Appreciate it. Thank you. Good morning, everyone. This is Bob Bakanauskas. And today, we are reporting first quarter 2025 financial and operational results. We are delighted to have you on the call. I'm joined today by Danny Brown, our CEO; Michael Lou, our Chief Strategy and Commercial Officer; Darrin Henke, our COO; Richard Robuck our CFO, as well as 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. And with that, I'll turn the call over to our CEO, Danny Brown.

Thanks Bob. Good morning, everyone and thanks for joining our call. Over the next few minutes, I’ll plan to provide a brief overview of our first quarter performance and results in current capital, discuss the current macro environment and Chord’s position and then briefly touch upon some of our current initiatives before passing it over to Darrin, who will provide more color on our operations. Darrin will hand it over to Richard for more details on our financial results before we open up for Q&A. So turning to first quarter results. Chord delivered another great quarter with solid operating results yielding free cash flow above expectations which supported robust shareholder returns. Specifically, first quarter oil volumes were above the capital guidance reflecting strong execution in well performance while capital was favorable to guidance largely reflecting improved program efficiency. Operating expenses also came in lower than our expectations as the team continues to drive improvements to our cost structure. And thanks to our entire organization for delivering favorable results once again and in particular to our folks in North Dakota who did an amazing job navigating extreme winter weather positioning us to surpass expectations. Fantastic job by all. This strong performance led to adjusted free cash flow for the first quarter of approximately $291 million. We maintain shareholder returns at 100% of free cash flow for the second consecutive quarter, repurchasing $216.5 million or about 2 million shares during the quarter. And since April 1, we have already repurchased another $45 million or about 500,000 shares at approximately $91 per share. We will be paying our base dividend of $1.30 per share on the lower share account, which equates to approximately $75 million. Since closing the Enerplus transaction, Chord has reduced its share count by approximately 9% through the end of April. To put that in perspective, Chord has repurchased over a quarter of the shares issued to purchase Enerplus in less than a year since the transaction closed. We were able to do this while keeping leverage essentially unchanged at about 0.3 times. Given our view on the intrinsic value of our shares relative to how they currently trade in the market, we expect a continued focus on share repurchases in the current environment. Turning to the macro, we are all keenly aware that the pricing outlook has deteriorated and volatility has increased since we entered the year and Chord is in the enviable position to navigate this type of environment. In the event conditions remain unfavorable or weakened, Chord has substantial operational and financial flexibility to moderate activity and maintain an efficient returns focused program with strong free cash generation. As Slide 7 illustrates, Chord has one of the lowest base decline rates amongst its peers, which supports our low reinvestment rate. Additionally, on the land side, Chord has no material drilling obligations as our acreage is essentially all held by production. On the midstream side, Chord is well covered with very limited volume commitments and we have intentionally laddered and structured our service contracts to provide program optionality. And finally, at a leverage ratio of 0.3 times, our balance sheet strength stands out versus our peer group. Our development plan also provides us with significant optionality. Chord started the year running five drilling rigs and two frac crews. In accordance with our original plan laid out in February, we have already reduced our frac crew count and by early June, we'll be running a program consisting of four rigs and one frac crew. Both our original and current guidance reflect the return of the second frac crew in the fourth quarter of this year. This allows us to monitor the macro environment at a lower activity pace and gives us the option to either bring back this second frac crew or just keep one frac spread through the end of ‘25 and into 2026. Letting it be clear that at current strip prices, we are inclined to maintain one frac crew instead of reinstating the second frac crew near year end. However, given the original plan already included a mid-year reduction in activity, we have several months to decide on this second frac spread with the final decision to be made in the third quarter. If Chord makes the decision to stay with one frac crew and not bring back the second, the production impact of 2025 would be negligible. However, fourth quarter capital would be much lower than current expectations. I should note that last night Chord announced a $30 million reduction to its full year capital guidance. This $30 million reduction largely reflects program efficiencies and does not currently contemplate any reductions to activity given we have until the third quarter to make the final call. And once again, Chord's full year volume expectations remain unchanged. Next, I'd like to discuss some of our initiatives to increase free cash flow given our track record of innovation and continuous improvement. Slide 12 outlines approximately $3 billion of controllable cash, controllable costs across the business between operated D&C capital, lease operating expenses, marketing expenses, and G&A. There is a concerted effort across every part of the organization to improve our cost structure and drive efficiency. We've already made progress this year in reducing our capital investment in LOE guidance with no impact to volumes. Our culture is built around continuous improvement and advancing efficiencies to improve our capital productivity and margins. A good example of this is our recent decision to lean into four-mile laterals with seven spuds now planned versus our original expectations of two to three. This follows our first four-mile lateral, which was successful on a variety of fronts, including being $1 million below budget and successfully cleaning the well out all the way to the toe. Production over the first couple of months for the well has been encouraging, but we really need to get past the flat period and initial decline to get a better sense of the ultimate productivity and recovery. Darrin will provide more details in his section, but it's fair to say, we like what we're seeing. In light of the improved capital efficiency and lower breakeven costs that long lateral development provides, Slide 11 illustrates an example of how Chord is reconfiguring acreage to optimize longer lateral development. You can see as Chord moves from the two-mile scenario to the four-mile scenario, it results in a 24% reduction in capital to develop the same amount of resource. This results in stronger rates of return and lower break-even pricing. Our goal is to convert our inventory to over 80% long laterals in the coming years, which will enhance economic returns. Since I arrived at the company over four years ago, we've had a successful track record of keeping our sub-$60 inventory position strong. We've done this not just through disciplined M&A, but also organically, through wider spacing, longer laterals, and program efficiencies. Going forward, we expect to further improve our inventory strength and returns by extending laterals and driving down costs. This will include straight three and four miles, as well as alternate-shaped well designs. On the LOE side, we've leveraged our scale to get more efficient, systematize processes, and reduce downtime. Looking forward, we have multiple initiatives to drive further improvement, including artificial lift optimization, faster cycle times, logistics improvements, and potentially leveraging newer technologies, such as predictive maintenance and remote well site monitoring. On the marketing side, we're driving efficiency through consolidating contracts from predecessor companies and negotiating competitive rates when contracts mature. Also, on the gas and NGL side, we are adding more dual and split connections to our facilities, which provides midstream optionality when the gas plants are down. This has the dual benefit of higher gas capture rates and additional revenue. Lastly, a few words on sustainability before handing it to Darrin. I want to reemphasize that Chord is proud of our work providing reliable and affordable sources of energy, so critical to every aspect of modern living. And we do this while maintaining a commitment to operating in a sustainable and responsible manner. On this front, Chord continues to make progress on our already strong sustainability initiatives with a focus on putting safety first, minimizing our environmental impact, and being a good partner in our communities. We plan to publish an updated Sustainability Report in the second half of this year, which will reflect the full integration of Chord and Enerplus. So, to summarize, while markets have taken a turn for the worse in recent months, Chord has a strong foundation and significant flexibility to adjust if needed. Chord was built around modest mid-cycle oil price expectations with the recognition that we operate in a cyclical business and there will inevitably be downturns from time to time. The steps we've taken over the past four years have lowered our cost structure, strengthened our inventory position, and enhanced flexibility in our development program, all while keeping the balance sheet and liquidity in an enviable place, allowing us to better navigate times like these. And with that, I'll turn it to Darrin.

Thanks, Danny. While the macro environment is challenging, the Chord team continues to execute with excellence, and we're off to a great start this year. We have tremendous confidence in our execution ability, and we have the flexibility and optionality to reduce activity if needed while still generating significant free cash flow at lower prices. As Danny mentioned, we are laser-focused on driving continued efficiency throughout the program. As a result, we were able to lower our 2025 capital by $30 million without changing our production targets. This $30 million reduction is incremental to the $90 million reduction to the 2025 budget versus pro forma 2024 capital. Furthermore, this $30 million reduction is also net of expected tariff pressure later in the year, which wasn't contemplated in our February guidance. We've certainly made a lot of progress improving capital productivity over the past year. Since we're on the topic of efficiency improvements, we wanted to give you an update on Chord's four-mile program. As announced earlier in the year, Chord successfully drilled and completed our first four-mile lateral and reached a TD exceeding 30,400 feet while cleaning out the frac plugs. The clean-out was executed in only one run and was much faster than we originally expected, leading to a total well cost approximately $1 million below the original budget. Additionally, we ran tracers on this well and subsequently observed every stage of the lateral contributing to production. Initial volumes and pressure indications are encouraging, but we need to monitor the flat period and initial decline before drawing definitive conclusions. Over the spring, Chord successfully drilled two additional four-mile wells, with drilling times, again, faster than expected. These wells are in the queue to be completed later this year. As we announced in April, we're planning to spud a total of seven four-mile wells over the next eight to nine months, and with success, Chord is likely to implement many more in 2026 and beyond. As a reminder, our initial approach to four-mile wells will be converting two two-mile DSUs to one four-mile DSU. However, similar to Chord's evolution on the three-mile program, as we make progress on execution and drive the risk-adjusted returns higher, we could ultimately look to convert some of our existing three-mile inventory into four-mile wells. Relative to two-mile wells, four-mile wells are expected to recover 90% to 100% more ultimate recovery for only 40% to 60% more capital. On a breakeven basis, four-mile laterals are expected to be anywhere from $8 to $12 per barrel lower than two-mile wells. It's important to remember that all else equal, longer laterals will deliver slightly higher IPs versus two-mile wells, staying flatter longer and exhibit shallower declines. When comparing analog well performance on a per-foot of lateral basis, initially, longer lateral wells will typically be lower than two-mile wells, as the higher IP is more than offset by the longer lateral. However, typically in a 6 to 12-month period, the longer flat period and shallower declines will lead longer laterals to catch up to the two-mile well on a recovery per-foot basis. Additionally, Chord's choke methodology is more restrictive than most peers, which minimizes sand flowback and ultimately lengthens the life of our ESPs, saving costs and delivering higher returns on average. Given our focus on improved returns versus higher IP rates, we have been implementing this more restrictive choke program on the Enerplus wells, which will impact the optics of initial IP rates per foot on a year-over-year basis. Again, per-foot performance is an appropriate way to judge well productivity over the long term, but early data can and often is misleading. Turning to LOE, Chord lowered its full-year guidance reflecting strong first-quarter execution and our current outlook. LOE has been a major focal point for the company in recent years, and Chord has been able to drive efficiency improvements through multiple avenues, including streamlining workover expenses and reducing downtime. Chord strives for additional improvements as we competently manage capital allocation, maximize returns, and efficiently generate free cash flow. Lastly, I wanted to comment on Chord's operational efficiency. Our teams continue to perform with excellence and aim to drive cycle times lower for both drilling and completions. We are drilling three-mile wells 13% faster than a year ago, and our full-time frac crew is using sample frac operations on most pads, which has driven down non-productive time and materially increased the lateral footage completed on a daily basis. Pumping hours per month are also well above basin peers. On the post-frac cleanout side, Chord continues to drive faster cycle times as we leave the basin in three-mile laterals. To sum it up, Chord's execution and delivery remain best in class. We're off to a great start in 2025 and look forward to additional progress as our teams relentlessly pursue continuous improvement and innovative solutions. I'll now turn it over to Richard.

Thanks, Darrin. I'll round out our conversation with some final thoughts that expand on comments made earlier and in our press release. I'll start with the strength of our balance sheet. In the first quarter, the team completed the issuance of a $750 million senior secured notes at 6.75% that are due in 2033, and by increasing our elected commitment amounts under our revolver to $2 billion. We continue to have pure leading leverage and strong liquidity as we navigate the current environment. We also layered on additional hedges during the first quarter, and our derivative position can be found in our latest investor deck. Next, I'll cover differentials. Oil differentials in the first quarter averaged $2.30 below WTI, which weakened slightly from our prior quarter but were within our original guidance range. We expect oil differentials to improve modestly over the course of the year, which is reflected in our updated guidance. NGL realizations were 20% of WTI in the first quarter, just above the midpoint guidance. Natural gas realizations of 63% were above the top end of guidance and benefited from seasonally strong regional prices in both the Bakken and Marcellus. We anticipate realized natural gas prices to soften during the middle of the year before improving modestly toward the end of the year, reflecting normal seasonality. As a reminder, certain marketing fixed fees are deducted from our NGL and natural gas prices. This drives higher operating leverage, which hurts realizations for both NGLs and natural gas in times of weaker prices and benefits realizations in times of higher prices. Separately, the team has done a great job managing costs, beating first quarter guidance with continued momentum for the balance of the year as LOE is down $0.30 per BOE and capital is down $30 million in our 2025 guidance. Production taxes averaged 6.8% of commodity sales in the first quarter, which was below our expectations. This primarily reflects the impact of non-recurring refund for stripper wells that received an adjusted tax rate during the quarter. The oil revenue from these low producing wells is taxed at a reduced rate. Additionally, the production tax rate was impacted by higher gas revenues as a percent of total sales as gas is taxed differently than oil. For the remainder of the year, we anticipate production taxes to average 8.5% of commodity sales. First quarter cash taxes were in line with our expectations at $34 million and we expect full year cash taxes to approximate 4% to 9% at WTI prices ranging between $55 and $75 per barrel. There have been no changes to full year cash tax guidance issued in February other than the yearly range now reflects actual first quarter results. In closing, thanks again to the Chord team for all their hard work and intense focus on improving day-to-day operations during the period of market uncertainty. We are pleased with the company's first quarter performance and believe that we are in a strong position to successfully deliver on our goals for the remainder of the year. With that, I'll hand the call over to Vincent for questions.

Ladies and gentlemen, we will now begin the question-and-answer session. The first question comes from Oliver Huang with TPH. Please go ahead.

Good morning, Danny and team, and thanks for taking the questions. Just wanted to start on activity levels. And I know there are many variables that go into the decision-making process and understand the biases to not pick up the spot right crew in Q4 at this time, whether it is more returns driven or just not wanting to chew through precious inventory at these oil prices. But if we're talking about crude with a five handle on it once Q4 and even early 2026 comes around, would one full-time simulfrac fleet be the default optimal ballpark of activity levels for 2026 as well? If you could just maybe walk through the thought process on what would need to happen to justify the bringing back of the spot crude for a portion of the year.

Thanks for the question, Oliver. And I think you framed it well. At the end of the day, it's really just a capital allocation decision for us. And it's going to depend on a variety of factors. So we'll be looking at service costs based on this. We'll be looking at our own share price candidly because, again, it's just a capital allocation decision. But all else being equal, I think what we would want to see is oil, I would say, firmly and what we would think would be in the 60s in order to bring that second frac crew back. So with oil at a five handle, again, all else equal, we probably would anticipate we'd have better capital allocation opportunities in an environment like that. And that's kind of how we're thinking about it. But again, we have not made that decision. We are in a really nice place just naturally through our program that we've reduced activity in this environment. And it gives us a chance to monitor. And so we've gone down to the single frac crew that's doing simulfracs for us. It's a very efficient program. And we'll maintain this. And we'll really make a final call on this in the third quarter. So no decisions have been made, but wanted to be transparent about kind of how we're thinking about this environment, and I think you framed the situation well.

Thanks, Danny. That's helpful color. And maybe for a follow-up, I think Slide 11 does a really good job in illustrating the magnitude of potential capital savings with a four-mile lateral program. And I know Darrin hit on it very briefly in the prepared remarks, but should we think about the potential move to incorporate a four-mile development plan being more gradual or an immediate jump from that 40% to 50% to the 80% goal? Because it would seem that once you're able to confirm the success, there should be very minimal reason to do two-mile laterals within the program. And any sort of color in terms of time frame we could see this progression on? And if you could remind us how big of an undertaking this would be in terms of altering previously approved permits?

I believe you framed it well. We transitioned quickly from a two-mile to a three-mile program, and I anticipate that we could move to a four-mile program just as quickly, if not slightly faster. We’ve gained confidence and improved our operational capabilities during the three-mile program, which has prepared us to start four-mile operations. I believe we can transition to this new program relatively quickly and perhaps even quicker than we did with the three-mile program. However, it will involve re-permitting and require our development team to effectively plan the layout of our various pads. Each location we have is mapped out, so this necessitates a comprehensive re-evaluation of our development strategy, including roads, midstream connections, and related factors. This does take some time as we navigate the permit process, but I expect that we will be able to move to this new program more swiftly than we did with the three-mile program. Overall, we are optimistic about what we are observing, and we see it as a significant opportunity to transition smoothly to the new program.

Awesome, thanks for the time Danny.

Thank you.

Good morning, everyone. For my first question, the first quarter appears to be a very strong quarter with oil production exceeding expectations. The second quarter also seems to be stronger than many of us anticipated in our models. Could you discuss how the oil production schedule looks for the third and fourth quarters of this year?

Thank you for the question, Noah. If you look at our guidance for the full year compared to what we achieved in the first and second quarters, you can infer that oil production will likely decrease, especially in the fourth quarter. Considering our shift to a one crew program right now and the possibility of adding a second crew in the fourth quarter, this also suggests a change in the timing of our oil production. We expect oil production to decline as we approach the end of the year. If we do add that second frac crew in the fourth quarter, it will allow us to start completing those wells, and we might begin to bring them online towards the end of the fourth quarter, more prominently in 2026, which will lead to an increase in our production cadence. However, we do foresee a slight drop in oil production as the crew is reduced. We will be bringing online fewer wells in the fourth quarter, resulting in a decrease in our production volumes during that time. If we decide to pick up the frac crew, we expect production to increase again in the first quarter.

And for the third quarter, last quarter results, you mentioned that 3Q would be above 2Q. Should we kind of think maybe put 2Q rising that 3Q would be flat versus the prior quarter?

Yeah. I think flattish to 2Q is probably a good expectation.

Great. And then for my second question, just could you maybe add a little more color on what's giving you guys the confidence to increase your original plan from spudding three, four-mile laterals to seven? And then will you be testing anything new with these additional wells like a different cleanout technique or anything else?

We've observed positive results, which is the short answer. I'll pass it to Darrin for more details. We're pleased with what we're seeing so far, and it's boosting our confidence. Now, over to Darrin for further insights.

Yeah. So we have three wells drilled now, and each well is drilled better than we anticipated. We've seen lower torque and drag. Just really operationally, everything has gone as well or better than expected. So that's definitely given us confidence to move forward with additional testing additional wells, which will help us convert to, ideally, a more longer lateral program, four miles, et cetera. Down the road, four miles, and when I say 'et cetera,' I'm talking about alternate well shape as well. So really, everything is going very well operationally in that regard, Noah. So that's just given us confidence to press forward faster.

Make sense, guys. Thanks.

Good morning all, congrats on a strong 1Q.

Thanks, Derrick.

Wanted to focus on your maintenance capital as my first question. If we were to assume the approximate 150,000 barrel per day rate implied by your second half guide, could the current rate of activity generate flattish growth in 2026? And if so, what would the maintenance capital be to sustain that at current cost and optimal level through all or greater laterals?

I think if the question is about maintaining 152.5, that relates to a 1.5 crew program. If we fall below that, it's probably unlikely we can maintain a 150 program. So, it would be something below that if you're referring to a one crew simulfrac program.

Terrific. And then just any color on what that would be from a capital perspective as you guys see cost at current?

As we look ahead to 2026, I typically don’t provide guidance this early, but considering the current dynamic environment, if we shift to a one frac crew program, we could see about a third of our operated activity coming from that program throughout the year. The 1.5 crews would deliver roughly a third of the TILs over the year, and there would be associated capital impacts as well as some additional volume if we pursue that approach.

Great. And then maybe just shifting over to your self-help slide on Page 12. Danny, if you or Darrin could just speak to how material the LOE and market contract opportunities could be to lower your cash costs? I know several of your marketing contracts are set to renew over the next few years.

I believe there is a significant opportunity in this area. We're definitely concentrating on capital expenditures, which often attract attention in the headlines. However, other factors also have a substantial effect on free cash flow. Every dollar, regardless of its source, contributes directly to that incremental free cash flow. As you mentioned, we have some marketing contracts expiring in the coming years, providing us with the chance to renegotiate those terms. Additionally, we have gained considerable advantages by consolidating various contracts. Our three legacy organizations each had agreements with different midstream providers, which made management cumbersome for both sides. We have managed to merge these into a single contract that gives us better rates, which is a positive outcome. Regarding our lease operating expenses, I see significant potential for improvement as we continue to utilize the scale we have achieved as a company to enhance and reduce these costs. I’ll let Darrin share some specifics about what we are examining.

We are actively collaborating with our vendors to lower costs, especially for chemicals. We are also focused on improving the run times of the legacy Enerplus wells to match those of the legacy Chord wells. By minimizing downtime and enhancing run times while reducing the need for workovers in the future, we can significantly cut costs and boost cash flow through increased production. We are continuously exploring these types of opportunities.

Good morning. Thanks for the question. Could you provide more detail on the total addressable market, particularly regarding the four-mile laterals compared to locations? You mentioned that this represents 50% of the program. Should we consider this when looking at the wider inventory numbers, or is there a different decline rate to expect over time?

Thank you for the question, Paul. As we consider our long lateral inventory, we aim for over 80% of our total inventory. The four-mile laterals represent less than 50% of our program, while we are targeting 80% for three-mile plus laterals. This approach provides significant efficiency improvements compared to a two-mile program. What was the second part of your question?

No. Should we be able to extend that perspective to total sticks in terms of inventory? Should we expect that to continue over time?

Lowering our breakeven economics significantly enhances our financial position. This shift enables us to reconsider inventory that previously seemed less appealing for development, as it can now yield attractive returns. Consequently, we can integrate more inventory into our operation by reducing our breakeven cost, which we are achieving with these four-mile laterals. This not only boosts our capital efficiency but also provides us with greater opportunities to continue developing the field.

Understood. Makes perfect sense. And just a quick follow-up. Given the current volatility, how should we think about any shifting sentiment with the macro? And as far as how that would kind of read through into your willingness to either expand or contract your existing hedge book?

There is a lot of volatility in the marketplace right now. We take a conservative approach to hedging because of our strong balance sheet, low reinvestment rate, and solid free cash flow, even at very low prices. Over time, we’ve noticed that people tend to hedge at the wrong times. When oil prices are high, they anticipate prices will rise further and avoid hedging. Conversely, when prices are low, they assume prices will remain low and hedge, which often results in poor decisions. One of the positives is the resilience of our business and the organization we’ve built acts as a hedge for us. We find some level of predictability beneficial, which is why our hedge book has been structured to cap our hedging at about 40% in the past quarter. We typically hedge less at lower prices and hedge more when prices are higher. This approach aligns with our understanding that we operate in a cyclical business, and we don't foresee significant changes to our hedging philosophy.

Yeah, thanks. Good morning, guys. Just wanted to ask on a couple of questions on the M&A side. First, just on the Marcellus, just wanted to see how you're thinking about that asset. Obviously, stronger gas prices this year relative to last year. How are you thinking about that as kind of a Chord fit within the portfolio right now and potentially use the proceeds there?

Yeah. So as we've said before, we like that asset. It's in the core of the basin. We've got a great operating partner associated with that. However, it's not core for our organization. And so we recognize that that's not a noncore position for us, and we're going to look to maximize value on that over time. Clearly, gas price relative to oil price is more constructive now than it has been historically. And so we're always looking at how we can maximize value.

And then just on Williston M&A, you guys are always active and looking to do some bolt-ons and other transactions. Have you seen any change in valuations or how people are thinking about transacting in the basin just given the lower oil prices right now?

I'd say the move has been pretty swift and still fairly recent. As a general comment, I would say that significant and rapid movements in price aren't really helpful for M&A, just in that it creates a bid-ask spread between buyers and sellers. That's not really helpful to getting deals done. So price stability is always a nice thing to have if you want to get deals done. So I haven't really seen any significant impact. But by the same token, I think it's our expectation that M&A may just be a little bit more challenged in this environment than it would be in an environment of more stability.

Hi, guys. The question is really about sort of the increase in cycle times from sort of two-mile to three-mile to four-mile. And as you sort of migrate to a greater percentage of the longer laterals. How will that sort of change your, I guess, cadence of spending and production if you kind of look out to 2026 and 2027?

My expectation is that while the cycle time per well is increasing, the cycle time per foot is decreasing. This means you can achieve the same lateral foot drilling with lower capital costs and fewer wells, depending on your objectives. If your goal is to deliver a specific well count, that's one perspective, but that's not necessarily our focus. We will assess the right capital allocation for our current environment, with production being a result rather than a factor in that decision. It's advantageous that the cycle times may extend, but per foot delivery shows significant improvement related to this.

That's fair. And then just a follow-up on Paul's question from earlier, just to make sure I understand the answer. When I look at Slide 6 with your inventory life at both sort of sub-50 and sub-60. As you migrate to the longer laterals, you're saying there won't be significant degradation in sort of the inventory life of the program?

We are measuring inventory life not just in terms of stick count, but in relation to our production capacity and the reserve delivery compared to what we are currently producing.

Hi, good morning. I apologize if you touched on this already, but can you talk about sort of the potential footprint expansion that four-miles could give you, just making locations or parts of the play that were not quite economic feasible?

I’m not sure how specific I can be about that. We've shared some acreage maps in the past, and we can discuss offline about areas that are on the outskirts of the basin where we faced challenges in competing for capital. As we explore opportunities to attract capital, moving to four-mile laterals should present attractive rates of return associated with development in those areas. Additionally, there will be a small footprint expansion connected to successfully transitioning to four-mile laterals because of the improvement in breakeven costs resulting from more efficient development designs.

No, the only thing I'll add is that the team has done an incredible job over the last few years, increasing capital efficiency through three-mile laterals, spacing, and four-mile laterals. All these initiatives are continuously benefiting the program. You heard in Danny's prepared remarks that he discussed a 10-year inventory life that's sub-60, and we've managed to maintain that flat at 10 years for the last four years. Some of this is due to mergers and acquisitions, but much of it comes from ongoing improvements. The team is enhancing economics by bringing acreage that currently isn't sub-60 into that sub-60 category. We still have a significant amount of acreage that's outside that sub-60 category today, but with four-mile laterals and the team's continuous advancements, we will keep bringing that into the 10-year inventory life and lower our current inventory life to a lower breakeven. The team is doing a great job in that regard.

Great. Great. And again, this is something that would just be incremental. But as I look ahead to the implications of the longer laterals sort of rippling through. Would you have enough data, production data from your first or early four-milers to be able to get any bits of re-rating upward as far as reserve bookings? I don't know if he had two two-mile pubs on the books that we're going to go to four with the better economics and so forth. And would that needle get moved at all?

I believe that as we transition our proven reserve base from two to four miles, we are effectively capturing the entire resource that's already accounted for in a more cost-efficient way. As we enhance our ability to leverage better breakeven economics, we can expand our inventory, which will gradually shift into the proven undeveloped category. The wells we are focusing on should hopefully represent the entirety of the resource from those two-mile wells, but we need to monitor this over time. We are already seeing positive trends with three-mile wells, and we need to ensure the same holds true for four-mile wells. By reducing breakevens and enhancing our capacity to develop the basin, we will add more wells, which will in turn transition into proven and undeveloped reserves, positively impacting our overall reserve situation.

So over time, there's a reserve impact biased upward and then capital bias downward, so the PV should be biased upward.

Terrific. Thanks a lot.

There are no further questions. I'll now turn the call back over to Danny.

I want to express my gratitude to all of our employees for their ongoing hard work and commitment to our organization. Despite the challenges in the macroeconomic environment, the company is in its strongest position since I joined four years ago. Our strategic initiatives, along with our exceptional operations team, have resulted in what we believe is a valuable and increasingly rare asset. Chord has a substantial production base with low decline rates and high oil cut, supported by a robust portfolio of economically viable, low-risk, conservatively spaced, oil-rich inventory. We are proud of our achievements and confident in our ability to succeed moving forward. We will continue to closely monitor the oil price environment and have the flexibility to optimize capital allocation in order to enhance returns and maintain strong free cash flow. Thank you for your interest, and I appreciate your participation in our call.

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.