Northern Oil & Gas, Inc. Q2 FY2022 Earnings Call

Greetings. Welcome to Northern Oil'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. 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. 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 5 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. And 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 disciplined, 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 multipronged 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 discount to 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 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. C, 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. D, finally, actions speak louder than words. Our successful execution of acquiring and integrating accretive acquisitions has driven our free cash flow to record levels, and 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 1/3 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 widths. 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 2-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 of service providers. Our active management of the portfolio on the buy side has provided us with the ability to forego 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 gain 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 3/4 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 LNG has scaled up and diversified over the last 18 months, the breadth of opportunities that we are 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. 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 sellers' market, we continue to source unique opportunities, and we remain disciplined in only pursuing acquisitions that meet or exceed our return thresholds.

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 32% 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 the 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 continue to remain strong in Q2, which is leading to the increase in our annual guidance for gas utilizations. 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 utilizations below 100% of NYMEX in the third quarter. Fixed 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 occurrence 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 for costs associated with a 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 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 field 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, that's 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 durational 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 to 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 of $1.3 billion and $850 million, respectively. That, coupled with our free cash flow, means that 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 hedging time 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 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 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 to $5.25 per barrel. Bumping up our gas realization guidance, we do expect lower realization in the second half of 2022 as I mentioned earlier. 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.

Our first question is from Neal Dingmann with Truist Securities.

Nick, my first question is on capital allocation. Specifically, your thoughts on balancing our suggested dividend and other shareholder return plan with what looks to be continued very opportunistic ground game.

It really comes down to how we allocate capital and the risk-adjusted returns associated with it. Typically, from a pure corporate finance standpoint, bolt-ons and ground game still offer some of the highest returns. As multiples and valuations have decreased, our own securities and dividend strategies have started to compete more significantly. We've designed this plan to provide a lot of flexibility, and we've been increasing our focus on it, especially as new opportunities arise. Ultimately, it's a multipronged, comprehensive strategy.

I'm glad to hear that. For my second question regarding competition, could you discuss?

I mean, like any other cycle, we definitely see pockets of competition here or there. In the current environment, we've seen some competition for very small interests. And on the larger side of transactions for PDP heavy properties, that's fine 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 in cost structures to be truly safe investments. On sizable concentrated ground game assets and the larger packages, we always have some competition, but find that we remain highly competitive. Our biggest competition is generally the hold case and/or 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. We're fine to lose if that's the case. As for SPACs, etc., all I would say is that 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. And 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 0 basis promote. And 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 castles 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 5 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. And I always love these analogies.

Every quarter.

Our next question is from Derrick Whitfield with Stifel.

Nick, I love that analogy. 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 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 we're only going to have, on the Williston acquisition, we're only going to have let's call it 45 days or so, Derrick, when we close in mid-August. The effective date goes back, but that will 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 going to have, in the fourth quarter, you're going to have a much, depending on the timing of WPX, you're probably going to see the largest impact from completions just because even if we have a very aggressive turn-in-line schedule in Q3, you're only going to get a portion of that volume. Jim, I don't know, you want to comment towards that?

Yes, Derrick, it's Jim. We've got some pretty large pads in 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 from Williston which is obviously our highest oil cut area. We expect it to be later towards the end of the year that we see that big ramp.

Terrific. And then just 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?

I think it's a combination of the operator mix and operators remaining disciplined. We're not seeing necessarily the step-ups that we've seen in oil runs in the past. You've got our low-cost and what we would consider some of our best, top 3 operators, contributing to that. I don't know, Jim, do you want to add anything?

Yes. I would say a lot of the stuff that came on in the first half of the year as well as what was elected to in 2020 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. We would expect some well performance degradation towards the back half of the year and into 2023. But so far, we're very pleased with the performance that we're seeing.

Our next question is from Austin Aquane with Johnson Rice.

First question is, Northern seems to be one of the few companies who are not having to increase CapEx outlook due to inflation. Can you provide some color on how you set your inflation expectations at the beginning of the year?

Yes, the simplest explanation is that we accounted for inflation this year, but we did not account for deflation in 2021. We were operating under cost structures from before the pandemic and didn't adjust that forecast, instead adding inflation on top of it. Currently, the only factors that could really change this for this quarter are if there's a pull forward of activity, which essentially borrows from future quarters, or if we see variable success in our acquisition efforts. When we acquire acreage and wellbores, we immediately accrue for the capital, and while the processing of wells might not cost much, we still record all costs associated with those wells in progress, which can lead to variability. However, we feel comfortable with our current guidance. Even with a significant acceleration in development, it would primarily shift the timing within the year rather than change the overall outlook. We've consistently aligned with our targets throughout the year. Historically, we strive to look beyond immediate costs and have invested considerable time, particularly at the end of last year, to assess future cost trends, expecting them to rise throughout the year. Nevertheless, our average exploration and production costs remain about $1 million per well below our budget, even though we budgeted for higher expenses as the year progresses.

And that's a function of the operating partners that we actively manage to participate with. We have an idea of our operating partners' cost structures, their propensity to overrun. And using that data in 2020 moving into '21 and into '22, you can leverage that and structure around it.

I appreciate the color. And 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 base dividend, then debt reduction and finally, repurchasing out of common shares?

I think the situation is more complex than it appears because it's very opportunistic. The preferred stock currently has value. The gap between preferred and common stock is narrowing, particularly as our common dividend rises. The difference in the cost of capital between the two is minimal at this moment. The value of common stock has increased. We are a risk-averse group, so reducing debt remains a significant focus. There’s a distinction between paying off debt and buying back bonds; the high Fed funds rate leads to lower bond prices, meaning we’re not only reducing debt but also enhancing enterprise value by buying at a discount. This affects both our equity value and overall debt levels. We strive to remain flexible. A stable and growing dividend is crucial to us, and we are conscious of managing yield expectations. Low yields can be problematic, as can very high yields, so we want to avoid both extremes. We have no desire to revert to being a traditional upstream MLP, but we aim to maintain high flexibility. We have established systems from both an authorization standpoint and within our internal processes to allow us to act opportunistically.

Our next question is from John Freeman with Raymond James.

First question, if I heard you correctly, Adam, I believe you mentioned there are many opportunities for acquisitions in Delaware, Midland, and the Williston Basin. However, I didn't hear you bring up the Marcellus. I'm curious if that's a deliberate choice, or if it's due to increased competition, or other reasons why it wasn't included.

We've looked at 2 or 3 potential acquisitions this year in the Marcellus. They just weren't a fit. I think my prepared comments were around kind of the 13 processes that are effectively current right now. We run those out kind of quarter and kind of put those to bed. We're actively looking. It's just a matter of not being a fit at the moment.

Yes, and we have one Marcellus prospect that was exciting to us, it just didn't trade, John, to be candid.

The old hold case.

The follow-up I had, it's kind of on the prior line of questions, Nick, that you answered. You've obviously done a great job managing the cost line while most everybody else in the space is having continued CapEx increases. And I may not hold you to this, but just you're all going to have better insights than just about anybody given the number of operators and across the basins that you are in. I mean, do you have 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 hard to predict, as I can certainly share how we view the situation currently. However, if oil prices are $50 next year, the answer would change significantly. It would be quite presumptuous to make that assumption. Generally speaking, cost increases tend to be sticky. I believe we have around a 15% increase expected from now until the end of the year, is that correct, Jim?

Yes, that's about right. 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. 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 deals and whatever else is kind of in the backlog in terms of AFEs that will be drilling into that, we'll be able to better frame that up.

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

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 AFE cost between a larger operator and a smaller operator at this point in time?

I've seen just from anecdotally, John, and I'll let the smarter people in the room answer the rest of this, but when we've seen kind of stand-up rig operators looking for development capital in the Permian, $2 million to $3 million a well difference. And that's because they're paying spot prices for every single item. They're borrowing the rig, they're borrowing the frac crew. We've seen at least one AFE that was $16 million for a two-mile lateral. We did not participate in that.

The variability is certainly why 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 that we're not necessarily just focused on well costs, right? I mean we're solving for a required rate of return. It's going to also need to take into consideration completion methodologies, offsets, all those types of technical aspects to it. We're happy to elect to maybe above average AFE to the extent that it's going to meet our hurdle rates.

Thank you. The second question is about maintenance capital expenditures. It seems like you have a strong trajectory at the end of this year, which could impact your spending in 2023. If you had to estimate right now, what do you think maintenance capital expenditures will look like, considering inflation? Additionally, do you have any insights regarding this in relation to your various areas?

Well, when you say maintenance CapEx, what's the production level you're picking, right?

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

Yes. I mean that's 58 to 62 wells probably. But remember, it's going to be let's call it $450 million to $500 million handwaving. Again, I think it's a little early to kind of make those assumptions.

Our next question is from Noel Parks with Tuohy Brothers.

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're starting to see a little bit of trouble with materials delivery and with that sort of backing its way up into slowing completions. Even though the estimated costs aren't different, they're just starting to see that there's schedule padding or schedule slippage. I'm just wondering, are you hearing about anything like that in any of your regions?

Yes, absolutely. And I think we've seen material delays as much as 6 months on pads. What I'd say is, if I remember when I looked at June, I think we had an entire net well, or excuse me, half of a net well delayed and 1 well that came on 6 months early. It's always a push and pull. There are always delays. The deals are very, very tight. But statistically speaking, it hasn't really been a major issue for us.

Well, and that's the beauty of the diversification and the 500 wells that we have in process, right? 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.

Yes, 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 and they cost more, and that's why we are where we are at this point in the year with roughly a budget on schedule.

Got you. And 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 they pick a number 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 we are paying the most we’ve ever paid for services in a particular basin. And then 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 blooms, but that sort of steady trickle is on the way. Again, just wondering if you had any insight on that.

I think that follow the money, I think I’ve been involved in the energy business for 22 years now, and I’ve never seen a cycle in which the service provider makes a ton of money with relatively low barriers to entry and new equipment doesn’t enter the market. So yes, this won’t go on forever. There’s no – 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, just make a pressure pump even. It’s really just timing and 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. And frankly, what I would say is that there are a lot of other risks that can solve those issues for you, right, the 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 within the 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.

Our next question is from Nicholas Pope with Seaport Research.

I was curious if you could kind of expand a little bit looking at kind of the split of CapEx spending in 2Q? There's a pretty big jump in Permian as kind of a split. And 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 splits between these three assets right now?

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 for annual. I think it's just happenstance.

Yes, I think it's just cadence of development. If I look at our adds during the quarter, been 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 was around 18%.

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.