them is relatively de minimis at this point in time. I think common stock has gone up. I think we still you know, we are a risk-averse group, and so, you know, debt reduction still plays a big role. I think there's a difference between paying down debt and buying in your bonds, in the sense that, to the extent that, you know, high interest, high, you know, Fed funds rates means that, bond prices go down.
We're not just retiring debt, but we're actually creating enterprise value because you're buying it at a discount to what you owe. That actually has an impact to the equity value as well as the overall debt levels. I think that we really try to stay flexible. I think that a stable and growing dividend is really important. We also are very mindful of managing the yield expectation on that. I don't think when companies have really low yields, it doesn't matter, and when they have really high yields, that tends to create its own set of problems and its own, you know. We don't really wanna go down either one of those paths. We have no interest in being an upstream MLP of old.
I think we will be very, very flexible. You know, we have put mechanisms both from an authorization perspective and just in terms of our own internal mechanics around SEC rules to be able to be very, very opportunistic.
Thank you. That's all for me.
Our next question is from John Freeman with Raymond James. Please proceed.
Good morning, guys.
John, how are you?
Yeah. Good, thanks. First question. If I heard you right, Adam, I think you said that y'all have got, you know, just a lot of opportunities in the pipeline for acquisitions in Delaware, Midland, and Williston Basin. I didn't hear you mention the Marcellus. I'm just wondering if that's by design or it's just, you know, other, you know, it got really competitive or just any other reasons why that one wasn't mentioned.
No, I mean, we've looked at two or three, you know, potential acquisitions this year in the Marcellus. They just weren't a fit. I think, you know, my prepared comments were around kind of the 13 processes that are effectively current right now. You know, we've run those out kind of in a quarter and kind of put those to bed.
Yeah.
We're actively looking. It's just a matter of not being a fit at the moment.
Yeah. We had one Marcellus prospect that was exciting to us. It just didn't trade, John, to be candid. You know, it didn't.
The old hold case.
Yeah, the old hold case came to bite us, I think, John.
The follow-up I had, it's kind of on the prior line of questions, Nick, that you answered. You have obviously done a great job managing the cost line while most everybody else in this space has had the continual CapEx increases. You know, I may not hold you to this, but just y'all are gonna have better insights than just about anybody, given the number of operators and across the basins that y'all are in. I mean, give sort of an idea of what you would assume, just as it stands now, what you would assume is a reasonable cost inflation number to plug in for next year.
It's difficult to know in the sense that. You know, I could certainly tell you how we see it exiting, but I think, you know, if oil prices are $50 next year, it's gonna be a very different answer. I think it's. It would be very presumptuous to make the assumption. I mean, I think ceteris paribus if, you know, cost increases tend to be sticky. You know, I think we've got about, what, Jim? About 15% between now and the end of the year total. Is that right?
Yeah.
Yeah.
That's about right. Yeah, I guess the way that I kind of frame it up is it's gonna depend on your operating partners. It's gonna depend on your working interest associated with them. As we get towards the end of the year and kind of frame up and have a better idea of the cadence of kind of the wells and whatever else is kinda in the backlog in terms of AFEs that'll be drilling into that, we'll be able to better frame that up.
I appreciate the answers, guys. Well done.
Thanks, John.
Our next question is from John Abbott with Bank of America. Please proceed.
Good morning, guys.
Good morning.
Thank you for taking my questions. Sort of similar along the lines of the prior question on inflation. You know, given the pivot, it seems towards going with larger companies versus smaller companies, can you provide any sort of color on the difference between AFE costs between a larger operator and a smaller operator at this point in time?
I mean, I've seen just anecdotally, John, and I'll let the smarter people in the room answer the rest of this, but when we've seen kind of, you know, start-up rig operators looking for development capital in the Permian, $2-$3 million a well difference. That's because they're paying spot prices for every single item. They're borrowing the rig. They're borrowing the frack crew. You know, we've seen, I believe, one AFE that was $16 million.
2 mile lateral.
For a 2-mile lateral.
We did not.
We did not participate in that.
The variability is certainly wide in the Permian, just given the number of different operators you have. Maybe relative to Williston, I guess the only other thing that I would qualify it with is, you know, we're not necessarily just focused on well costs, right? I mean, we're solving for a required rate of return. It's gonna, you know, also need to take into consideration completion methodologies, offsets, all of those types of, you know, technical aspects to it. We're happy to elect to, you know, maybe above average AFE to the extent that it's gonna meet our hurdle rates.
Appreciate it. The second question is sort of on maintenance CapEx. I mean, it looks like you have a very strong trajectory at the end of this year, which probably will help your spending potentially in 2023. If you had to guess at this point in time, where do you think maintenance CapEx, just sort of thinking about inflation, is overall? If you do have the color, where do you think about it in terms of your various areas?
Well, when you say maintenance CapEx, what's the production level you're picking, right, that are out there this year?
Let's just choose the 77,000 BOE per day exit rate, potentially somewhere around there.
Yeah, I mean, that's 58-62 wells probably. You know, but remember, it's gonna be, you know. Yeah, let's call it $450 million-$500 million hand-waving. I again think it's a little early to kinda make those assumptions, but.
I understand. Hey, thank you very much for taking my questions.
Yep, you're welcome.
Our next question is from Noel Parks with Tuohy Brothers. Please proceed.
Hi, good morning.
Good.
Say, you know, maybe as a subset of the discussion about what you think about cost trends. I've been hearing here and there from some operators that they're starting to see a little bit of trouble with materials delivery, and with that sort of backing its way up into slowing completion. Even though, you know, the estimated costs aren't different, they're just starting to see that bit of schedule, you know, schedule padding, or schedule slippage. I'm just wondering, are you hearing about anything like that in any of your regions?
Yeah, absolutely. I think we've seen, you know, material delays as much as six months on pads. You know, what I'd say is, if I remember when I looked at June, I think we had, you know, an entire net well, or excuse me, a half a net well delayed and one well that came on six months early. It's always a push and pull. There are always delays. You know, the fields are very, very tight. But statistically speaking, it hasn't really been a major issue for us.
Well, that's the beauty of the diversification and the 500 wells that we have in process, right? We don't have one particular operator, you know, creating a big problem for us to the extent that they've got a big problem for themselves.
Yeah, I mean, I think our secret sauce, Noel, is that we generally don't take everything at face value, meaning that we make assumptions that things take longer, that they cost more, and that's why we are where we are at this point in the year, with roughly.
Right.
Static budget and on schedule.
Gotcha. There definitely has been an air of caution among operators as far as, you know, committing or even previewing what their expectations are for 2023. I guess I'm just thinking in your view, if say, you know, pick a number, you know, by this time next year, we're up another 10%, 15%, 20%, whatever. Do you have any sense of whether we might be peaking in terms of the service environment? I've heard from some operators, you know, we are paying the most we've ever paid for services in a particular basin.
Others have been saying that they do see signs of new equipment coming online from the service companies, not at the pace that you have seen in past booms, but that sort of steady trickle is on the way. Again, just wondering if you had any insight on that.
I mean, I think that, you know, follow the money. I think, you know, I've been involved in the energy business for 22 years now, and I've never seen.
Right.
A cycle in which a service provider makes a ton of money and with relatively low barriers to entry and new equipment doesn't enter the market. Yeah, this won't go on forever. As I think I said this in the last call, there's no shortage of the ability to make steel pipe or sand in the United States or frankly to make a pressure pumping unit. It's really just time and you know fixing some of those issues that are plaguing frankly the entire world economy. I have a lot of optimism that this in time will pass. Frankly you know what I would say is that there are a lot of other risks that can solve those issues for you, right?
Oil and natural gas prices themselves, to the extent that, you know, you see, you know, weakness in pricing, you will see slowing activity. If delays become so rampant, then ultimately that will become, you know, self-defeating to some degree. So yes, I think that there will be a peak. Which is it? You know, next year or this year, I'm not sure. You know, there are certain items that we have seen start to slow down. Things like labor take a lot of time to fix when you have these issues, but, you know, eventually, you know, capitalism is a beautiful thing, they usually do.
Right. Great. Thanks a lot.
As a reminder, just star one on your telephone keypad if you would like to ask a question. Our next question is from Nicholas Pope with Seaport Research Partners. Please proceed.
Hello, everyone.
Nicholas, good morning.
I was curious if you could kind of expand a little bit, looking at kind of the split of CapEx spending in 2Q is a pretty big jump in Permian is kind of a split. Is that really the opportunity set? Is that where you're seeing kind of the returns are driving that CapEx, or is that kind of the rate we should expect as kind of a split between these three assets right now?
You know, Nick, we had guided, I think, 45 and 10 for the year. I looked at it yesterday, and it's about the same for our model. I think it's just happenstance.
Yeah, I think it's just cadence and development. If I look at our AFEs during the quarter, you know, and looking at kind of our working interest between the Permian and the Williston, you know, our average working interest in North Dakota was around 8%, whereas our Permian was around 18%.
Got it. Okay, that's all I had. I think most of everything else has been asked. Thanks, guys.
Sure you don't wanna ask another one?
There are no more questions at this time, so I would like to turn the conference back over to management for closing comments.
Thank you all for joining us today. We very much appreciate your interest, and we'll see you next quarter. Thanks.
Thank you. This does conclude today's conference. You may disconnect your lines at this time, and thank you for your participation.