Chord Energy Q2 2023 Earnings Call Transcript

Quartr
Provided by Quartr
August 3, 2023

There are 9 speakers on the call.

Operator

Morning, and welcome to the Cord Energy Second Quarter 2023 Earnings Results Conference Call. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions. Please note that this event is being recorded. I would now like to turn the conference over to Michael Lu, Chief Financial Officer.

Operator

Please go ahead.

Speaker 1

Thank you, Megan. Good morning, everyone. Today, we are reporting our Q2 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.

Speaker 1

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 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 ks 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, Reconciliations to the applicable GAAP measures can be found in our earnings releases and on our website.

Speaker 1

We may also reference our current investor presentation, 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 on 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 Cord has done over the past 12 months to integrate 2 premier Williston Basin operators and form a new, Stronger and more resilient organization.

Speaker 1

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. 1 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 $1,100,000,000 in the form of dividends and another $198,000,000 via share buybacks, including aggressively repurchasing steeply 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 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 executive team, Shannon Kenny.

Speaker 1

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, She was Vice President, Deputy General Counsel and Corporate Secretary. We are absolutely thrilled to have Shannon as part of the team and look 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 turn in lines or TILs early in the quarter.

Speaker 1

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 So taking all of this into account, we generated $116,000,000 of adjusted free cash flow during the quarter, which as presented in our deck, Does include removal of around $11,000,000 of capital booked from non operated well bores, which had been sold and which will be reimbursed to us. And 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 $5,000,000 is the difference between 75 of the $116,000,000 of adjusted free cash flow generated in the 2nd quarter minus the base dividend of approximately $52,000,000 Minus $31,000,000 of 2nd 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 discipline and shareholder returns.

Speaker 1

And as we noted last quarter, we aimed to increase share repurchases as a percentage of return capital in recognition of the That we believe Core trades at relative to peers and our intrinsic value. Accordingly, in the second quarter, share repurchases accounted for almost 90 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.

Speaker 1

Year to date, 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 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 clean out side, We've also made steady improvements and have generally been able to stimulate and access the vast majority of the 3rd mile. As a reminder, for 3 mile wells, we are assuming a 40% EUR 3rd mile is only 80% as productive as the first two miles.

Speaker 1

In practice, what we're seeing is a volume response proportional to the percentage of the 3rd mile that's cleaned out. So a 50% longer well that was cleaned out all the way to the TOW 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 Clearly outperforming 2 mile wells in the same area.

Speaker 1

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 1 or 2 stages further in the lateral Despite using dissolvable plugs, we came back to the well 10 weeks later to clean out the tow 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 Very low cost operation are effective all the way to the toe could allow us to increase the 80% efficiency number for the 3rd 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 is running slightly favorable to expectations.

Speaker 1

This can be attributed to the effectiveness of the 3 mile laterals we just discussed as well as our practice of 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 2nd quarter results, Core announced the sale of additional non core properties for proceeds of approximately $29,000,000 This includes approximately $11,000,000 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 Q2 capital return as you can see in our deck. Oil volumes associated with these non core 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.

Speaker 1

Year to date, Cord has announced over $64,000,000 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 barrels a day Per day of oil in the second half of twenty twenty three. This bolt on was an excellent supplement to our core inventory and demonstrates natural synergies from scale position in the Bakken, which is now over 1,000,000 acres. We added approximately 123 net locations and importantly, we were also able to convert 6 Chord, 2 mile DSUs and to 3 mile DSUs. This further enhanced the economics of the deal, which is immediately accretive to cash flow, free cash flow and our return metrics.

Speaker 1

In light of the above, we have updated our full year capital forecast to a range of $850,000,000 to $880,000,000 Excluding the $11,000,000 of reimbursed non operated capital, the midpoint of annual CapEx investment increased approximately $20,000,000 largely due to additional drilling and completions activity associated with maintaining a larger production base moving forward. And finally, a brief update on ESG. Gord expects to publish its 1st sustainability report as a combined company in the Q3 of this year. My thanks to the team for putting together a great piece of work. 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.

Speaker 1

To sum things up, the assets are performing well. We are substantially through merger integration and have become a 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 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 Q2 and discuss our updated 2023 guidance.

Speaker 1

As Danny mentioned, oil volumes We're strong in the 2nd quarter, about 1.5 percent 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 Q1 to ethane recovery in the Q2. 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 fees. Our TNF fees are allocated based on a percent of gas and NGL revenues.

Speaker 1

With weaker residue gas prices in the 2nd 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 2nd quarter and are improving into the 3rd quarter along with higher Henry Hub gas prices. Clearly, the Bakken has a bit higher gathering and processing fees 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.

Speaker 1

Till activity is concentrated in the 2nd and third quarters, leading to sequential production increases in the 3rd and 4th quarters. As Danny mentioned, we added some frac activity to the Q4. However, most of the wells will not be cleaned out until early 2024, So there is no volume impact in 2023. Turning to cash costs. LOE was a little below midpoint guidance, While GPT was above.

Speaker 1

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 percent 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.

Speaker 1

So better than expected gas production, Coupled with weaker prices resulted in a higher reported production tax as a percentage of revenue. As gas price recover, it will 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. Core cash G and A expense was $17,700,000 in the 2nd quarter, which was within the guidance Our 2023 G and A guidance remains unchanged at $63,000,000 to $73,000,000 Cord paid no cash taxes during the Q2.

Speaker 1

And in the second half of the year, Cord expects cash taxes to Approximate between 0% and 10% of second half EBITDA at oil prices between $70 $90 per barrel. Our full year capital budget guidance was increased about $20,000,000 at midpoint, mostly reflecting higher 4th quarter frac Turning to liquidity, Accord's borrowing base remains $2,500,000,000 Elected commitments remain at $1,000,000,000 with nothing drawn as of June 30. Cash was approximately $215,000,000 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 core 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.

Speaker 1

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 $200,000,000 of share buybacks 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 core team We continue 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

We will now begin the question and answer session. The first question comes from Scott Hanold with RBC Capital Markets. Please go ahead.

Speaker 2

Thanks and good morning all. I was wondering, Danny, you gave some kind of more details on Cleaning out the total of those 3 mile wells. Just out of curiosity, can you give us some sense like when you do that, is Does it take longer? Is there more cost to make sure it's properly cleaned out? And when you do get that contribution, typically, Does that influence IP rate?

Speaker 2

Is it more of a shallower decline, that ultimately leads to the higher EUR?

Speaker 1

Thanks for the question, Scott. 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 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 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 2 mile because you just have more reservoir feeding in over time.

Speaker 1

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 a clean out's perspective, that's actually one of the 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. 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.

Speaker 1

There may be in any operations there will be times where maybe we don't get 100% of it cleaned out, but 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 3rd mile up closer 100% contribution to the 3rd mile, which will be fantastic. So I'll let Chip weigh in as well.

Speaker 3

Yes. Yes, Scott. This is Chip. Yes, I'd agree 100% what Danny said, flatter for longer, of course, on versus the IPs. And then, we want to run the test to see what dissolvable We're actually dissolving, do we have a clean wellbore or not.

Speaker 3

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 little biz, Danny indicated 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 The team is really finding ways to get certain fluids, certain designs to make sure they're knocking this thing out as quickly as possible.

Speaker 3

But for a very small amount of time Additional, we can hopefully get 50% of the Wilbur versus 40%.

Speaker 2

That sounds Good. 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'd say, I guess, 2024 momentum because of those DUCs you mentioned. What does 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 two factors and That coupled with, I guess, OFS cost reductions seems to be moving in your favor.

Speaker 1

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'd 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.

Speaker 1

And now that we've Some recovery in oil prices, which we're obviously very thankful for, that's probably likely to provide some support to service cost 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 getting to see a little further. And with respect to 24, 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 as 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.

Speaker 2

Understood. Thanks for that.

Speaker 1

Thanks, Scott.

Operator

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

Speaker 4

Thanks. Good morning all. Congrats on another strong Start to another strong quarter.

Speaker 1

Thanks, Derek.

Speaker 4

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 interrupt your recovery assumptions for the last mile?

Speaker 1

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

Speaker 4

Sure. Given the proof of the TRACER data on Slide 10 of your presentation, does that bias Your recovery assumptions for the last model of the lateral?

Speaker 1

Yes. I think as we're able to see I think as we're able to get more data on this, Derek, that's the implication, 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 6 wells we've gotten essentially out We've gotten the entire lateral cleaned out. So 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 We can start moving that 80% recovery in the last mile up closer to 100% recovery for the last mile.

Speaker 1

So that's the goal here.

Speaker 4

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

Speaker 1

I'd say from my perspective, Derek, 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 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. It is we feel like we are a natural consolidator within that basin and so we pay attention 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 accrete to value for the organization and

Operator

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

Speaker 5

Good 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 point to the details there?

Speaker 1

Yes. Thanks, Neil. So again, I'll lead off here and then ask Chip to weigh in with some additional color commentary. In Indian Hills, I think we 1, 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.

Speaker 1

And so I really think It's a combination of subsurface quality of wider spacing and of 3 mile laterals. And so I think we've got a slide and a graphic in the deck That shows some of the varying contribution of that. But it's really a combination of all three of those things. But It's a great portion of our asset and it's one we're super happy with. Yes,

Speaker 3

Neal. 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 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 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 going to do for the rest of the

Operator

basin.

Speaker 5

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 prepared remarks. I just wondered, Does this mean you'll kind of diverge from what you're doing before and would you think they'll go to more of a formulaic plan? Or I know you talked about opportunistic buyback.

Speaker 5

I'm just wondering if there's any thoughts on going to maybe like a unique plan

Speaker 1

there. No, I think as we Talked about last quarter, Neil, the thought was as we were just being too restrictive on how we were judging our performance, particularly relative to others. 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.

Speaker 1

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 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 we'll continue to do that. And we think we're undervalued versus our intrinsic value and It appears and so those share repurchases made a lot of sense to us.

Speaker 5

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

Speaker 1

Thanks, Neil.

Operator

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

Speaker 6

Yes, 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?

Speaker 1

Yes. Thanks, Phillips. 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 will last essentially through the end of Q3. And In the Q2 and Q3, we ran 2 frac crews.

Speaker 1

In the Q1 and Q4, we'll 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 commiserate Completion spinning will fall away from the program there. Now we'll continue to till those wells as we get into the Q4 and a bit into the first Order as well, and then we'll start resuming capital activity.

Speaker 1

So I recognize it does provide Some cyclicality in the production profile that we produce, 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.

Speaker 6

Yes. 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 3.5 ish kind of rig program or so?

Speaker 6

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?

Speaker 1

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 Should be relatively similar. And from a drilling perspective, my anticipation is we'll run around a 4 rig program next year.

Speaker 6

Okay. Sounds good, Danny. Thank you.

Speaker 1

Yes. Thanks, Phillips.

Operator

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

Speaker 7

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 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?

Speaker 7

And also how should we think about potential for DUC build into year end if the accelerated pace were to increase or continue? And how might this help the 2024 program?

Speaker 3

Oliver, this is Chip Reimer. I appreciate the question. Yes, 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.

Speaker 3

So you can see we're Prior to merger, they're 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 BH bottom hold 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. Am I going to say they're going to do another 3 days for 6 months from now, maybe a little harder to do, but they continue to chase things down and make it more efficient.

Speaker 3

So that's the exciting piece About it. So we'll keep doing it and then we'll play by ear by the duct count. But right now, this is I'm just really excited what our team is doing on the drilling 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.

Speaker 7

Thanks. Appreciate the color there. And just wanted to kind of follow-up on the 3 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 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

Speaker 1

So Oliver, I think 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 system, through 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 Any significant constraints as a result of going into these other areas because we'll have the infrastructure sort of Proceed is there as we go in. So that's how we'll design the program.

Speaker 1

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 I'm 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.

Speaker 6

Yes.

Speaker 3

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

Speaker 7

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

Operator

Our next question

Speaker 8

Good morning, John. My first question is on JP and T. I understand that you've been I understand the accounting change in that. There's no impact to margin. But why make the change if there's no benefit to you?

Speaker 8

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?

Speaker 1

Yes. 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.

Speaker 1

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.

Speaker 8

That's very helpful. And then just quickly for Michael. So Michael, understanding the cash tax guidance The second half of the year, 0% to 5% to 10% of EBITDA. What's your latest thoughts as you look to 2024 and beyond in terms of how that cash tax Great sort of trends.

Speaker 1

Yes. So, cash taxes later part of this year, I kind of said 0% to 10% $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

Operator

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

Speaker 1

Thanks, Megan. Well, to close out, I just want to thank the employees of Cord for their commitment 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 Cord's position 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.

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