Northern Oil and Gas, Inc. (NOG) Earnings Call Transcript & Summary

Greetings, and welcome to the Northern Oil Fourth Quarter and Year-End 2022 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Evelyn Infurna, Vice President of Investor Relations. Thank you, Evelyn. Please go ahead.

Thank you, Paul. Good morning, and welcome to our fourth quarter 2022 earnings conference call. Yesterday after the market closed, we released our financial results for the fourth quarter and fiscal 2022. You can access our earnings release and presentation on our Investor Relations website and our Form 10-K will be filed with the SEC within a few days. I'm joined here this morning by NOG’s Chief Executive Officer, Nick O'Grady; our President, Adam Dirlam; and 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 provide his remarks on the quarter and on our recent accomplishments, and Adam will discuss an overview of operations, and Chad will review our fourth quarter financials and walk through our 2023 guidance. After our prepared remarks, the executive team will be available to answer any questions. Before we go any further, let me cover our safe harbor language. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by our forward-looking statements. Those risks include, among others, matters that we've discussed 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'll turn the call over to Nick.

Thank you, Evelyn. I'd like to take a few moments to welcome Evelyn to the NOG team. Evelyn comes to NOG with tremendous amounts of capital markets and investor relations experience, and we're excited to have her on board. All right, I'll get down to it with 5 key points. Number one, business fundamentals are strong. We delivered strong results in the fourth quarter and the full year. Despite lower commodity prices and severe weather, we generated approximately $90 million of cash in the fourth quarter and still were within our annual production guidance. As we enter Q1, the business is back online and building momentum driven by strong turn-in-line activity in December. Number two, growth. The fourth quarter was incredibly busy for the company. We closed on 3 Permian acquisitions and in the first week of January, we closed on our Midland Petro transaction. In total, these represented over $750 million of closings and over $900 million in acquisitions announced in 2022, which should translate into more than 20% growth in our year-over-year production on a reduced diluted share count. This is following roughly 40% growth in 2022, all the more impressive given we are in a low growth era for most public energy companies. As the largest, best-capitalized non-operator with superior data insight and an unmatched track record, we are proud to be the preferred partner to the public and private upstream community. NOG's differentiated positioning sets the stage for significant relative and absolute outperformance in 2023. We have transformed the company by diversifying and growing our footprint, enhancing the quality of our portfolio and meaningfully improving the strength of our balance sheet. Despite inflationary pressures and lower current commodity strips, we expect to generate significant cash flow and production growth in 2023. Our disciplined and efficient transaction underwriting, prudent and sophisticated capital formation and superior data insights have driven, and we expect will continue to drive consistent multiyear equity outperformance. Number three, the 2023 outlook. Our 2023 guidance, which Chad will delve into later reflects capital efficient growth, conservative cost inflation assumptions and as I just mentioned, significant and differentiated volume and cash flow growth throughout the year. At our new elevated level of baseline production, we expect to generate significant levels of free cash flow in 2023. As the Midland Petro project reaches completion, it sets the stage for a substantial increase in free cash flow in the coming years, enabling us to further accelerate the company's growth and enhance shareholder returns. Number four, competitive advantage. We believe our competitive advantage has expanded in 2022. Over the last 4 years, we've not only rebuilt our infrastructure, augmented the financial strength and improved the asset positions of the company but have also invested in data science to continuously improve our technical analysis. With the launch of our purpose-built AI-powered system in January, we expect to further enhance the power of our proprietary data and the accuracy and efficiency of our decision-making. More specifically, we believe our enhanced analytics will enable us to efficiently find differentiated value in properties to further enhance our risk management tools. Our team does not rest on its lolls and we believe we are unmatched in the non-operated sphere, given our scale, data analytics and underwriting advantages. We believe that few can compete with us for the high-quality properties that we target daily, and our scale allows us to play in a field largely on our own. As the breadth of opportunities has expanded for us both from a basin and structural basis, our competitive advantage has only widened. 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 share repurchase programs, repurchasing high-cost debt and increasing the cash dividends for our common shareholders. During the fourth quarter, we continued to tactically repurchase our common stock and senior notes. As market opportunities allow, we will continue opportunistic common buybacks and debt repurchases throughout 2023 and beyond. A few weeks ago, we announced a 13% increase in our quarterly common stock dividend to $0.34 per share for the first quarter and introduced a plan to accelerate the dividend further to our target of $0.37 per share, about 2 quarters ahead of schedule. We continue to have 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 our shareholders and our equity value over the long term. Our [ Goldilock ] strategy should give us the ability to both pay healthy, growing current income to our shareholders and also allow for our significant excess retained cash flow to provide for value-added bolt-on acquisitions and growth opportunities. Going forward, we remain focused on driving the highest total return to shareholders, focusing on optimal yield, tax and capital efficiency and management of our overall leverage levels. The good news is with the business positioned for strength, we anticipate being able to deliver continued growth to our returns while still leaving room for flexibility and the ability to scale the business responsibly over time. 2022 was another evolutionary leap forward for NOG, and I want to recognize the NOG team from top to bottom for their hard work and dedication to all we've accomplished. In closing, I'll remind you, as I always do, that we are a company run by investors for investors, and I want to thank you all for taking the time to listen to us today. With that, I'll turn the call over to Adam.

Thanks, Nick. On both the operational and business development fronts, we finished off another transformational year and look to continue our growth trajectory into '23. In the fourth quarter, turn-in-lines beat our internal forecast as we added nearly 20 net wells and completions returned to a relatively balanced mix as the Williston and Permian accounted for a 60-40 split. While initial production results were outperforming internal estimates, winter weather in December impacted production by approximately 10,000 barrels a day. As normal operations return, we expect to receive much of the benefit of our fourth quarter adds moving into the first quarter. Looking further ahead, we anticipate a typical turn-in-line schedule with spuds front-end loaded and completions weighted toward the back half of the year. Given the pull forward in well completions during the back half of '22, our wells in process finished the year totaling 55.4 net wells, with the Williston accounting for roughly 80% of our WIPs excluding our Marcellus DUCs. That said, we added 6.8 net wells in process with the closing of our Mascot project in January. And accordingly, we now expect new drilling activity levels to be equally weighted across the Permian and Williston for 2023. In the Marcellus, we have deferred most activity to 2024 as we focus on higher-margin oil properties, but continue to look for ways through acreage trades and other means to potentially add exposure in the back half of the year. Q4 well proposals on our organic acreage remained healthy as we received over 125 AFEs during the quarter, which accounted for roughly 10 net wells. The combination of our operators staying disciplined and our acquisitions focused on the core of our respective basins, led to a consent rate of approximately 95%. Economics also continued to improve as we saw estimated IRRs increase by over 25% relative to our Q3 well proposals. As we think about well costs going forward, it has been encouraging to see a deceleration in inflation, which broadly aligns with the conversations that we've had with our operators. We do expect and have seen some creep from some of our lowest cost operators in the Williston as long-dated service contracts roll off. This has been offset by a steadier state in the Permian, which has kept our overall AFE inflation modest. We anticipate those minimal increases from leading-edge indicators at year-end to carry over into 2023, which results in an estimated 7.5% inflationary increase at the midpoint. As Nick alluded to earlier, the fourth quarter was extremely busy for the business development team as we work to close some of the most impactful acquisitions in company history. The $750 million of M&A completed in Q4 and Q1 has deepened our exposure to top-tier inventory with the addition of approximately 8,000 net acres in the Permian. Overall, our 2022 closed acquisitions and ground game activity added approximately 125 high-quality, low breakeven net future locations to our inventory and 15% to our proven reserves, which increased to an estimated net 330 million barrels of oil equivalent. Note that our year-end reserves exclude the impact of the recently closed Midland Petro acquisition. Midland Petro represents an important evolution in our M&A strategy. The transaction showcased Northern's scale and ability to provide creative capital solutions for our operating partners, while generating best-in-class returns. On the heels of our announced joint development agreement, we have been approached by multiple operators trying to find solutions for existing assets and desired development plans as well as partnership opportunities to co-bid and acquire operated assets. Not only are we one of the few non-operators with scale and a balance sheet to help move the needle pursuing large-scale acquisitions, we also have the data insights to underwrite with conviction and participate alongside our operators as a load maintenance partner. These competitive advantages have established NOG as a partner of choice in pursuing operated assets and at the same time, broaden the opportunity set available to us. As we move into 2023, the M&A backlog is spooling, and we are reviewing more than $5 billion in non-operated packages, operated packages and joint development opportunities. While there are more prospects than ever available to us, our colors have not changed. We remain laser-focused on our consistent approach to capital allocation and our ground game. In the fourth quarter, we closed on 1.2 net wells and 127 net acres, finishing our 2022 ground game efforts, acquiring 8.7 net wells and over 1,400 net acres across 24 transactions. As we look ahead to 2023, we are seeing a variety of compelling opportunities across our respective basins, and we will actively manage the portfolio in order to build on an already high-graded drilling program and maintain our superior return on capital employed. With that, I'll turn it over to Chad.

Thanks, Adam. I'll start by reviewing key fourth quarter results, which were solid across the board despite the impact of the recent winter storms. Our Q4 average daily production was 78,854 BOE per day, a 23% increase compared to Q4 of 2021. Oil volumes were up 4% sequentially over Q3 and have normalized after the winter storms. Our adjusted EBITDA was $264.8 million in Q4 and topped $1 billion for the year, a record for our company. Our fourth quarter free cash flow was robust at $87 million despite growing activity, and we generated almost $460 million of free cash flow in 2022, which is more than double the prior year. Our adjusted EPS was $1.43 per share in Q4, up roughly 35% year-over-year. Oil differentials were again better than internally expected in Q4 and came in at $2.42 per barrel due to continued strong in-basin pricing and having more barrels weighted towards the Permian, which are typically priced tighter. For the year, our differentials were $2.73 off WTI, a record low for the company driven by improvements in North Dakota and the diversification of our business over the last several years. Natural gas differentials were 92% of benchmark prices for the fourth quarter, lower sequentially but better than our internal expectations. Lower natural gas and NGL prices drove the reduction, a function of lower gathering cost absorption and lower NGL uplift. For the year, they averaged 113% of NYMEX. On the CapEx front, we invested $142.9 million during the quarter, evenly split between the Williston and Permian basins. Activity has been robust. As Adam mentioned, Q4 turn lines were up dramatically from the third quarter and provide strong momentum as we enter 2023. This has resulted in a DMC list of 62.2 net wells inclusive of the Mascot project and has contributed to the pull forward of our capital spending, along with the continued success of our high-return ground game investments. The balance sheet remains strong. We closed a $500 million convertible notes offering in the fourth quarter to fund in part our recent acquisitions. As you may recall, due to the features we selected, there will be minimal to potentially 0 dilution to our existing holders. And to the extent there is, the company has options to manage this over time. In addition to the convertible notes offering, we were able to expand the capacity of our revolving credit facility to $1 billion from $850 million, reflecting the growth in our borrowing base to $1.6 billion from $1.3 billion. As a result of our M&A activity, we flexed our balance sheet for the announced transactions in the fourth quarter, and our leverage will be modestly higher over the next couple of quarters but well within our comfort zone. Our net leverage ratio should return to normal levels by the end of 2023 as our acquisitions contribute to our operations and we're able to organically [ delever ]. Liquidity remained strong. We still have over $1 billion of dry powder in the form of unused revolver and borrowing base capacity. In 2022, we retired $25.8 million of our 2028 notes, and we'll continue to look for ways to efficiently reduce leverage if market opportunity arises. With respect to hedging since our last report, we opportunistically added volumes in the form of attractive costless collars that provide downside protection with the optionality of participating in the upside of prices rally. We continue to hedge volumes from each closed and pending acquisition based on our conservative hedging strategy of 55% to 65% of expected production on a rolling 18-month basis. As it pertains to our 2023 guidance, with our run rate CapEx from 2022 of approximately $500 million largely carrying over, capital plans from our 2022 acquisitions of approximately $220 million layered in and $25 million to $50 million of service cost inflation. This translates to a range of $737 million to $778 million total CapEx guidance for 2023. From a [indiscernible] perspective, we expect approximately 60% of our annual spend will occur in the first half of the year. I want to point out that only approximately $25 million to $60 million that is specifically associated with the build-out of our Mascot project is expected to reoccur in 2024. We do expect to see continued inflation in the first half of 2023, but the decline in natural gas prices and subsequently what appears to be the beginning of a reduction in overall rig count, which is down approximately 25% from the peak in the United States could lead to cost savings in 6 to 9 months if the current trend stays in place. Additionally, we've seen debottlenecking in sand tubulars and added pressure pumping capacity, all green shoots towards stabilization or reduction in costs as the year progresses. Regarding our 2023 production guidance, we expect to start the year at a range of 84,000 to 86,000 BOE per day in Q1, improving each quarter with a target fourth quarter exit rate of 96,000 to 100,000 BOE per day. Overall, the quarterly production should translate to an average range of 91,000 to 96,000 BOE per day for the full year. With respect to the first quarter, we typically see seasonal organic declines and accordingly guide conservative given the end of winter in the Williston. However, we do expect strong activity throughout the year to drive that higher exit. On differentials, we're taking a conservative view given the recent downtick in natural gas prices and typical volatility of in-basin oil pricing. We believe that there's room for improvement potentially as the year goes on. LOE and G&A should be largely consistent with 2022, adjusted for inflation and operating and public company costs. With that, I'll turn the call over to the operator for Q&A.

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

My first question for Chad, this is on capital spend or maybe specifically, we're modeling, how should we think about your '23 CapEx sort of pre and post potential transactions? Or maybe asked another way, do you all assume there'll be at least a minimum amount of ground game additions that we should put in the model and just really trying to speak to CapEx versus production expectations this year.

We always leave room in our CapEx guidance for flex capital. So the ground game is in there, and that's so we can actively manage the portfolio throughout the year. Whether we use it or not, it depends on the [indiscernible] proposals that come in the door, what their expected sputter sales times are and compare that to the ground game opportunities that we're seeing day in, day out. So meaning we really weight the returns against one another. And so, we may have the opportunity to high-grade our drilling program and modify it and we'll definitely take advantage if we do. I'd say, like any other year, it will depend on what we're able to get done and if there are compelling opportunities to flex forward through the ground game. But again, as I'd reiterate, we budget a pretty hefty amount in our base budget every year for that amount.

And then just second, really on Bakken activity. I'm just basically wondering maybe for Adam, how stable, more recently, have most of your operating plans have become and if you're are receiving what I'd call more or less proposals than a year ago? I asked that because obviously, one of the gas is getting -- gas guys are becoming very volatile and some other plans are volatile. I'm just wondering if you're seeing a bit more stability in maybe Bakken versus Permian and just wondering how the proposals have become more recently.

And I think in the fourth quarter 125-plus AFEs, we received about 100 of those were in the Williston. And so looking at the end of the year, if we're looking at our oily basin, kind of makeup, that's about 80% of kind of the wells that are in process right now. And so we see that kind of pumping along to continue to add rigs and the operator makeup is certainly compelling as well when we're partnering with the likes of Ovintiv and Continental and Conoco. So we've been encouraged by the activity phase.

And I would say, Neal, based on our guidance that we put forth today, or whether or not the Williston Basin grows as a whole or not, I would probably say it probably remains pretty stable. We're going to have record volumes in the Williston by a big measure this year.

And I think it's a function of the working interest and the concentration with some of our operators. We've got significantly larger working interest that we're stepping into here at the beginning of the year.

Our next question is from Scott Hanold with RBC Capital Markets.

I think one maybe underappreciated factor is this new AI system that you all have, and it sounds like going to be coming -- going more full bore on it now. Can you just give us some context on what do you think this does to your pace? And maybe -- I don't know if it's the right way to say but quality of sort of your ground game and your potential acquisition activity. Where do you see upside? Like when you do back looks at what you did versus what you know now with the system, what have you made a change in are strategic advantages to having this in place?

From a strategic standpoint, especially if we branched out into multiple different basins, the volume of opportunities coming at us is at an all-time high. And so we've got to be able to prosecute these evaluations and do it with conviction. And when you've got the volatility that you have from a commodity standpoint as well as the inflationary pressures that ebb and flow, the fact that we've got north of 100-plus operators, all that information needs to be socialized and it needs to be done quickly in order for us to truly high grade and allocate capital appropriately. And so by instituting the AI program, we're able to take that real-time data and truly furnish all of the information that we have coming through the jibs and the revenue checks as well as all the public data and do that with one source of truth. And so that's going to be the key to our success as well as taking the look backs on the various transactions. I think we did one just recently in terms of kind of the recent major acquisitions, and I think we were within about 2% to 3% of original underwriting.

And the only color I would add to that is you got 9,000 gross wellbores at this point in the business. And the database has always been massive. It's always been the secret to our success, right, being in half of every Williston well drilled means you have full board of knowledge, but the speed of which you can access that data and harness it can take minutes now what would take our engineering team a week to come through in the past.

And so my next question is if you could be patient with you a second because there's a couple of pieces to it. But like if I think about where natural gas prices are today, and obviously, the entrance you all made into Appalachia, the first thing that stands out to me is if I look back, when you guys announced that acquisition, gas prices were about 250 and then they went to 910 and now back to 250. So early, they're kind of back to where it was when you made that acquisition. Do you think -- 2 things on it. Do you think that this environment does it make it more ripe for opportunities on new gas plays from a competitive sort of ability to make an acquisition? And number two, when you do your look back at the Marcellus deal you did, do you like the returns on economics? I mean there definitely was a step down in production versus where you originally expected. But do you think the [indiscernible] return still justified that move?

Yes. So I mean, to the latter point, Scott, that transaction, even net of all of the hedging we did paid out in 1 year, meaning we got all our money back in 1 year of owning it, and it has 20 years of inventory on it. So the pace at which it goes, I would say the pace has been slightly slower than we thought. But at the same time, the cost structure and well performance has been 20% or 30% better than what we underwrote. So net-net, we've done a lot better. And so we're thrilled to have it. It is truly a call option. We're also thrilled that we're not developing it this year that, that development really is in 2024. And that's really important to us because I don't -- while it is economic today, I don't really think we want to develop our gas properties at $2 gas -- but going back to the more -- the larger M&A question, I said we are basin and fuel agnostic, but convexity of returns does matter. For example, buying assets at $100 oil has a lot more risk even if you're hedging it versus buying it at $50. And buying gas last year was pretty unattractive to us on a risk-adjusted return because ultimately, there's a lot more that can go wrong then that could go right, and that goes back to when we bought the properties in early 2021. And so I would say, as it pertains to gas, it appears to us at current that the longer-term complexity on gas assets is very attractive and that would play a role and we're certainly actively looking at gas properties day and day out.

Our next question is from Philip Johnston with Capital One.

A question for Chad. You mentioned the weak gas realizations that you're expecting for '23. That's pretty similar to what we saw yesterday from one of your Williston operators. You guys are obviously on a 2-stream report here and obviously, a big driver there is weak NGL prices. And I, of course, realize there's a fixed component that's coming into play relative to lower NYMEX prices. But I guess the 75% to 85% of NYMEX seems pretty low. So I'm just wondering if you can maybe give us a little more insight as to what the drivers are there? And what's different about this year versus last year in addition to lower NGL prices.

I think what we're currently seeing right now is in -- we're probably down even below that. We're seeing some pickups from past months that kind of creeped us up to that 92%, but we're currently realizing at or below those, I guess, with respect to where we currently sit. I think some of the struggles in the Permian, obviously, with gas takeaway is going to also kind of creep into, I guess, 2023, and that's kind of where we're being a bit more conservative, I think, with respect to realizations of gas prices.

I mean, Philip, there's like -- it's kind of 4 dimensional chance, right? You have your fixed gathering cost getting it from wellhead to pipe, that doesn't move. But as the price of gas goes down, that becomes a larger percentage. And then you have the price of the NGL basket, which swings wildly because the actual yields from the plant changes depending on where the -- what the plants want to do, meaning whether ethane is economic or not to extract, and some people do it anyway. We'll leave them enable us, but some people do it whether it is or not. You get more volumes, obviously, but you then -- if you're a 3-stream reporter, but you're losing money. And I think the thing to think about though is that although NGL prices came down in the fourth quarter, gas prices really came down in the first quarter. And so actually, from a ratio perspective, the used propane and as an example, it was about 1.25:1 versus gas in the fourth quarter, but it's over 2 today. So that actually helps the percentage. And so really, the absolute price of the gas versus the NGL impact as much. And so we try to be really conservative because we're not -- we don't have a crystal ball here in terms of where natural gas is going. I wouldn't say we're internally particularly bullish. But we try to run it. And if you look at our track record in the past, we've historically been very conservative in this because these are non-controllable costs that we don't really want -- there's no benefit to us by doing anything but taking a conservative run at it. But I do think there -- as Chad mentioned in his prepared comments, there are some -- there is some room for improvement throughout the year, and we'll update you according.

On the reserve report, I'm just wondering if you can maybe share what your next 12-month PDP decline rate is for, I guess, for both oil and gas and perhaps how that's changed relative to where you were in the past couple of years. I'm assuming it's come down a little bit, but just looking for the approximate magnitude or so.

So our base PDP decline is going to be in the low 30s, 32% to 34%. Obviously, as we go through the year and we start bringing on some of these acquisitions, the NPDC project, those sorts of things, our decline rate will increase throughout the year. So as we exit the year, we're probably going to be closer to mid-30s to high 30s in that kind of range, but that's kind of where we're starting out today.

[Operator Instructions] Our next question is from John Abbott with Bank of America.

First question [indiscernible]. DD&A came in a little bit high for the fourth quarter with the merger closing. How do you think about an appropriate DD&A rate just sort of going forward?

Yes, John, we were just looking at that this morning. I think when we roll MPDC, I think we're sitting right around 150 for kind of exit DD&A. And I think NPDC will likely add 1 or 2 to it. So I think once we get that rolled in, it will probably be somewhere in the $11.50 to $12.50 range, I would guess.

And then the second question is on the acquisitions that you just sort of -- you just closed on here. Anyway, you just got them in the door, any pleasant surprises, any changes in activity levels versus what you originally assumed?

Yes. I mean I think maybe a few anecdotes to start first, like a small anecdote like our first Midland acquisition that we closed in October is performing exceptionally well. But we actually just did this look back this morning and in aggregate, we are ahead of schedule and the assets are performing really well. As a non-operator, you just have to say, like anything, this will change and pivot depending on the environment. But we underwrite conservatively and focus on good geology. And so they should be relatively resilient. And so ultimately, while drilling schedules move around here and there, I don't think we expect any major surprises in 2023.

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

The first one I want to ask is I know it is definitely way too early to get specific at all on guidance or any type of an outlook for 2024, obviously. But I'm just wondering if you can talk about this at a much higher level, just broadly in terms of given the high level of M&A activity that you've had -- including this quarter in the preceding 4 quarters. Is there any kind of embedded growth in that, that you would expect to translate into 2024 in terms of the cadence you see rigs moving through that acreage? I know maybe we assume -- if we assume something like an $80 oil price roughly, just when you're looking at all that acquisition activity that you did and you kind of hold things constant, do you see that as something leading to incremental growth in '24 over '23? Or would growth in '24 over '23 need some additional kind of proactive activity on your guys' part?

Yes. I mean I think the simple say and way to say this and assuming, obviously, keeping costs constant for a second Donovan, if we spent the same levels of activity this year that we -- next year, we would certainly see growth. We do highlight this in our earnings presentation, but the effective roll off of some of the MVDC activity. And what we try to highlight is, obviously, the guidance is for 91,000 to 96,000 barrels a day, you're obviously going to exceed that at some point as that project completes. And as Jim pointed out earlier, your decline rate is going to be a little bit higher as you kind of reach that [ Xenith ]. You need about 70 net wells a year to kind of hold above 90,000 barrels a day flat and probably grow it a little bit from that base over time. And so you're talking about $600 million to $700 million of sort of sustaining capital underneath at those levels. But obviously, our guidance is more like $750-ish this year. So if you continue at those levels you're going to grow. I will say, when you talk about 1 year to 1 year, the cadence of that spending really matters too, because you're going to carry forward those barrels into a year or so not all dollars are equal, but that should be some good goalpost for you.

And then if I could get another -- for a second question. I know this -- it might seem a little bit like a bit of an oddball question and one you probably haven't gotten in a while. But I am curious to know if you would ever consider taking non-op positions outside of these U.S. shale plays. There are still some conventional onshore opportunities here and there. And then you have things like Gulf of Mexico or Canada or moving somewhere international. And I know you don't -- that certainly wouldn't fit into a core competency where you have this real differentiated knowledge base. But of course, building -- you have to start somewhere to build that knowledge. And so I'm just curious if you think about stepping out into some of these other areas, doing a little like a small degree of dabbling to build that knowledge base. I'm just curious to know just how you think about that.

Well, I will agree that is an oddball question, but the answer is I don't think so. I mean I think we've seen a handful of Canadian opportunities in our way, and they've never made it past the e-mail in box. I think we take great pride and we take this really seriously about having technical knowledge we spent over 2 years in the Permian before we bought 60 acres, right? And so, if you're going to do something, you need to do it well. And I think that we've seen this one. We've been shopped conventional opportunities in the United States, which is within this country. And those are just simply our technical team is focused elsewhere. And so we want to focus on what we're good at. So I'd say that's a relatively low probability outcome for us.

Yes. I guess to frame it up a little bit differently in terms of M&A landscape, I think the most interesting opportunities that we're seeing currently are within the basins that we're already in. And that's not to say that we're not canvassing different basins within the Lower 48 because we look at the Eagle Ford, we look at the Haynesville, we've looked at the DJ. We've looked in other basins in that regard. But I think even stepping out into any of those basins, you're going to have to have a hurdle rate that's going to need to be compelling in order for us to dedicate significant resources to that. And so I think we'll continue to keep our ear to the ground and take a look at these other basins from a shale standpoint, but even then, it's going to have to be a higher bar.

Our next question is from Noel Parks with Tuohy Brothers.

So just a couple of things. It was interesting to hear you say that the longer-term outlook is making you see gas assets as very attractive with this pullback and that you're certainly looking at those properties. So I'm just wondering, as you do your evaluation process, how do you sort of weight the issue of getting more concentrated, say, in gassy assets incrementally versus infrastructure uncertainty. I mean how do you sort of tick that into your model?

I mean I think it all goes in there. I mean the number one, we don't -- we certainly don't pick some esoteric gas price that we think it should got to, to underwrite these things. You have to underwrite them based on the world you're living in now and then stress that further. I'd say that infrastructure is really important. Just using an example when we underwrote our Appalachian properties, we certainly never model in growth just given the infrastructure constraints within that basin, and we ramp pretty punitive differential analysis when we went through that. I'd say in basins that we're not in use the Haynesville, as an example, where we've observed as it's grown materially in the last few years, that infrastructure has gotten really tight. We also did the same thing when we were looking in the Permian recognizing the same thing. And so our internal analysis factor in sometimes differentiated views on those things. We've suffered through infrastructure constraints in every basin we operate in. And the key thing is to understand what's short term and what's long term and what's going to have a meaningful impact on the actual value of the properties.

And just wondering, and apologies if you touched on this before. Are you on the path to maybe going non-consent on more of what is proposed to you in, for example, Appalachia over for other players that wait a little bit gather?

Yes. I mean, in Appalachia, the good news is that we have a multiyear program with EQT, and it's more happens a function of the gas environment, but there are no completions this year. So there'll be minimal CapEx. We may spend some drilling CapEx as we prepare for the 24 plan at the end of the year, but not a ton.

Yes, it's much longer-term planning. I think where you're going to see the non-consent levered getting pulled or not getting full is going to really depend on inflation and how that interacts with commodity prices because -- and then obviously, depending on who the operators are because at the end of the day, we're in an IRR-driven shop, right? And so if you have a gap down in commodity pricing, but inflation stays sticky, then there's going to be things that may or may not meet our hurdle rate. I think the good news is that most operators are staying relatively disciplined in terms of sticking to the core. And so I think you've got some buffer in that regard versus a lot of the science experiments that we've seen in cycles past.

Yes. And just to elaborate on that, Noel. Like as an example, we came into the Permian later where the delineation had been largely made. And so we don't have a ton of acres in areas that are noncore or going to be really subject to some of the swings in commodity prices you see now in the Williston well because we have a large legacy position, we own a lot of noncore properties to Avon's point, they're just not being developed. And so it allows the operators in some ways are doing the work for us.

Ladies and gentlemen, we have reached the end of our question-and-answer session. I'd now like to turn the call back to Nick O'Grady, CEO for closing remarks. Over to you, sir.

Thanks, everyone, for joining us today. We'll work really hard to execute on the 2023 plan, and we'll see you on the next quarter.

To access the digital replay, please dial (877) 660-6853 or (201) 612-7415 and enter access code 13736011. Ladies and gentlemen, this concludes today's conference. You may disconnect your lines at this time, and thank you for your participation.