Chord Energy Corp (CHRD) 2023 Q2 法說會逐字稿

Good morning, and welcome to the Chord Energy Second Quarter 2023 Earnings Results Conference Call. (Operator Instructions) Please note that this event is being recorded. I would now like to turn the conference over to Michael Lou, Chief Financial Officer. Please go ahead.

Thank you, Megan. Good morning, everyone. Today, we are reporting our second quarter 2023 financial and operational results. We're delighted to have you on our call. I'm joined today by Danny Brown, Chip Rimer and other members of the team. Please be advised that our remarks, including the answers to your questions, include statements that we believe to be 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 those currently disclosed in our earnings releases and conference calls.

Those risks include, among others, matters that we have described in our earnings releases as well as in our filings with the Securities and Exchange Commission, 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 this conference call, we will make reference to non-GAAP measures, and reconciliations to the applicable GAAP measures can be found in our earnings releases and on our website. We may also reference our current investor presentation, which you can find on our website. With that, I'll turn the call over to our CEO, Danny Brown.

Thank you, Michael, and thank you to everyone who's joined our call and what I know is a very busy morning. So with that, in addition to discussing our quarterly results and expectations for the balance of the year, I'd also like to briefly recognize what Chord has done over the past 12 months to integrate 2 premier Williston Basin operators and form a new, stronger and more resilient organization. While integration is never easy, I am very proud of what the team has accomplished, including fulfilling our commitment to capitalize on the best practices of the 2 legacy organizations and using that to capture and expand significant financial and operating synergies.

We've also been very focused on our shareholders. One year ago, we rolled out what we believe to be a peer-leading return of capital program that showed our commitment to both the balance sheet and to delivering returns to our investors. For the 12 months from July 2022 to June 30, 2023, we returned $1.1 billion in the form of dividends and another $198 million via share buybacks, including aggressively repurchasing steeply discounted shares shortly after the transaction closed.

We've also strengthened the portfolio, including closing the XTO bolt-on acquisition on the 1-year anniversary of close and selling noncore assets, streamlining our operations and directing focus to where we have scale and competitive advantages. I'm also very pleased to announce that we've added a key member to our executive team, Shannon Kenny. Shannon joins us as our Executive Vice President and General Counsel, and brings over 20 years of legal experience with her, most recently from ConocoPhillips, where she was Vice President, Deputy General Counsel and Corporate Secretary. We are absolutely thrilled to have Shannon as part of the team and look forward to working with her and benefiting from her expertise as we move forward.

Now turning our attention to the quarter. The organization once again delivered strong operational performance, resulting in oil and total volumes above expectations. This volume delivery was underpinned by very solid performance from new wells, the underlying asset base and acceleration of Permian lines or TILs early in the quarter. While NGL and gas realizations were softer sequentially and Michael will provide more detail on this topic shortly, capital and other items were generally right in line with expectations and guidance. So taking all of this into account, we generated $116 million of adjusted free cash flow during the quarter, which is presented in our deck, does include the removal of around $11 million of capital booked from nonoperated wellbores, which have been sold and which will be reimbursed to us.

And given this free cash flow generation and in keeping with our return capital framework, we declared a variable dividend of $0.11 per share with a base dividend, which remains unchanged at $1.25 per share. As a reminder, the aggregate variable payment of approximately $5 million is the difference between the 75% of the $116 million of adjusted free cash flow generated in the second quarter, minus the base dividend of approximately $52 million, minus $31 million of second quarter share repurchases. In other words, the variable dividend is designed to make up any difference between our targeted free cash flow payout and the amount distributed through base dividends and share repurchases.

As I've said before, we believe our capital return program is peer-leading and demonstrates our commitment to both capital discipline and shareholder returns. And as we noted last quarter, we aimed to increase share repurchases as a percentage of return capital in recognition of the discount that we believe Chord trades at relative to peers and our intrinsic value. Accordingly, in the second quarter, share repurchases accounted for almost 90% of capital returned after our base dividend. As we look forward, we will continue to be opportunistic with share repurchases and return capital through a mix of base dividends, share repurchases and variable dividends.

Now shifting topics to development. As most of those on the call know, 3-mile laterals are an important part of our program in 2023 and beyond. So I want to spend a little time discussing our latest performance and what we're expecting going forward. Year-to-date, we've filled around 13 3-mile laterals. And when combined with the 17 wells from 2022, I'm encouraged by the performance we've seen so far. More specifically, we are seeing improving performance on well delivery and are clearly seeing a strong contribution from the furthest portions of the lateral once that rock is stimulated and cleaned out.

As Slide 9 of our presentation shows, we have materially reduced drilling times for 3-mile wells over the past year and are now running a little ahead of schedule. On the cleanout side, we've also made steady improvements and have generally been able to stimulate and access the vast majority of the third model. As a reminder, for 3-mile wells, we are assuming a 40% EUR uplift for 50% longer lateral and about 20% more drilling and completion costs. Said another way, we're assuming the third mile is only 80% as productive as the first 2 miles.

In practice, what we're seeing is a volume response proportional to the percentage of the third mile that's cleaned out. So a 50% longer well that was cleaned out all the way to the toe is generally delivering an approximate 50% uplift in EUR. In some instances, we've been unable to clean out a small portion of the toe and that can lead to a reduction in productivity for the last mile. But once again, we've anticipated this with our 80% production assumption I just discussed. We provided more performance analysis on Slide 9 of our investor presentation, which shows the 3-mile wells are clearly outperforming 2-mile wells in the same area.

Additionally, as you can see on the left side of Slide 10, we performed a study using Tracer to determine which portions of the lateral are contributing to production at specific points in time. For this test, initially, the Teal well was intentionally not cleaned out, and we observed a strong production response from the stages that were cleaned out plus only 1 or 2 stages further interlateral despite using double plugs. We came back to the well 10 weeks later to clean up the toe stages and subsequently saw a strong production response from the previously uncleaned portion of the wellbore.

Given the large number of potential 3-mile laterals the court has and the improved capital efficiency opportunity, these laterals represent. The results we are seeing are exciting and that our execution performance has been improving, and we believe spending a little more time to ensure that our coiled tubing drill-outs, which is a very low-cost operation, are effective all the way to the toe could allow us to increase the 80% efficiency number for the third mile of the lateral, which would obviously enhance our capital efficiency even further. Finally, on Slide 11, you can see that in aggregate, our well performance is running slightly favorable to expectations. This can be attributed to the effectiveness of the 3-mile laterals we just discussed as well as our practice of which we believe improve per well recoveries, increased capital efficiency and reduce variability of performance across the asset.

Moving on from development. Concurrent with second quarter results, Chord announced the sale of additional noncore properties for proceeds of approximately $29 million. This includes approximately $11 million of capital reimbursement for nonoperated spending we had not budgeted for 2023. Given this capital will be reimbursed and was not part of our original guidance, we excluded it from adjusted free cash flow and CapEx for the purposes of the second quarter capital return, as you can see in our deck. Oil volumes associated with these noncore sales approximate 500 barrels of oil per day. And for clarity, the 500 barrels of oil per day are not associated with the non-op wellbore sales but are associated with scattered legacy wells outside the Williston Basin.

Year-to-date, Chord has announced over $64 million of noncore asset sales. We've updated our full year guidance to reflect these asset sales and production gain from the XTO bolt-on acquisition, which is contributing approximately 3,000 barrels per day of oil in the second half of 2023. This bolt-on was an excellent supplement to our core inventory and demonstrates natural synergies from our scale position in the Bakken, which is now over 1 million acres.

We added approximately 123 net locations. And importantly, we were also able to convert 6 core 2-mile DSUs into 3-mile DSUs. This further enhance the economics of the deal, which is immediately accretive to cash flow, free cash flow and our return metrics. In light of the above, we have updated our full year capital forecast to a range of $850 million to $880 million. Excluding the $11 million of reimbursed nonoperating capital, the midpoint of annual CapEx investment increased approximately $20 million, largely due to additional drilling and completions activity associated with maintaining a larger production base moving forward. And finally, a brief update on ESG. Chord expects to publish its first sustainability report as a combined company in the third quarter of this year. My thanks to the team for putting together a great piece of work. And we will highlight our continued focus on improving safety and emissions and our commitment to continuous improvement in other aspects of sustainable operations while proudly delivering the energy the world needs.

To sum things up, the assets are performing well. We are substantially through merger integration and have become a stronger organization than either legacy company. We have a compelling financial outlook and are keenly focused on continuing to deliver and support high levels of sustainable free cash flow as we move forward. I'll now turn it over to Michael for some additional updates.

Thanks, Danny. I'll highlight a handful of key operating and financial items for the second quarter and discuss our updated 2023 guidance. As Danny mentioned, oil volumes were strong in the second quarter, about 1.5% over midpoint guidance. Total volumes were above the high end of guidance driven by NGL volumes as we saw Bakken midstream providers pivot from ethane rejection in the first quarter to ethane recovery in the second quarter. This led to higher NGL volumes, but weaker realizations as ethane became a larger portion of our overall NGL barrel. In addition, NGL realizations were impacted by a combination of lower Conway prices and impacts associated with our T&F fees.

Our T&F fees are allocated based on the percent of gas and NGL revenues. With weaker residue gas prices in the second quarter, NGL realizations were disproportionately impacted quarter-over-quarter. We have updated realization guidance to reflect recent market conditions. It does seem like NGL prices hit a bottom in late second quarter and are improving into the third quarter, along with higher Henry Hub gas prices. Clearly, the Bakken has a bit higher gathering and processing fees versus other basins. This drives higher operating leverage, which hurts realizations for both NGLs and gas and times of weaker pricing, but should improve quickly as prices recover.

Our 2023 activity schedule is similar to what we expected earlier in the year. TIL activity is concentrated in the second and third quarters, leading to sequential production increases in the third and fourth quarters. As Danny mentioned, we added some frac activity to the fourth quarter. However, most of the wells will not be cleaned out until early 2024, so there's no volume impact in 2023. Turning to cash costs. LOE was a little below midpoint guidance while GPT was above. On GPT, beginning in the second quarter, we converted a crude oil marketing contract from a sales contract to a transportation contract. From an operating profit standpoint, the result of this change is neutral but it does result in higher GPT but also higher crude oil realizations. We've updated our guidance to reflect this change going forward. Production taxes were 8.4% of oil and gas revenue, which was at the higher end of our guidance range. In North Dakota, production taxes on gas are volume-based. So better-than-expected gas production, coupled with drive a lower percentage of revenues.

In addition, oil continues to become a larger portion of revenue and is taxed at higher rates than gas and NGLs. Our forward guidance reflects oil's higher contribution to revenue as well as an escalation in North Dakota gas extraction tax in July. Chord cash G&A expense was $17.7 million in the second quarter, which was within the guidance range. Our 2023 G&A guidance remains unchanged at $63 million to $73 million. Chord paid no cash taxes during the second quarter. And in the second half of the year, Chord expects cash taxes to approximate between 0% and 10% of second half EBITDA at oil prices between $70 and $90 per barrel. Our full year capital budget guidance was increased about $20 million at midpoint, mostly reflecting higher fourth quarter frac activity associated with the XTO bolt-on.

Turning to liquidity. Chord's borrowing base remains $2.5 billion. Elected commitments remain at $1 billion with nothing drawn as of June 30. Cash was approximately $215 million as of June 30, which is net of the final cash payment made to XTO for the bolt-on deal that closed on June 30. In closing, the Board team continues to execute well and drive strong returns, which supports our sustainable free cash flow profile as well as our peer-leading return of capital program. Our team continues to drive a more capital-efficient program in the Bakken, and this has led to our superior returns for our shareholders.

As a result, we have returned about $28 of cash per share to shareholders in the last 12 months, along with the $200 million of share buybacks, and this has driven a total shareholder return of approximately 57% since the merger closed last July. We are incredibly proud to be a safe and reliable low-cost provider of energy, which feels a better world. We're also proud of the entire Chord team who continued to show care for each other and for our communities and encourage to always do what is right. With that, I'll hand the call back over to Megan for questions.

(Operator Instructions) The first question comes from Scott Hanold with RBC Capital Markets.

I was wondering, Danny, you gave some kind of more details on cleaning out the those 3-mile wells. Just out of curiosity, can you give us some sense like when you do that, does it take longer or more cost to make sure it's properly cleaned out? And when you do get that contribution, typically, does that influence IP rate? Is it more of a shallower decline that ultimately leads to the higher EUR?

So I'm going to take a stab at this, and then I'll ask Chip to weigh in for additional color if we need to. But to go with the second part of your question first, I think as we think about 3 mine laterals in general, the early IP rates and that early time production really isn't too different from what we see with 2 miles. We're not really designing larger facilities. We just -- we end up running that production flat for a longer period of time with a 3 mile than a 2 mile. And then ultimately, the decline is shallower on a 3 mile than a 2-mile because you just have more reservoir feeding in over time. And so generally, not a big uplift in IT on 2 miles versus 3 miles, but a lot better EUR and clearly much more capitally efficient.

From a cleanout perspective, that's actually one of the really exciting things to me. The part of the operation that is involved in getting out to the toe of the coiled tubing operation is one of the lowest cost portions of the operation. And so spending a little time getting further making sure that we get cleaned out all the way to the end, it actually doesn't cost us very much at all, but it can deliver some significantly improved volume contribution from that end portion of the well. So Yes, not a whole lot of incremental cost for it. There may be -- in any operation, there will be times where maybe we don't get 100% of it cleaned out, but spending a little longer to get essentially the entire -- that entire lateral cleaned out has a big opportunity for us to move that 80% contribution from the third mile closer to 100% contribution to the third mile, which will be fantastic. So I'll let Chip weigh in as well.

Yes. Scott, this is Chip. Yes, I'd agree a 100% with what Danny said flatter for longer, of course, versus the IPs. And then we want to run a test to see what dissolvable plugs were doing. We're actually dissolving do we have a clean wellbore or not. So we ran that test and be able to look at those tracers and see what's going on. So identifying and be able to knock out that last a little bit, as Danny indicated, is a very small amount of dollars when it's all said and done. But we have a lot better understanding of what the contribution is across the wellbore. So really excited -- I'm really excited. I want to thank the team for really finding ways to get certain fluids, certain designs to make sure they're knocking this thing as quickly as possible, but for a very small amount of time, additional, we can hopefully get 50% of the wellbore versus 40%.

And then, I guess a question that leads me to next is as you think about getting more of these 3 milers online and obviously with a little bit more, I guess, back half or early I say, I guess, 2024 momentum because of those DUCs you mentioned. What did that say to the capital efficiency of the program going into 2014? Does it -- should we be able to see a little bit of an improvement on that given those 2 factors? And that coupled with, I guess, OFS cost reductions seems to be moving in your favor?

So Scott, I'll -- I think as we look forward, clearly, we're trying to drive capital efficiency -- improve capital efficiency in all aspects of our business. So that's always the driver for us over here. And this additional opportunity we see with the 3-mile laterals and the coiled tubing drill-outs that we just discussed, obviously, helps with that. From a deflationary sort of environment in oilfield services, I'd say we're certainly seeing some encouraging signs in that, but I still think it's maybe a bit early to really roll forward with that in our full planning process. We've got line items that are certainly lower, but we also have some line items that are higher.

Labor cost is generally sticky. And now that we've seen some recovery in oil prices, which we're obviously very thankful for, that's probably likely to provide some support to service costs as well. So I think the deflation is -- we're seeing encouraging signs. I'm not ready to quite roll through completely yet. We're going to see a little further. And with respect to 2024, I think we'll provide -- we're working to develop a plan that's essentially a maintenance level plan versus our current year. We're going to do that in a capitally efficient manner as possible. And we'll talk more about that later this year and probably come out with full specific guidance in early 2024.

Our next question comes from Derrick Whitfield with Stifel.

So for my first question, I wanted to build on Scott's question. Given the proof of the tracer data that you show on Slide 10, does that bias you to in your recovery assumptions for the last mile?

I'm sorry, say that one more time, Derrick.

Sure. Given the proof of the tracer data on Slide 10 of your presentation, does that bias you to inch up your recovery assumptions for the last mile of the lateral?

Yes. I think as we're able to see -- I think as we're able to get more data on this, they are at best the implication that, that 80% recovery efficient for that last mile. If we're successful in getting all the way out to the 2, as we have been able to, I think, the last 6 wells we've gotten essentially out to the -- we've got the entire lateral cleanout. So we'll see results coming through that. And if that lines up with the early results we've seen from the other laterals that we've done, the implications is we can start moving that 80% recovery in the last mile, up closer to 100% of recovery for the last mile. So that's the goal here.

And as my follow-up, I wanted to ask if you could speak to the A&D environment in the Williston at present. More specifically, are you guys seeing greater deal flow now that oil has stabilized higher in private equity simulating holdings?

Yes, I'd say from my perspective, Derrick, there's always been sort of a little bit of chatter in Williston across a whole variety of different assets from, I'd say, small asset positions from trades to private equity opportunities. And so I don't know if I've seen a noticeable uptick in that. I think it's just been -- it's been a bit steady. And we evaluate a lot of things that come through. Some of them transact. Some of them don't transact and -- but we've got our gear to the ground with our position in the Williston -- the -- it is -- we feel like we are a natural consolidator within that basin, and so we pay attention to what's going on. And as you saw with the XTO acquisition, we think when it -- when we have opportunities out there that fit in well with what we're trying to accomplish at which that XTO acquisition did, we can act and we think it's really going to accrete to value for the organization and for shareholders.

Our next question comes from Neal Dingmann with Truist.

Could you tell me what's driving -- you still see some remarkable results in Hills. I'm just wondering is that from water spacing laterals, efficiencies. If you could just point to the details there.

Yes. So again, I'll lead off here and then ask Chip to way in with some additional color commentary. In Indian Hills, I think we -- one, it's just -- it's a good spot in the basin. We have spaced those wells out wider and we've moved more toward 3-mile laterals. And so I really think it is a combination of subsurface quality of wider spacing and a 3-mile laterals. And so I think we've got a slide on the graphic in the deck that shows some of the varying contribution of that and -- but it's really a combination of all 3 of those things. But it's a great portion of our asset, and it's one we're super happy with.

No, you're exactly right. I think that slide on Page 9, I think shows what's going on there. We're taking the same thoughts with spacing and longer laterals and other areas and going across the basin this back half of this year, you're going to see some different spots in the basin. So I think we'll be able to have some results later next year for your -- early next year probably before you and to see how that's working, but really excited about what we're seeing in Indian Hills and what that's going to do for the rest of the basin.

Yes. It really seems to be working well, guys. And then just my second on shareholder return. Dan, you kind of talked about this in pared remarks. So I just wondered, you all -- does this mean you'll kind of diverge from what you were doing before? And would you think they go to more of a formulated plan? Or I know you talked about opportunistic buybacks. I'm just wondering if there's any thoughts of going to maybe like a unique plan there.

No, I think -- as we talked about last quarter, Neal, the thought was we were just being too restrictive on how we were judging our performance, particularly relative to others. We always thought from an in transit value standpoint, we were a pretty compelling opportunity. And as we open the aperture up there, it's allowed us to do some more -- allowed us to do some more share repurchases. So I think this is just in keeping with what we talked about last quarter.

Clearly, a bit of a departure, at least from a percentage standpoint and what we did early in the capital return program where we were being more focused on variable dividends, again, because of the framework we were looking at this through. So as we've opened that aperture up more was flowing toward share repurchases, but we'll continue to think about that opportunistically. I think the great thing is we're committed to a very strong return program. It's just part of the ethos of the organization. And so we'll continue to do that. And we think we're undervalued versus our -- versus our intrinsic value and versus peers. And so those share repurchases made a lot of sense to us.

Our next question comes from Phillips Johnston with Capital One.

Your CapEx guidance implies that we'll see a fairly large reduction in spending in Q4. Can you maybe provide some context there? And how should we think about what that means for production momentum going into next year.

Yes. As we talked about early when we set budget guidance for the year, we've really put a program together where we've got -- we started the year with 1 frac crew. We added a frac crew as we got out of winter and got into the warmer sort of easier months to operate in North Dakota. And that last essentially through the end of the third quarter. And so the second quarter and third quarter, we ran 2 frac crews in the first quarter and fourth quarter will only run 1. And that's really predicated around just winter weather in North Dakota. So that really explains the capital drop-off.

We'll drop that frac crew and all the commensurate completion spending will fall away from the program there. Now we'll continue to fill those wells as we get into the fourth quarter and a bit into the first quarter as well. And then we'll start resuming capital activity. So I recognize it does provide some cyclicality in the production profile that we produce, but we think it's the more capitally efficient way to run the program just to avoid some of that really harsh winter weather where you can have some real difficulties from an operations perspective.

Yes. Okay. And then looking out into next year, you mentioned just the intention to kind of keep volumes relatively flat. Obviously, it's early, but directionally, do you think that's about sort of a 3.5-ish kind of rig program or so. And then on the mix of 3-mile laterals, do you think it will be kind of similar to this year, around 50% or so? Or do you think it will be significantly different next year?

I think the 3-mile lateral program will probably be pretty similar to this year. We're still working through the specific DSUs that we'll drill next year, but I think it should be relatively similar. And from a drilling perspective, my anticipation is we'll run around a 4-rig program next year.

Our next question comes from Oliver Huang with TPH.

Just wanted to kind of hit on the drilling side of things. The improvements have been rather sizable over the last 6 months on the 3-mile laterals. Just wondering how much more running room do you all see on this front? Or is the low-hanging fruit already been captured? And also, how should we think about potential for production into year-end if the accelerated pace were to increase or continue? And how might this help the 2024 program?

Oliver, this is Chip Rimer. Yes, I'm really excited about what the team has done here. And I think Danny mentioned earlier in his script was we capitalized on the best practices. We looked at the best practices from both companies going forward. So you can see prior to merger there probably averaging 17 days. And through those best practices, and it's not just 1 or 2 things. It's a lot of different things that the guys put together from different fluids to bit designs, to Bottom hole assembly designs, just tweaking the system a little bit every time.

So excited what they've been putting together, finding the right rigs with the right people on board also and be able to move quicker and just be able to knock those prices down. So am I going to say they're going to do another 3 days from 6 months from now? Maybe a little harder to do, but they continue to chase things down and make it more efficient. So that's the exciting piece about it. So we'll keep doing it. And then we'll play by year by the DUC count. But right now, this is -- I'm just really excited what our team is doing on the drone side. And the other thing it's across the whole organization from the completion side to the facility side. It's cradle to grave. So really excited what they're doing.

And I just wanted to kind of follow up on the 3-mile laterals, but just on the facility side of things. Have you started to just do more activity in areas like Red Bank, Painted Woods and Foreman Butte. Just trying to understand, is the facility side in pretty good shape there? Or would we be looking at an increased level of constraints on the 3-mile lateral wells just given these are areas where there's probably been a little bit less activity historically?

So Oliver, I think that's a great question. As we put the development program together, we're cautious in where we're drilling to make sure that we do have the infrastructure to have takeaway volumes there, whether that be through our gathering system through our more long-haul pipelines were through our local facilities. And so that all kind of goes into where we plan on drilling over time. So I don't anticipate any significant constraints as a result of going into these other areas because we'll have the infrastructure sort of see us there as we go in. So that's how we'll design the program.

And Oliver, the nice thing is we have strong inventory across a large portion of the acreage here in the Bakken. So we are drilling in different areas. They all have good capital efficiency. And as we spread that out, infrastructure constraints actually get minimized because you're spreading the program out over a larger area. So every pipeline is going to be a little bit better off because you're not concentrating into all in one area.

Yes. I think the other thing is the -- all the prior, but it's also gas capture. Beth gas capture numbers up high. So you're not concentrated in one area.

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

My first question is on GP&T. I understand that you -- I understand the accounting change in that, there's no impact to margin. But why make the change if there's no benefit there. So what is the benefit to you of switching from the sales to the transportation contract? And could we see a better realization versus just assuming neutrality.

The contract is just kind of a form of how we're -- we made some small changes in terms of how we're operating. And so I don't think it actually changes overall margins. And so we kind of talked about that. We realized that we have taken GPT up a little bit, and we didn't make that same move on the realization side. Part of that is just overall realizations in the basin are still very, very strong. There's still a positive differential to TI. But they're just not quite as strong as where they were. And so we didn't move that realization side up. In reality, on that specific deal, it does take GPT up, but it does take realizations up on that one contract.

And then just quickly for Michael, so the understanding the cash tax guidance for the second half of the year, 0% to 5% to 10% of EBITDA. What's your just your latest thoughts as you look to 2024 and beyond in terms of how that cash tax rate would have trends?

Yes. So cash taxes later part of this year, I kind of said 0% to 10% in the $70 to $90 oil price. If you look at that kind of going forward, I'd kind of think next year is in the same $70 to $90 range, probably 4% to 11%, somewhere in that neighborhood. So we are going to be cash tax paying going forward, but that's going to kind of be the range to be thinking about.

This concludes our question-and-answer session. I would like to turn the conference back over to Danny Brown, Chief Executive Officer, for any closing remarks.

Thanks, Megan. Well, to close out, I just want to thank the employees of Chord for their and dedication to our organization. Last year was a pivotal year for our company, and I know the team worked hard to integrate 2 predecessor companies and put us in a great position to succeed going forward. And to our investors, I'd say Chord is positioned to deliver value for its shareholders through disciplined capital allocation, efficient operations and maintaining a strong balance sheet while remaining committed to responsible operations. Thanks, everyone, for joining our call.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.