Title

Presentation

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

Michael Lou: 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.

Daniel Brown: Thank you, Michael. And thank you to everyone who’s joining 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 two premiere 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 two 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 1, 2022 to June 30, 2023, we’ve 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 one-year anniversary of close and selling non-core 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 Kinney, 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 turned-in-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 removal of around $11 million of capital, booked from non-operated wellbores which had been sold and which will be reimbursed to us.

And given this free cash flow generation and in keeping with our return on 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 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 target and 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 pure 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 our percentage of return capital in recognition of the discount that we believe core 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.

Either day, we’ve tilled 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 protis portions of the lateral once that rock is stimulated and cleaned out. At Slide nine of our presentation shows, we have materially reduced drilling times for 3-mile wells over the past few year, and are now running a little ahead of schedule. On the clean outside, we’ve also made steady improvements and have generally been able to stimulate and access the vast majority of the 3-mile. 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 two 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 TIL is generally delivering an approximate 50% uplift in EUR. In some instances, we’ve been unable to clean out a small portion of the TIL 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 nine of our investor presentation which shows the 3-mile wells are clearly outperforming two 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 total well was intentionally not cleaned out. And we observed a strong production response from the stages that were cleaned out plus only one or two stages further in the lateral, despite using dissolvable plugs. We came back to the weld 10 weeks later to clean out the TIL stages and subsequently saw a strong production response from the previously unclean portion of the wellbore. Given a large number of potential 3-mile laterals, the quarter has an 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 TIL 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 three mile laterals we just discussed, as well as our practice of wider well spacing, both of which we believe improve per well recoveries increase 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 non-operated spinning, 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. Well volumes associated with these non-core sales approximate 500 barrels of oil per day. For clarity, the 500 barrels of oil per day are not associated with the non-up wellbore sales but are associated with scattered legacy wells outside the Williston Basin. Year-to-date, Chord has announced over $64 million of non-core asset sales. We’ve updated our full year guidance to reflect these assets sales and production gain from the XTO bolt-on acquisition which is contributing approximately 3000 barrels a day 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 six Chord to two mile DSUs into three mile DSUs. This further enhanced 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 forecasts to a range of $850 million to $880 million. Excluding the $11 million of reimbursed non-operating 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 it will — we will highlight our continued focus on improving safety and emissions and our commitment to continuous improvement and 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.

Michael Lou: Thanks Danny. I’ll highlight a handful of key operating and financial items for the second quarter and discuss our updated 2023 guidance. As Daniel 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 TNF [ph] fees. Our TNF fees are allocated based on a percent of gas and NGL revenues.

With Uyghur 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 in 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 weaker prices resulted in a higher reported production tax as a percentage of revenue.

As gas prices recover, it will drive a lower percentage of revenues. In addition, oil continues to become a larger portion of revenue and is taxed at a higher rate than gas and NGLs. Our forward guidance reflects oils 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, Chords 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 payments made to XTO for the bolt-on deal that closed on June 30. In closing, the Chord 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 the courage to always do what is right. With that, I’ll hand the call back over to Megan for questions.

Operator: [Operator Instructions] The first question comes from Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Hanold : Thanks, and good morning. I was wondering, Dan you give some kind of more details on cleaning out the total those three mile wells, just out of curiosity. Can you give us some sense, like when you do that is 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?

Daniel Brown: Thanks for the question, Scott. So I’m going to take a stab at this, and then I’ll ask Chip to way in for additional color if we need to. But, to go with the second part of your question, first, I think is we think about 3-mile 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 ended up running that production flat for a longer period of time with the 3-miles going 2-miles. 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 IPs on 2-miles versus 3-miles but a lot better EUR and clearly much more capital efficient.

From cleanouts 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 TILs the Coiled Tubing operations is one of the lowest cost portions of the operation. And so spending a little time getting further and making sure that we get cleaned out all the way to the end is 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. There may be, in any operations there, there will be times where maybe we don’t get 100% of the 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 up closer to 100% contribution to that third mile, which will be fantastic.

So I’ll let Chip weigh in as well.

Charles Rimer: Yes, Scott, this is Chip. Yes, I agree 100% what Danny said, flatter for longer, of course on versus the IPs. And then, we have run the 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, and be able to look at those tracers and see what’s going on. So identifying and be able to knock out that last 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 I’m really excited, I want to thank the team is are really finding ways to get certain fluids, certain designs to make sure they’re knocking this thing out as quickly as possible. But for a very small amount of time, additional, we can hopefully get 13% [ph] of wellbore.

Scott Hanold: That sounds good. And then I guess a question that leads me to next is, as you think about getting more of these three milers online and obviously with a little bit more, I guess back have or early I’d say it gets 2024 momentum because of those ducks you mentioned. What does that say to the capital efficiency the program going into 2014? Does it, should we be able to see a little bit of an improvement on that given those two factors. And that coupled with I guess OFS cost reductions, seems to be moving in your favor?

Daniel Brown: So, Scott, 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 coil tubing drill outs that we just discussed, obviously, helps with that. From a deflationary sort of environment and oilfield services, I’d say, we’re certainly seeing some encouraging signs in that, but I still think it’s maybe a bit 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 and oil prices, which we’re obviously very thankful for that’s probably likely to provide some support to service to service costs as well.

So I think the deflation is we’re seeing encouraging signs, I’m not ready to quite roll that through completely yet, we’re going to need 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 do that in his capital 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.

Scott Hanold: Understood, thanks for that.

Operator: Our next question comes from Derrick Whitfield with Stifel, please go ahead.

Derrick Whitfield : Thanks. Good morning, all. Congrats on another strong quarter. 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, is that bias you to inch up your recovery assumptions for the last mile?

Daniel Brown: I’m sorry, say that one more time, Derrick.

Derrick Whitfield: 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?

Daniel Brown: I think is we’re able to see, I think as we’re able to get more data on this, Derrick, that’s the implication. That 80% recovery vision for that last mile if we’re successful, in getting all the way out to the toe, as we have been able to I think the last six wells, we’ve gotten essentially out to the we’ve gotten the entire lateral plane down. 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% recovery sort of last mile. So that’s the goal here.

Derrick Whitfield: Thanks, Danny. And as my follow up, I wanted to ask if you could speak to the AMD environment in the Willesden at present. More specifically, are you guys seeing greater deal flow now that well was stabilized higher in private equity is seemingly trending affluence?

Daniel Brown: Yes, I’d say you know, from my perspective Derrick there’s always been sort of a little bit of chatter in Willesden across a whole variety of different assets from I’d say small assets positions from trades to private equity, 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 that come through some of them transact some of them don’t transact and but we’ve got our ear to the ground with our position in the Willesden. 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 we have opportunities out there that fit in well with what we’re trying to accomplish which that XTO acquisition did. We can act and we think, it’s really going to equate to value for the organization and for shareholders.

Derrick Whitfield: That’s great. Thanks for your time.

Operator: Our next question comes from Neal Dingmann with Truist. Please go ahead.

Neal Dingmann : Good morning, guys. Could you tell me what’s driving — you still see some remarkable results in Indian Hills? I’m just wondering is that from water spacing, laterals, efficiencies, if you could just, you know, point to the details there?

Daniel Brown: Yes, thanks, Neil. So again, I’ll lead off here and then ask Chip weigh with some additional color commentary. In Indian Hills, I think we want 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’s a, it’s a, it’s a combination of subsurface quality of wider spacing, and of and a 3-mile laterals. And so I think we’ve got a slide on the graphic in the deck that shows us some of the variant contribution of that, and we can, but it’s really a combination of all three of those things, but it’s, it’s a great portion of our asset, and it’s one where we’re super happy with.

Charles Rimer: Neal, no, you’re exactly right. I think that slide on page nine, I think shows what’s going on there. We’re taking those same thoughts with spacing and longer laterals and other areas and going across the basin is 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 or early next year, probably see how that’s working. But really excited about what we’re seeing the Indian Hill, and what that’s going to do for the rest of the season.

Neal Dingmann: Yes, it really seems to be working well, guys. And then just my second on shareholder return. Danny you talked about this in prepared remarks, I just wondering as you — does this mean you’ll kind of diverge from what you were doing before. And would you think they’d go to more of a formulate plan? I know, you’ve talked about opportunistic bites. So I’m just wondering if there’s any thoughts of going to maybe like a unique plan there.

Daniel Brown: As we talked about last quarter, Neal, the thought was is we were just being too restrictive on how we were judging our performance, particularly relative to others. We always thought from an intrinsic value standpoint, we were a pretty compelling opportunity. And as we’ve opened the aperture up there, it’s allowed us to do some more, it’s 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 fluid more was flowing toward share repurchases.

But we’ll continue to think about that opportunistically. I think the great thing is, 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 intrinsic value and versus our peers. And so those share repurchases made a lot of sense to us.

Neal Dingmann: It’s great to see have you guys doing well with this. Thanks, Dan.

Daniel Brown: Thanks, Neal.

Operator: Our next question comes from Philip Johnston with Capital One, please go ahead.

Philip Jonston: Hey, guys. Thanks. 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?

Daniel Brown: Yeah, thanks, Philip. So as we talked about, early when we set budget guidance for the year. We’ve really put a program together where we get — we started the year with one frack crew. We added a frack crew as we got out of winter and got into the warmer sort of easier months to operate in North Dakota. And that lasts essentially through the end of the third quarter. And so second quarter and third quarter, we ran two frack crews and first quarter and fourth quarter will only run one. And that’s really predicated around just winter weather in North Dakota. So that really explains the capital drop off, we’ll drop that frack crew and all the commits are completion, spinning will fall away from the program there.

Now, we’ll continue to tilt 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 that we produced, but we think it’s the more capital 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.

Philip Jonston: Yeah. Okay, that makes sense. 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 three and a half-ish kind of rig program or so. And then, on the mix of three-mile laterals, do you think it’ll be kind of similar this year around 50% or so? Or do you think it’ll be significantly different next year?

Daniel Brown: I think the Three Mile Lateral program probably be pretty similar to this year, we’re still working through the specific DSU that will drill next year, but I think it should be relatively similar. And from a drilling perspective, my anticipation is we’ll run around a four-rig program next year.

Philip Jonston: Okay, sounds good. Thank you.

Daniel Brown: Yep. Thanks Philip.

Operator: Our next question comes from Oliver Huang with TPH. Please go ahead.

Oliver Huang: Good morning, Danny, Michael, Chip and team. Thanks for taking my questions. I just wanted to kind of hit on the drilling side of things. The improvements had been rather sizable over the last six months, on the Three Mile laterals, just wondering how much more running room do you all see on this front? Or at the low hanging fruit already been captured? And also, how should we think about potential for dovetails into year end? If the accelerated pace were to increase or continue? And how might this help the 2024 program?

Charles Rimer : It’s Chip Rimer. Appreciate the question. Yeah, I’m really excited about what the team has done here. And I think Danny mentioned earlier in his script was, we capitalize on the best practices, we looked at the best practices from both companies going forward. So you can see or prior to merger, they’re probably averaging 17 days. And through those best practices, and it’s not just one or two things, it’s a lot of different things. The guys put together from different fluids to bid designs to BH bottomhole, 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 three days for the six months from now a little harder to do? But they continue to chase things down and make it more efficient. So that’s exciting piece about it. So we’ll keep doing it. And then we’ll play by your by the duck count, but right now, this is just really excited what our teams do on the drilling side. And I think it’s across the whole organization, from the completion side to the facility sides, it’s cradle to grave, so really excited what they’re doing.

Oliver Huang: Thanks, appreciate the color there. And just wanted to kind of follow up on the Three Mile Laterals, but just on the facility side of things. As you all start 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 Three Mile Lateral walls, just given the other areas where there’s probably been a little bit less activity historically?

Michael Lou: So Oliver, I think that’s a that’s a great question. As we put the development program together, we’re cautious and we’re drilling to make sure that we do have the infrastructure to have takeaway volumes there, whether that be through our gathering systems or more long haul pipelines or 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 precede us there as we go in. So that’s, that’s how we’ll design the program.

Daniel Brown: Now 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 it all in one area.

Charles Rimer : I think the other thing is the, Oliver, it’s Chip Rimer, but it’s also gas capture. We aim to keep those gas capture numbers up high, so you’re not concentrated in one area.

Oliver Huang: Awesome, appreciate the color. Thanks for the time, guys.

Operator: [Operator Instructions] Our next question comes from John Abbott with Bank of America. Please go ahead.

John Abbott: Good morning, and thank you for taking our questions. My first question is on GP&T. I understand that, if you are going to understand the accounting change and that if there’s no impact margin. But why make the change if there’s no benefit to you? So what is the –what is the benefit to you of switching from the sales to the transportation contract? And could we see a better realisation versus just assuming neutrality?

Daniel Brown: Yeah, it’s a good question, John. 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 base, and they’re 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 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.

John Abbott: That’s very helpful. And then just quickly for Michael. So Mike, so the understanding the cash tax guidance for the second half of year, zero to 5% to 10% of EBITDA. What’s your just your latest thoughts as you look for 2024 and beyond in terms of how that cash tax rates would have trends?

Michael Lou: Yeah, so cash taxes, later part of this year, kind of at zero 10% and $70 to $90 oil price. If you look at that kind of going forward, kind of thing 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 taxpaying going forward. But that’s going to kind of be the range to be thinking about.

John Abbott: Very helpful. Thank you for taking your questions.

Michael Lou: Thanks, John.

Operator: 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.

Daniel Brown: Thanks, Megan. Well, to close out I just want to thank the employees of Chord for their commitment and dedication to our organization. Last year was a pivotable pivotal year for our company. And I know the team worked hard to integrate to predecessor companies and put us in a great position to succeed going forward. And to our investors, I’d say Chord’s 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.

Operator: The conference has now concluded thank you for attending today’s presentation. You may now disconnect.