Northern Oil & Gas Inc. (NOG) Q2 2022 Earnings Call Transcript

Northern Oil & Gas Inc. (NYSE: NOG) Q2 2022 earnings call dated Aug. 04, 2022

Corporate Participants:

Erik Romslo — Chief Legal Officer

Nicholas O’Grady — Chief Executive Officer

Adam Dirlam — President

Chad Allen — Chief Financial Officer

Jim Evans — EVP and Chief Engineer

Analysts:

Neal Dingmann — Truist Securities. — Analyst

Derrick Whitfield — Stifel — Analyst

Austin — Analyst

John Abbott — Bank of America — Analyst

John Freeman — Raymond James — Analyst

Noel Parks — Tuohy Brothers — Analyst

Nicholas Pope — Seaport Research — Analyst

Presentation:

Operator

Greetings. Welcome to the Northern Oil Second Quarter 2022 Earnings Call. [Operator Instructions]. Please note this conference is being recorded. I will now turn the conference over to Erik Romslo. You may begin.

Erik Romslo — Chief Legal Officer

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.

Nicholas O’Grady — Chief Executive Officer

Good morning everyone and thank you for participating in today’s call. I will get right down to 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 one times 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 2, 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 a 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 3. 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 4, 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. And while quality is as variable as ever, there are also an ever-growing number of significant bolton 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 disciplined analytical rigor and balance sheet strength that will set NOG apart more than anything else through the cycles.

Number 5, shareholder returns. Our goal is to provide our shareholders with the highest possible total return over the long-term. We have implemented a multi-prong 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.

A, 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 discounted face value, which is accretive 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 hope. 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 a $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 the 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 a 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.

Adam Dirlam — President

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 the NOG’s production in the region by 11%. The new wells have all outperformed in tune with 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 and process to 57 net wells across 500 gross widths[Phonetic]. 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 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 wells, 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 DNC list on average has incurred roughly 50% of the anticipated development spend and it’s consistent with the ramp and completion activity we are expecting in the second half of the year.

Well cost came in as expected on inbound AFPs in the second quarter, an average $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 and benefit from their leverage of 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 Ground Gain standpoint, we closed on 4.2 net wells in Q2, and the acquisitions are expected to generate a full cycle return on a capital of 52% in 2023. The Williston made up approximately three quarters of the activity as operators remain focused in the core. We 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’re evaluating. The focus remains in the Delaware, Midland, 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 were 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.

Chad Allen — Chief Financial Officer

Thanks, Adam. I’ll start by reviewing some of our key second quarter results, which was again on 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 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 a $114.3 million, 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, with a strong Bakken pricing and having more barrels weighted towards the Permian, which has a sub-$2 oil differential. Gas realizations continue 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 were lower realizations in the latter half of the year. Combined with the seasonally wider Marcellus differentials in the solar [Indecipherable], we expect gas realizations blow 100% of Nymex [Phonetic]in the third quarter. Finished 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. Cash 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 of 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 is slightly above Street expectations as we saw [Indecipherable] 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 a 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 revolver borrowings ended only slightly lower quarter-over-quarter at a function of $17 million deposit on our Williston acquisition, as well as over a $30 million reduction in our 2028 notes. In aggregate, leverage was still down on an absolute and ratio basis, with an LQA ratio of one times. Leverage will tick up slightly next quarter with the Williston acquisition closing, but the ratio should still be well below one times 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 of revolver will be undrawn by mid next year despite funding the Williston acquisition this year while 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. The $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, most of the filler targets in 2023 and 2024 and the top up volumes from our recent acquisitions. We continue to target hedging around 60% of production on rolling 18-month basis with select long-dated hedge [Indecipherable] 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 to 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 the 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 in our full-year guidance to $4.50 to $5.25 per barrel. We’re bumping up our gas realization guidance. We do expect lower realizations in the second half of 2022 as I mentioned earlier.

From 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 for 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.

Questions and Answers:

Operator

Thank you. [Operator Instructions]. Our first question is from Neal Dingmann with Truist Securities. Please proceed.

Neal Dingmann — Truist Securities. — Analyst

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.

Nicholas O’Grady — Chief Executive Officer

I think it just comes down to capital allocation and kind of a risk-adjusted return. I think you know usually when you run it as a pure corporate finance perspective, both on this Ground Game, still some of the highest returns. 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. 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-prong kind of all the above approach.

Neal Dingmann — Truist Securities. — Analyst

Glad to hear that. And then second question on competition specifically. Could you discuss kind of today’s industry competition such as from maybe specs or other players versus what you saw several quarters ago when you took over?

Nicholas O’Grady — Chief Executive Officer

Sure. Yeah, I mean like any other cycle, we definitely see pockets of competition here and there. In the current environment, we’ve seen some competition for a very small interests and on the larger side of transactions for PDP heavy properties that’s find by us. 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 ‘cap rate.’

This of course assumes you have an accurate view of the PDP declines, cost structures to be truly safe investments. On sizable concentrated Ground Game assets and in the larger packages, we always have some competition but fine — we remained highly competitive. Our biggest competition is generally the whole case and-or unrealistic development expectations. Sometimes, we feel like we know too much that we lose assets because buyers maybe miss modeling the reserves cost or development timing. We’re fine to lose if that’s the case. As for stacks [Phonetic], etc., all I would say is that there is 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. And it’s not just a switch you simply pull. So stacks have an inherent misalignment, which are designed to give free value to the sponsor in the form of a zero basis for [Indecipherable] and for the seller to be able to dictate the price of the sale into the stack rather than let the market and investors decide what those assets are worth, which begs the question as to why he would choose that path and I think the answer is obvious, which is that the value you get at least initially is self-selected in much higher than the market will bear. When I was a kid, my brother and I would build sand castles 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 has 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.

So I don’t perceive this is real competition. I think as a team, we 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.

Neal Dingmann — Truist Securities. — Analyst

Great details and always waiting to love these analogies.

Nicholas O’Grady — Chief Executive Officer

Every quarter, buddy.

Operator

Our next question is from Derrick Whitfield with Stifel. Please proceed.

Derrick Whitfield — Stifel — Analyst

Thanks and good morning all and make a love of that analogy.

Nicholas O’Grady — Chief Executive Officer

Thanks. I work hard for new one.

Derrick Whitfield — Stifel — Analyst

With my first question, I wanted to focus on the production trajectory for Q3 and Q4 and thinking about the production outages in Q2 and the acquisition that will close in Q3. We had oil production increasing about 4,000 barrels in Q3, and then another 3,000 barrels in Q4. Does that seem about right?

Nicholas O’Grady — Chief Executive Officer

Let me — I think, we’re only going to have — on the Wilson acquisition, only going to have, let’s call it 45 days or so [Indecipherable] going to close in mid-August, the effective date goes back, but that will be in the purchase price settlement. We will get that cash flow but it will not be in the form of production. I think we see steady ramp, but I think you’re going to have in the fourth quarter, you’re going to have a much depending on the timing, Derrick, you’re probably going to see the largest impact from completions, just because even if we have a very aggressive time schedule in Q3,you’re only going to get a portion of that volume. Jim, I do not know you want to comment towards that.

Jim Evans — EVP and Chief Engineer

Yeah, Derrick, it’s Jim. We’ve got some pretty large pad in the Williston right now that are working through. We expect those to be mostly towards late Q3, early Q4. Last one, we’re kind of expecting our big ramp in production [Indecipherable], which is obviously our highest oil-cut area. So, we kind of expect to be later towards the end of the year that we see that big ramp.

Derrick Whitfield — Stifel — Analyst

Terrific. And then 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 elections?

Adam Dirlam — President

Yeah, I think it’s a combination of the operator mix and operators remaining disciplined. We’re not seeing necessarily the step outs that we’ve seen and [Indecipherable] in the past and so you’ve got our low cost and what we would consider some of our best top three operators contributing to that [Speech Overlap].

Nicholas O’Grady — Chief Executive Officer

Yeah, obviously, a lot of the stuff that came on in the first half of the year was well to be elected to 2022 where oil prices were a little bit lower. So operators were still kind of sticking to that core. As we’ve gotten into 2022 here with high prices, we’ve seen some operators start to step out a little bit. So we would expect some well performance degradation towards back half of the year in 2023, but so far we’re very pleased with the performance that we’re seeing.

Derrick Whitfield — Stifel — Analyst

Terrific. Very helpful and thanks for your time.

Operator

Our next question is from Austin [Indecipherable] with Johnson Rice. Please proceed.

Austin — Analyst

Good morning, Nick and to your team. Thank you for taking my questions. Well, the first question. First question is Northern seems to be one of the few companies who are not having to increased capex outlook due to inflation. Can you provide some color on how you set your inflation expectations at the beginning of the year?

Nicholas O’Grady — Chief Executive Officer

Yeah, I mean I think the simplest is part of that we baked in inflation this year, but we also didn’t bake in deflation in 2021. So we effectively were running cost structures from pre-pandemic. We never really change that forecast and then added inflation on top of it. So as it stands today, the only cadence and frankly for this quarter in particular — the only cadence 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 the lumpy success that you have in the Ground Game when you’re acquiring because when you acquire the acreage or and the wellbores, you’re accruing immediately for the capitals of the wells happen process. It might not cost very much money but you’re booking all the cost of those wells process and so that’s why it can be quite lumpy.

But frankly as it stands today, we’re really comfortable with the guidance where it is if we had a material acceleration in development, it’s still won’t really change that. It just changes that the timing of that within the year. But we’ve been right in the middle of the goalposts pretty much all year and I just think the thing is that what 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. And we spent a lot of time, particularly at the end of last year as we were looking towards this because we had a fairly grave assessment for what we were seeing in terms of where cost ultimately were going to go and we do expect costs to continue to increase throughout the year. But as you could note from our average AFE costs, we’re still nearly $1 million well below where we’ve effectively budgeted it but, that’s our average for the year, but we actually budgeted for higher than that as you go throughout the year.

Adam Dirlam — President

That’s a function of the operating partners that we actively manage to participate with, right. And so we have an idea of our operating partners cost structure, their propensity to overrun. And using that data in 2020 moving into 2021 and into 2002, you can leverage that and structure around it.

Austin — Analyst

I appreciate the color. And then as a follow-up, how would you prioritize your cash return to our shareholders. Is a top priority buying back the preferred shares followed by the increase in the base dividend and debt reduction and finally, repurchasing our common shares.

Nicholas O’Grady — Chief Executive Officer

I don’t know if it’s that simple because I think it’s really opportunistic. I would say 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. So the cost of capital difference between them is relatively de minimis at this point in time. So I think common stock has gone up. I think we still — we are risk-averse group and so debt reduction is still plays a big role and I think there is a difference between paying down debt and buying in your bonds in the sense that to the extent that high-interest, high 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. So that actually has an impact of the equity value as well as the overall debt levels. So 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 at 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 — so we don’t really want to go down either one of those paths. We have no interest in being an upstream MLP of old. But I think we will be very, very flexible and 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.

Austin — Analyst

Okay, thank you. That’s all from me.

Operator

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

John Abbott — Bank of America — Analyst

Good morning, guys.

Nicholas O’Grady — Chief Executive Officer

How are you?

John Freeman — Raymond James — Analyst

Good, thanks. First question, if I heard you right, and I think you said that you’ve got just a lot of opportunities in the pipeline for acquisitions in Delaware, Midland and Williston Basin and I didn’t hear you mention the Marcellus. And I’m just wondering if that’s by design or it’s just other got really competitive. Is there any other reasons why that one wasn’t mentioned.

Adam Dirlam — President

No, I mean, two or two potential acquisitions this year in the Marcellus, they just weren’t a fit. I think my prepared comments were around 13 processes that are effectively current right now and so we’ve run those out kind of quarter and kind of put those to bed. So we’re actively looking. It’s just a matter of not being a fit at the moment.

Nicholas O’Grady — Chief Executive Officer

Yeah. And we had one Marcellus prospect that was exciting to us. It did not trade John [Speech Overlap]. to be candidate.

John Freeman — Raymond James — Analyst

The old whole case.

Nicholas O’Grady — Chief Executive Officer

The old whole case came to buy this [Indecipherable].

John Freeman — Raymond James — Analyst

So, the followup I had. It’s kind of prior [Indecipherable] questions. Nick you answered. You have obviously done a great job managing the cost line whilst everybody in the space has continued capex and may not hold you to this, but just show I can have better insights than just about anybody given the number of operators and cost the basins that you are in and give sort of an idea of what you would assume just as it stands now. What you would assumes a reasonable cost inflation number to plug in for next year?

Nicholas O’Grady — Chief Executive Officer

It/s difficult to know in the sense that I can certainly tell you how we see it exiting. But I think if oil prices are $50 next year, it’s going to be a very different answers. I think it will be very presumptuous to make the assumption. I mean I think ceteris paribus if cost increases tend to be sticky and so — I think we’ve got about [Indecipherable] about 15% between now and the end of the year total. That’s right.

Jim Evans — EVP and Chief Engineer

Yeah, yeah.

Nicholas O’Grady — Chief Executive Officer

I guess the way that I kind of frame it up is it’s going to depend on your operating partners. It’s going to depend on your working interest associated with them. So as we get towards the end of the year and kind of frame up and have a better idea of the cadence or kind of tilt and whatever else is got in the backlog in terms of AFEs, that we’ll be drilling into that we’ll be able to better frame that up.

John Freeman — Raymond James — Analyst

I appreciate the answers, guys. Well done.

Operator

Our next question is from John Abbott with Bank of America. Please proceed.

John Abbott — Bank of America — Analyst

Good morning, guys. Thank you for my questions. Sort of similar along the lines of the prior question on inflation, but given the pivot, it seems towards going with larger companies versus smaller companies. Can you provide any sort of color on the difference between AFC cost between a larger operator and a small operator at this point in time?

Adam Dirlam — President

Variability is certainly why in the Permian just given the number of different operators who have relative to Williston. I guess the only other thing that I would qualify with this, we’re not necessarily just focused on well costs, right. I mean we’re solving for a required rate of return and so it’s going to also be to take into consideration completion methodologies, offsets all of those types of technical aspects to it. So we’re happy to elect to maybe above average AFE to the extent that it’s going to meet our hurdle rates.

John Abbott — Bank of America — Analyst

Appreciate and it sounds — 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, but if you had to guess at this point in time where do you think maintenance capex just sort of thinking about inflation is overall and if you do have the color, what do you think about in terms of your various areas.

Nicholas O’Grady — Chief Executive Officer

Well, when you say maintenance capex, once the production level as you’re picking right? Is it our [Indecipherable].

John Abbott — Bank of America — Analyst

Let’s just choose the 77,000 BOE per day exit rate potentially, somewhere around there.

Nicholas O’Grady — Chief Executive Officer

Yeah, I mean that’s a 58 to 62 wells probably, so but remember, it’s going to be yeah, that’s call $450 million to $500 million hand waving. But again, I think it’s a little early to kind of make those assumptions.

John Abbott — Bank of America — Analyst

I understand. Okay, thank you very much for taking my questions.

Nicholas O’Grady — Chief Executive Officer

Yeah. Welcome.

Operator

Our next question is from Noel Parks with Tuohy Brothers. Please proceed.

Noel Parks — Tuohy Brothers — Analyst

Hi, good morning. You know maybe as a subset of the discussion about what you think about cost trends. I’ve been hearing here and there from operators that they are starting to see a little bit of trouble with materials delivery and with that sort of backing its way up into slowing completion. So, even though the estimated cost are different, they’re just trying to see that that bit of schedule padding or scheduled slippage. I’m just wondering are you hearing about anything like that any of your region.

Nicholas O’Grady — Chief Executive Officer

Absolutely. And I think we’ve seen material delays as much as six months on pads and what I’d say is, if I remember when I looked at June, I think we had an entire net wells or excuse I half net well delayed and one well that came on six months early. So, it always a push and pull there. There are always delays. The fields are very, very tight statistically speaking, it hasn’t really been a major issue for us.

Adam Dirlam — President

Oh, it’s the beauty. The diversification in the 500 wells that we have in process, right. So we don’t have one particular operator creating a big problem for us to the extent that they’ve got a big problem for themselves.

Nicholas O’Grady — Chief Executive Officer

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. Budget and on schedule.

Noel Parks — Tuohy Brothers — Analyst

Got you. And I — there definitely has been an air of caution among operators as far as committing or even previewing what their expectations are for 2023. I guess I’m just thinking in your view if say, pick a number, you know, by this time next year, we are 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 and then others have been saying that they do you see signs of new equipment coming online from the service companies, not at the pace that you will have seen in the past blooms, but that sort of the steady trickle is on the way. Again, just wondering if you had any insight on that?

Nicholas O’Grady — Chief Executive Officer

I mean I think that follow the money. I think I’ve been involved in the energy business for 22 years now. I’ve never seen a cycle in which a service provider makes a ton of money in with relatively low barrier sanctuary and new equipment doesn’t enter in the market. So, yeah, this won’t go on forever. There is no, as I think I said this in the last call, there is no shortage of the ability to make steel, pipe and sand [Indecipherable] or frankly to make a pressure pumping unit. It’s really just time and fixing some of those issues that are plaguing frankly the entire world economy. So I have a lot of optimism that this in time will pass and frankly 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 see weakness in pricing, you will see slowing activity if delays become so rampant, then ultimately that will become self-defeating to some degree. So yes, I think that there will be a peak, which is next year or this year, I’m not sure. 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 eventually capitalism is a beautiful thing they usually do.

Noel Parks — Tuohy Brothers — Analyst

Right. Great, thanks a lot.

Operator

[Operator Instructions]. Our next question is from Nicholas Pope with Seaport Research. Please proceed.

Nicholas Pope — Seaport Research — Analyst

Hello, everyone. 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 was a pretty big jump and in Permian, it’s kind of a split and is that really the opportunity set? Is that we’re you’re seeing kind of the returns are driving that capex or is that kind of the rate we should expect just kind of a split between these three assets right now.

Nicholas O’Grady — Chief Executive Officer

Nick. We had guided I think 45, 45 and 10 for the year and I looked at it yesterday and it’s about the same [Indecipherable] I think it’s just cadence of development. If try to look at our ads during the quarter, then looking at kind of our working interest between the Permian and the Williston, our average working interest in North Dakota was around 8% whereas our Permian around 80%.

Nicholas Pope — Seaport Research — Analyst

Got it. Okay, that’s all I had. I think most everything else have been asked. Thanks guys.

Nicholas O’Grady — Chief Executive Officer

Sure. You don’t want to ask another?

Operator

There are no more questions at this time. So, I would like to turn the conference back over to management for closing comments.

Nicholas O’Grady — Chief Executive Officer

Thank you all for joining us today. We very much appreciate your interest and we’ll see you next quarter. Thanks.

Operator

[Operator Closing Remarks]