Chord Energy - Q2 2023

Transcript

Operator (participant)

Good morning, and welcome to the Chord Energy Second Quarter 2023 Earnings Results Conference Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on your touch tone phone. To withdraw a question, please press star, then two. 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.

Michael Lou (CFO)

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.

Danny Brown (CEO)

Thank you, Michael, and thank you to everyone who's joined our call on what I know is a very busy morning. 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 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 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-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. 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 turn-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.

Taking all of this into account, we've generated $116 million of adjusted free cash flow during the quarter, which, as presented in our deck, does include the removal of around $11 million of capital booked from non-operated wellbores, which had been sold and which will be reimbursed to us. Given this free cash flow generation, and in keeping with our return of 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. As we noted last quarter, we aimed to increase share repurchases as our % 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-mi laterals are an important part of our program in 2023 and beyond. I want to spend a little time discussing our latest performance and what we're expecting going forward. Year to date, we've tilled around 13 mi-3 mi 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 nine of our presentation shows, we have materially reduced drilling times for 3-mi 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 3rd mi. As a reminder, for 3-mi 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 3rd mi is only 80% as productive as the first 2 mi. In practice, what we're seeing is a volume response proportional to the percentage of the 3rd mi that's cleaned out. 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.

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-mi wells are clearly outperforming 2-mi 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 toe of the 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 well 10 weeks later to clean out 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-mi laterals that Chord 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 3rd mi of the lateral, which would obviously enhance our capital efficiency even further. 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-mi 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 non-core properties for proceeds of approximately $29 million. This includes approximately $11 million of capital reimbursement for non-operated 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 non-core sales approximate 500 bbl of oil per day.

For clarity, the 500 bbl 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 non-core 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 bbl 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 scaled 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 Chord, 2-mi DSUs into 3-mi 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 forecast to a range of $850 million-$880 million. Excluding the $11 million of reimbursed non-operated 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. 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.

In it, 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.

Michael Lou (CFO)

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 a 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 2Q and are improving into the 3Q, 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. TILs activity is concentrated in the 2Q and 3Q, leading to sequential production increases in the 3Q and 4Q. As Danny mentioned, we added some frac activity to the 4Q. 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, 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-$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 FTO 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 30th. Cash was approximately $215 million as of June 30th, which is net of the final cash payment made to FTO for the bolt-on deal that closed on June 30th. 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. 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, 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 fuels a better world. We're also proud of the entire Chord team, who continues 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 (participant)

We will now begin the question-and-answer session. To ask a question, you may press star one on your touch tone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star two. The first question comes from Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Hanold (Managing Director and Senior Energy Analyst)

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

Danny Brown (CEO)

Thanks for the question, Scott. I'm gonna, I'm gonna take a stab at this, then I'll ask Chip to weigh in for additional color if we need to. You know, to, to, to go with the second part of your question first, I think as we think about 3-mi laterals in, in general, you know, the early IP rates, and that early time production, really isn't too different from what we see with 2 mi. We're not, 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-mi than a, than a 2-mi, and then ultimately, the decline is shallower on a 3-mi than a 2-mi, because you just have more reservoir feeding in over time.

You know, generally, not a big uplift in, in IPs on.

On 2 mi versus 3 mi, but a lot better EUR, and clearly much more capitally efficient. From a, from a clean-out's perspective, that's actually one of the really exciting things to me. The part of the operation that is involved in, in getting out to the toe of the coiled tubing operations is one of the lowest cost portions of the operation. 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, some significantly improved volume contribution from that, from that, end portion of the well. Yeah, not a whole lot of incremental cost for it.

There may be, you know, in any, in any operation, there, there will be times where maybe we don't get 100% of it cleaned out, but, spending a little longer to get, to get, you know, essentially the entire, that entire lateral cleaned out, has a big opportunity for us to move that 80% contribution from the 3rd mi up closer to 100% contribution to the 3rd mi, which will be fantastic. I'll let Chip, Chip weigh in as well.

Chip Rimer (EVP and COO)

Scott Hanold, this is Chip Rimer. I'd agree 100% what Danny Brown said, you know, flatter for longer, of course, on versus the IPs. You know, I, we wanted to run the test to see what dissolvable plugs were doing. We're actually dissolving, do we have a clean wellbore or not? We ran that test and, and be able to look at those tracers and see what's going on. Identifying and be able to knock out that last little bit, as Danny Brown indicated, is a very small amount of, of dollars when it's all said and done. We have a lot better understanding of what the contribution is across the wellbore. 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 out as quickly as possible. For a very small amount of time, additional, we can hopefully get 50% of the wellbore versus 40%.

Scott Hanold (Managing Director and Senior Energy Analyst)

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

Danny Brown (CEO)

Scott, I'll, I'll, you know, I think as we look forward, clearly, we're trying to drive capital efficiency, improve capital efficiency in, in all aspects of our business. That's always the driver for us over here. As you know, this, this additional opportunity we see with the 3-mi laterals and the, and the coiled tubing drill outs that we just discussed, obviously, helps with that. You know, from a, from a deflationary sort of environment in oil field services, I'd say, you know, we're certainly seeing some encouraging signs in that, but I still think it's maybe a bit, a bit early to, to, to, really, roll forward with that in our full planning process.

We've got, you know, line items that are, that are certainly lower, but we also have some line items that are higher. Labor cost is generally, sticky. Now that we've seen, you know, some recovery in oil prices, which we're obviously very, thankful for, you know, that's probably likely to provide some support to service, to service costs as well. I think the deflation, we're, we're seeing encouraging signs. I'm not ready to, quite roll that, quite roll that through completely yet. We're gonna need to, see a little further. With respect to 2024, you know, I think we'll provide, we're working to develop a plan that's, essentially a maintenance level, plan, versus, versus, our current year.

We're gonna do that in as capitally efficient manner as possible. We'll talk more about that later this year and probably come out with full specific guidance in early 2024.

Scott Hanold (Managing Director and Senior Energy Analyst)

Understood. Thanks for that.

Danny Brown (CEO)

Thanks, Scott.

Operator (participant)

Our next question comes from Derrick Whitfield with Stifel. Please go ahead.

Derrick Whitfield (Managing Director)

Thanks. Good morning, all. Congrats on another strong another strong quarter.

Danny Brown (CEO)

Thanks, Derrick.

Derrick Whitfield (Managing Director)

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

Danny Brown (CEO)

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

Derrick Whitfield (Managing Director)

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?

Danny Brown (CEO)

Yeah. I think as we're able to see, I think as we're able to get more data on this, Derrick, that's the implication. That, that, that 80% recovery efficient 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 the entire lateral cleaned out. We'll see results coming through that. 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 for the last mile. That's the, that's the goal here.

Derrick Whitfield (Managing Director)

Thanks, Danny. As my follow-up, I wanted to ask if you could speak to the A&D environment in the well at present. More specifically, are you guys seeing greater deal flow now that oil has stabilized higher and private equity is seemingly trimming its holdings?

Danny Brown (CEO)

Yeah, I'd say, you know, from my perspective, Derrick, there's always been sort of a little bit of chatter in, in Williston across a whole variety of different assets from, I'd say, small asset positions, from trades to private equity opportunities. 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. You know, we evaluate a lot of things that come through. Some of them transact, some of them don't transact.

But we've got our ear to the ground, you know, with our position in the Williston, it is, you know, we feel like we are a natural consolidator within that basin. So we pay attention to what's going on. As you saw with the XTO acquisition, we think when, you know, when, when it, when we have opportunities out there that fit in well with what we're trying to accomplish, which that XTO acquisition did, we can, we can act, and we think, you know, it's really gonna accrete to value for the organization and for shareholders.

Derrick Whitfield (Managing Director)

That's great. Thanks for your time.

Operator (participant)

Our next question.

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comes from Neal Dingmann with Truist. Please go ahead.

Neal Dingmann (Managing Director)

Morning, guys. Could you tell me what's driving you? 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.

Danny Brown (CEO)

Yeah, thanks, Neal. So again, I'll, I'll lead off here and then ask Chip to weigh in with some additional color commentary. You know, in Indian Hills, I think we've 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-mi laterals. So, I really think it's a, it's a, it's a combination of subsurface quality, of wider spacing and of and of three-mile laterals. So, I think we've got a slide and a graphic in the deck, that shows, some of the varying contribution of, of that. But it's really a combination of all the, all three of those things. It's a, it's a great portion of our asset, and it's one we're, we're super happy with. Chip, anything further?

Chip Rimer (EVP and COO)

Yeah, yeah, 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 in other areas and going across the Basin. This back half of this year, you're gonna see us in different spots in the Basin, so I think we'll be able to have some results later next year for you, early next year, probably for you, and see how that's working. But really excited about what we're seeing in Indian Hills and what that's gonna do for the rest of the Basin.

Neal Dingmann (Managing Director)

Yes. Yeah, it really seems to be working well, guys. Then just my second on shareholder return. Danny, you kind of talked about this in prepared remarks, but I just wondered, does this mean you'll kind of diverge from what you were doing before? Or I know you talked about opportunistic buybacks. I'm just wondering if there's any thoughts of going to maybe, like, a, a unique plan there?

Danny Brown (CEO)

No, I think, you know, as we talked about last quarter, Neal, the, you know, 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. 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. 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, in what we did early in the capital return program, where we were being, you know, more focused on variable dividends, again, because of the framework we were looking at this through.

As we've opened that, aperture up, you know, more, more was flowing toward, share repurchases, but we'll continue to think about that, opportunistically. You know, I think the great thing is, is we're, 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. We think we, you know, we're, we're undervalued versus our NAV, versus our intrinsic value and versus, peers, and so those share repurchases make a lot of sense to us.

Neal Dingmann (Managing Director)

It's a great, great issue to have. You guys are doing well with this. Thanks, Danny.

Danny Brown (CEO)

Thanks, Neal.

Operator (participant)

Our next question comes from Philip Johnson with Capital One. Please go ahead.

Philip Johnson (Analyst)

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

Danny Brown (CEO)

Yeah. Thanks, Philip. You know, as we talked about, early when we set, when we set budget guidance for the year, we've really put a program together where we've got, you know, we started the year with one frac crew. We added a, 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 lasted essentially through the end of the third quarter. You know, the second quarter and third quarter, we ran two frac crews, and first quarter and fourth quarter, we'll only run one, and that's really predicated around, just, winter weather in North Dakota. That really explains the capital drop-off.

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

Philip Johnson (Analyst)

Yeah. Okay, that makes sense. 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? Then on the mix of 3-mi laterals, do you think it'll be kind of similar to this year, around 50% or so, or do you think it'll be significantly different next year?

Danny Brown (CEO)

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

Philip Johnson (Analyst)

Okay. Sounds good, Danny. Thank you.

Danny Brown (CEO)

Yep. Thanks, Philip.

Operator (participant)

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

Oliver Huang (Director in Exploration and Production Research)

Good morning, Danny, Michael, Chip, and team. Thanks for taking my questions. Just wanted to kind of hit on the drilling side of things. The improvements have been rather sizable over the last six months on the 3-mi laterals. Just wondering, how much more running room do you all see on this front, or has the low-hanging fruit already been captured? Also, how should we think about potential for DUC builds into year-end if the accelerated pace were to increase or continue, and how might this help the 2024 program?

Chip Rimer (EVP and COO)

Yeah. Oliver, this is Chip Rimer. Appreciate the question. Yeah, I'm really excited about what the team's done here, and, you know, I think Danny mentioned it earlier in his script, was, you know, we capitalize on the best practices. We looked at the best practices from both companies going forward. You can see we're, prior to merger there, 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 that, that the guys put together, from different fluids to bit designs, to BHA bottomhole assembly designs. You know, just tweaking the system a little bit every time. Excited what they've been putting together. You know, finding the right rigs with the right people on board also, and being able to move quicker and just be able to knock those prices down.

You know, am I gonna say they're gonna do another three days from, you know, the six months from now? Maybe a little harder to do, but they continue to chase things down and make it more efficient. That's the exciting piece about it. We'll keep doing it and, you know, and then we'll play by ear by the duck count. Right now, this is, I'm just really excited what our team's doing on the drilling side. The other thing, it's across the whole organization, from the completion side to the facility sides. It's cradle to grave, really excited what they're doing.

Oliver Huang (Director in Exploration and Production Research)

Thanks. Appreciate the color there. Just wanted to kind of follow up on the 3-mi 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 3-mi lateral wells, just given these are areas where there's probably been a little bit less activity historically?

Danny Brown (CEO)

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

Michael Lou (CFO)

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. Every every pipeline's gonna be a little bit better off because you're not concentrating it all in one area.

Chip Rimer (EVP and COO)

Yeah, I think the other thing is the, Oliver, it's Chip Rimer, but it's also gas capture. Being able to keep those gas capture numbers up high, so you're not concentrated in one area.

Oliver Huang (Director in Exploration and Production Research)

Awesome. Appreciate the color, and thanks for the time, guys.

Chip Rimer (EVP and COO)

Oliver?

Operator (participant)

Again, if you have a question, please press star, then one. Our next question comes from John Abbott with Bank of America. Please go ahead.

John Abbott (VP of Exploration and Production Research)

Good morning, and thank you for taking our questions.

Danny Brown (CEO)

Morning, John.

John Abbott (VP of Exploration and Production Research)

My first question is on GP&T. I understand that you've indicated I understand the accounting change and that it, there's no impact to margin. Why make the change if there's no benefit to you? What is the benefit to you of switching from the sales to the transportation contract? Could we see a better realization versus just assuming neutrality?

Michael Lou (CFO)

Yeah, it's a, it's a good question, John. You know, the, the contract is just kind of a form of, of how we're, we made some small changes in terms of how we're operating. So I, 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. They're still a positive differential to WTI, but they're just not quite as strong as, 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 (VP of Exploration and Production Research)

That's very helpful. Then just quickly for Michael. So, Mike, understanding the cash tax guidance for the second half of the year, 0%-5%-10% of EBITDA, you know, just what's your, just your latest thoughts as you look to 2024 and beyond in terms of how that cash tax rate sort of trends?

Michael Lou (CFO)

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

John Abbott (VP of Exploration and Production Research)

Very helpful. Thank you for taking our questions.

Michael Lou (CFO)

Thanks, John.

Operator (participant)

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.

Danny Brown (CEO)

Thanks, Megan. Well, to close out, I just want to thank the employees of Chord Energy for their commitment and dedication to our organization. Last year was a pivotal, a pivotal year for our company, and I know the team worked hard to integrate two predecessor companies and put us in a great position to succeed going forward. To our investors, I'd say Chord Energy'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 (participant)

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