Q3 2024 Chord Energy Corp Earnings Call
Good morning, ladies and gentlemen, and welcome to the Cord Energy 3rd Quarter 2024 Earnings Call. At this time, all lines are in listen-only mode.
Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please press star followed by zero for the operator.
Speaker Change: This call is being recorded on Thursday, November 7, 2024. I would now like to turn the conference over to Bob Bakanauskas, Vice President, Investor Relations. Please go ahead.
Speaker Change: Thank you, Dion, and good morning, everyone. This is Bob Bakanauskas.
Today we're reporting our third quarter 2024 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, and other members of the team.
Speaker Change: 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.
Speaker Change: 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 release and conference calls.
Speaker Change: Those risks include, among others, matters that we have described in our earnings release, 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.
Speaker Change: During this call, we will make reference to non-GAAP measures and reconciliations to the applicable GAAP measures can be found in our earnings release and on our website.
We may also reference our current investor presentation, which you can find on our website.
Speaker Change: And with that, I'll turn the call over to our CEO, Danny Brown.
Danny Brown: Thanks Bob. Good morning everyone and thanks for joining our call.
Danny Brown: Over the next few minutes, I plan to provide a brief overview of Chord's third quarter performance and resulting return of capital before turning the discussion to our three-year outlook which Chord released last night.
Danny Brown: From there, I'll turn it to Darrin who will comment on our operations, including capital efficiency improvements, which support what we think is a compelling outlook. Darrin will then pass it to Richard for more details on our financial results before we open it up to Q&A.
Danny Brown: But before that, I wanted to take a few quick moments and make some comments on recent events in North Dakota.
Danny Brown: In early October, several wildfires spread in the northwest portion of the state, which tragically led to two fatalities, as well as damage to property and equipment.
Danny Brown: We are very thankful that the CORD team is safe. However, our thoughts and prayers are with the affected communities and citizens as they rebuild.
Danny Brown: CORD is also grateful for the leadership shown by both the state and MHA nation during the fires, and for the efforts of our field personnel which proactively shut in various sites and facilities and coordinated with local authorities.
Danny Brown: The curtailments to our production were short-lived, and we expect the impact of 4.25 oil volumes to be about 900 barrels of oil per day, which is reflected in our guidance.
Danny Brown: Turning to third quarter results, CORE delivered another great quarter with solid operating results yielding free cash flow above expectations which supported robust shareholder returns.
Danny Brown: Specifically, third quarter oil volumes were toward the top end of guidance, driven by strong execution, well performance, and lower downtime.
Danny Brown: Capital was below expectations, reflecting operational efficiencies, lower than expected cost, as well as timing adjustments to the program.
Danny Brown: Operating expenses also came in below expectations as the team continues to improve operating margins. My thanks to our field, development, and execution teams for delivering favorable results really across the board. Fantastic job by all.
Danny Brown: This strong performance led to adjusted free cash flow for the quarter of approximately $312 million and CORD will be returning 75% of this amount to shareholders.
Danny Brown: Given our base dividend of $1.25 per share, and our normal course share repurchases in the quarter of $146 million, we declared a variable dividend of $0.19 per share.
Danny Brown: After the base dividend, share repurchases represented 93% of capital return for the quarter and we bought back over 1.5% of shares outstanding.
Danny Brown: Given the compelling valuation we see at our current share price, we expect to continue to lean into buybacks in this environment.
Danny Brown: Additionally, CORD announced the divestiture of the DJ Basin assets acquired via the Interplus transaction and expects to use net proceeds to fund acquisition opportunities as well as repurchase shares. We would expect any repurchases related to the DJ sale to be incremental to the normal course return of capital program.
Danny Brown: Additionally, last night we issued fourth quarter and updated full year guidance.
Danny Brown: Net of the divestiture, we increased full year pro forma oil guidance for the second time this year, despite the impact from the fires, mostly reflecting outperformance in the third quarter.
We also trimmed full-year capital guidance reflecting improved program efficiencies.
Danny Brown: We are also training well on operating expenses and are pleased with the progress we're seeing over the last year or so on this front.
Danny Brown: Finally, we lowered gas volumes to reflect our latest estimates for our non-operated Marcellus production.
Danny Brown: Turning to our three-year plan, the core team has been working diligently to integrate the Interplus assets, drive synergy capture, and enhance our capital efficiency.
Danny Brown: We are now far enough along for the integration that we feel confident providing a medium-term outlook for our organization.
Danny Brown: Namely, holding oil volume steady at 152,000 to 153,000 barrels per day from 2025 through 2027 with annual capital expenditures of $1.4 billion per year.
Danny Brown: Our plan reflects the value the team has created through their focus on strong operational performance, continuous improvement, capturing over 200 million dollars of synergies annually.
Danny Brown: and represents the quality and depth of our inventory. Importantly, this is our current look, and we see further upside to these plans as we work to continue to extend lateral links, including incorporating four-mile wells, and push continuous improvement and cost reduction across all aspects of our business.
Danny Brown: Our strategic actions, coupled with our fantastic operations team, have created what we believe is a valuable and increasingly rare asset.
Danny Brown: CORD has a substantial, yet low decline and high oil cut production base, which is paired with a deep portfolio of highly economic, lower risk, conservatively spaced and oil rich inventory.
Danny Brown: We feel great about what we've accomplished and have a lot of confidence in our underlying assumptions and operational performance to deliver our plans.
Danny Brown: As a reminder, in our presentation we've included some material focused on helping investors better understand how attractive the Williston Basin is from an investment standpoint.
Danny Brown: We've added a graph contrasting the major lower 48 basins in terms of average cumulative oil recovery per well versus time. This is admittedly simplistic as it ignores other factors such as well cost, but it does highlight how productive Williston wells are versus other basins.
Danny Brown: We think there is a bit of a misconception out there that the Bakken's cost of supply is materially higher than that of other basins. But if you look at the well data and basin-specific productivity measures, you can clearly see the Williston Basin competes quite favorably with other oily basins.
Danny Brown: While our team and assets delivered another oil beat in the third quarter, we have had queries recently from folks trying to better understand early production data that may have led to concerns about us meeting our production guidance.
Danny Brown: I wanted to use this call as an opportunity to help investors understand trends seen in the state reported data. First, early time production is inherently volatile and impacted by a myriad of factors.
Danny Brown: These may include midstream issues, water disposal constraints, downtime related to artificial lift installation, testing, or a host of other factors that have nothing to do with a well's inherent productive capacity and expected ultimate recovery.
Danny Brown: Second, there is also a variability across the basin on flowback methodology.
Danny Brown: In some instances, wells are brought online at high IPs and sharper declines.
Danny Brown: While other instances you see wells brought online more gradually resulting in less early time production, but improved longer-term performance
Danny Brown: As a reminder, cord has shifted to drilling more widely spaced and longer laterals, on average, than others in the basin.
Danny Brown: While we don't initially flow these wells back as hard as some other operators, we believe our wells benefit from lower declines and higher ultimate recovery over time.
Danny Brown: This is demonstrated on slide 8, which shows that CORD's 12-month oil cumes are among the best in the basin, while our 3-month cumes are more average performers.
Danny Brown: Note as well that as we move to longer laterals we are not moving our initial production rates up and lockstep with the increased lateral length.
Danny Brown: So, as the average lateral length of the program increases, when looking at per foot productivity, production will be divided by a greater denominator and will show lower early-time well productivity.
Danny Brown: This analysis misses two things. One, we see per foot recovery catching up over time due to the lower decline. And two, well costs for the longer laterals are dramatically lower, meaning the resulting returns are significantly higher as we move to three-mile wells.
Danny Brown: Slide 8 adjusts for these factors and shows cords lateral length adjusted average 2023 and 2024 well productivity relative to drilling and completions cost.
Danny Brown: By dividing well productivity per foot by drilling and completions cost per foot, it gives a sense as to the overall capital efficiency of the program. As you can see, 2024 program starts off a little below 2023, but quickly catches up and ultimately surpasses last year due to a higher concentration of three-mile wells.
Danny Brown: To sum it up, the Longer Lateral Program is working and delivering greatly improved capital efficiency and returns. We encourage investors to observe our long-term well data in light of our wider spacing, conservative flowback strategy, inherent variability in near-term data, and the nature of longer laterals.
Speaker Change: And finally, before I turn it over to Darrin, I want to say that we are committed to delivering affordable and reliable energy, and to do so in a sustainable and responsible manner. In the spirit of transparency with our stakeholders, we recently published CORD's 2023 Sustainability Report.
Speaker Change: Thank you to the team for putting this together as it does a great job discussing our business and highlighting our efforts on emissions reductions, workforce health and safety, corporate governance, philanthropy, and other topics.
Speaker Change: We welcome feedback from our stakeholders on our progress and look forward to building upon our ESG efforts to shape an even stronger future for CORD and the communities we serve.
Speaker Change: To summarize, I couldn't be more pleased with the state of the business, and we are in a fabulous position to generate substantial value in the coming years. With that, I'll turn it to Darrin.
Darrin Henke: Thanks, Danny. Operationally, it was a strong quarter as the team continues to deliver.
Darrin Henke: I want to take a few minutes and discuss the strength of our asset base and all the factors giving core operational momentum into 2025 and beyond.
Speaker Change: I've been at CORD almost a year now and have been impressed with the culture of continuous improvement as the team constantly challenges themselves to drive efficiencies through leveraging technology and innovation.
Darrin Henke: Cord remains an industry leader in executing longer laterals, and the results have been impressive. We've turned in line over 100 3-mile lateral wells the past few years, while DNC cycle times and clean-outs continue to improve.
Darrin Henke: This quarter, we formally updated our third mile productivity assumption to be essentially identical to the first two miles.
Darrin Henke: Slide 7 of our investor presentation highlights over 60 three-mile wells with sufficient production history to illustrate the recovery is higher than our original type curves, yielding increased ultimate recoveries and better capital efficiency.
Darrin Henke: One of the largest technical accomplishments involves cleaning out the third mile, where the C.O.R.E. team has routinely been successful drilling out the frack plugs and reaching TD on most wells.
Darrin Henke: ProFOMA cords inventory consists of approximately 40% longer laterals and we believe we can increase that percentage materially over the next few years.
Darrin Henke: Just a quick update on 4-Mile Lateral Wells. CORD recently spud its first 4-Mile Lateral and plans several more in 2025.
Darrin Henke: We expect to have results from our first four-mile well by the second half of next year and are likely to implement more four-mile wells in 2026.
Darrin Henke: Turning to well spacing, it's important to consider CORD's average spacing across the basin is wider than other operators. This conservative spacing has helped keep declines shallow, production flat, and reinvestment rates low.
Darrin Henke: Slide 8 highlights cords decline rate relative to our peers, which compares quite favorably.
Darrin Henke: This advantage is driven not only by wider spacing, but longer laterals tend to have shallower initial declines as well.
Darrin Henke: Wider spacing has been a key driver to improve CORD's capital efficiency in recent years as it has delivered similar DSU recoveries with substantially less wells and capital.
Relative to integration,
Darrin Henke: We remain extremely confident in the strategic and financial benefits of the Interplus transaction. Our combined team has done a remarkable job integrating the assets, people, processes, and systems, all the while delivering an outstanding operational quarter.
Darrin Henke: Danny outlined our three-year plan where performance improvement is driven by operational advancements in Synergy Capture.
Speaker Change: Court expects to enhance returns on legacy Interplus assets by applying techniques it has developed over the past several years, including longer laterals, optimized spacing, and reduced downtime.
Speaker Change: On the drilling side, we are in the process of upgrading the legacy Interplus rigs to Chord specs, and we continue to set new records, with six of our eight fastest wells being drilled in the third quarter.
Speaker Change: To put this into perspective, we are drilling over 30% more feet per day than we were just one year ago.
Speaker Change: On the completion side, we are implementing simulfrac operations on most pads, which has driven down non-productive time, leading to well cost savings and getting production on quicker.
Speaker Change: Somnofrac has resulted in a 40% increase in fracked feet per day.
Speaker Change: Our operations team has driven costs down across the entire wellbore, including profit costs, by utilizing 100% local sand.
Speaker Change: Downtime continues to improve especially as we adopt CORD's best practices across our entire asset by also driving continuous improvement.
Speaker Change: To sum it up, CORD has an impressive track record of consistent execution and strong returns. We look forward to delivering on our long-term outlook. I'll now turn it over to Richard.
Richard Robuck: Thanks, Darrin. I'll focus my comments on the third quarter results and then discuss updates to our guidance. In the third quarter, Ford generated adjusted free cash flow of 312 million dollars with strong volumes, lower capital, and good cost control contributing to the upside.
Speaker Change: Oil volumes were towards the top end of guidance, while total volumes were above the top end.
Speaker Change: Oil realizations in the third quarter averaged about $1.50 below WTI.
Speaker Change: NGL realizations as a percent of WTI were at the low end of the guidance range of 8% and natural gas realizations were below the low end of the range at 20% of Henry Hub
Henry Hub averaged
Speaker Change: $2.16 per MBTU, which was weaker than our Outlook, which was set at strip at the time we released earnings last time.
Speaker Change: Realized gas prices in the Bakken were negatively impacted by depressed pricing at ACO.
Speaker Change: which is a gas hub in which our gas prices are mostly correlated. ACO started dislocating from its historical discount to Henry Hub around the second quarter and that dislocation continued into the third quarter.
Speaker Change: Additionally, 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.
like the most recent quarters we've experienced.
Speaker Change: With gas prices trading at low levels, the fees deducted from our price results in lower realization as a percent of benchmark price.
Speaker Change: Returning to operating costs, LOE was below expectations at $9.56 per BOE, reflecting better downtime and lower workover costs.
Speaker Change: Cash GPT was $2.91 per BOE. Cash G&A was $27.9 million excluding merger related costs of $17.5 million.
Speaker Change: Production taxes averaged 9% of commodity sales in the third quarter reflecting higher oil contribution in our revenue mix.
Cash taxes of $13 million was below our expectations.
Speaker Change: CapEx of 329 million dollars was below the low end of our guidance.
reflecting program efficiencies and minor shifts in program timing.
Speaker Change: As of September 30th, CORD had $470 million drawn on its $3 billion credit facility, which has $1.5 billion of elected commitments.
Speaker Change: Liquidity as of September 30th was 1.1 billion dollars including 52 million dollars of cash and approximately 1 billion of availability under our credit facility net of letters of credit.
Net leverage was 0.3 times at September 30th.
Speaker Change: During the third quarter, Corp repaid $63 million of Interim Plus senior notes and net debt decreased by $20 million, even as we paid out our second quarter dividends of approximately $156 million and bought back $146 million of shares during the quarter.
As we look forward now, on a pro forma basis...
Speaker Change: Cord increased its oil guide by about 600 barrels a day, which marks the second consecutive volume guidance increase this year. The midpoint of our fourth quarter oil guide
Speaker Change: of 152,000 barrels of oil per day would have been approximately 153.3 thousand barrels of oil per day adjusting for the impacts of the D.J. divestiture and the shut-ins related to the wildfires.
Speaker Change: Oil differentials are improving in the Williston Basin to the best levels we've seen all year, so we're capturing that in our fourth quarter guide. Our marketing team continues to deliver basin leading oil differentials.
Speaker Change: NGL realizations are expected to be similar to the third quarter. And as I discussed earlier, natural gas realizations have been weaker due to eco-pricing.
Speaker Change: The recent improvement in ACO pricing is reflected in our realized natural gas pricing guidance. Looking out and further in time, realizations should also improve quickly in environments where gas prices rise.
Speaker Change: On the cost side of the business, we're expecting basically flat LOE and GPT quarter-over-quarter. Our G&A guidance remains unchanged, and it does not include the impact of merger-related items, which are continuing to step down each quarter.
Speaker Change: Cash taxes are expected to be 0% to 5% of adjusted EBITDA in the fourth quarter at prices ranging between $60 and $80 per barrel WTI, which is down from our original expectations.
Our Preliminary 2025 Expectations
Speaker Change: reflect cash taxes of 2 to 11 percent at prices of 60 to 80 dollars per barrel WTI
Speaker Change: With the team continuing to get more efficient we lowered our pro forma full year capital spending guidance by 10 million.
Speaker Change: Separately, CORD layered on some hedges during the quarter and since our last update. So our derivatives position
as of November 5th can be found in our
Speaker Change: In closing, the team's hard work on integrating the Interplus asset while at the same time improving day-to-day operations gives me great conviction in our ability to deliver our three-year plan that we just rolled out. I have great confidence in the team as a technical and operational leader in the Williston Basin.
Speaker Change: Y'all delivered another great quarter and have positioned us in an enviable place to continue to add value for our shareholders in the future. With that, I'll hand the call over to Dion to open up the line for questions.
Speaker Change: Thank you. Ladies and gentlemen, we will now begin the question and answer session.
Speaker Change: Should you have a question, please press the star followed by the number one on your touchstone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press the star followed by the number two.
Speaker Change: If you are using a speakerphone, please lift the handset before pressing any keys.
One moment please for your first question.
Speaker Change: Your first question comes from Neil Dingman of Trust Security. Please go ahead.
Neil Dingman: Morning guys, nice quarter. My first question is around that, I like that three-year plan of yours. I'm just wondering...
There are various commodity price scenarios where you would alter.
Neil Dingman: I'm wondering if you continue to see further operational efficiencies, Dan, as you and the group have, would that cause you to increase activity or would you maintain activity and just you'd see the free cash flow boost?
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Yeah, so thanks for the question, Neil.
on the
Speaker Change: On the latter part of your question with respect to sort of what we're gearing this around, it would really be around if we saw increased efficiencies, which, candidly, we've seen the teams have been delivering increased efficiencies really quarter on quarter. And so I don't think we're at the end of that. The train hadn't reached the station on that. I expect we will continue to see increased efficiencies relative to what we put in this plan. And if and when we do see that, we're going to not increase activity. We won't be managing to sort of holding a capital level flat and let production float up. We're going to do the exact opposite, just kind of maintain a flattish production profile. And if we see if we need to spend less capital, do so. Fantastic. And we'll just let some more free cash flow flow through the system.
Neal: I was hoping you'd say that and then go ahead guys we can say so no what was your first question again Neal
Speaker Change: was more just on the the price sensitivities you know again if we had a 60 versus 80 I just how stable that plan would be
Speaker Change: Yeah, I'd say, you know, the plan is really sort of geared around our, I'd say, current commodity price environment. Obviously, we are going to be observing what the market is telling us. This is all just a capital allocation decision at the end of the day. We think we've got great inventory. We've got great, sort of a great asset.
Speaker Change: But if the market is telling us something vastly different from where we're at right now, then we're going to respond, we'll respond accordingly and allocate capital accordingly. So if we saw dramatically lower commodity prices, we would have to think, what's the market telling us, and should we continue to execute the plan as contemplated, or do we have better capital allocation opportunities?
Speaker Change: Simultaneously, if we saw prices spike, telling us the market was undersupplied, and we weighed this relative to our other capital allocation opportunities, we might choose to do something a little different. But, sort of call it a round of band of where we're at today. We think this plan is, you know, a solid one, very, very, very achievable, maybe somewhat conservative, and we expect to be able to deliver upon it or do a little better.
Speaker Change: Great and then second question maybe just around now you've got such a large 1.3
Speaker Change: Bill, an acre position. I'm just wondering how you maybe see the variability around this, you know, specifically given the improved completions.
Speaker Change: that you're seeing now really throughout much of the portfolio. I'm just wondering, you know, how do you see well break-evens? You know, I don't know, like if you look in the west in Williams and McKenzie counties versus, you know, going east around Mud Trail and Dunn, how different do break-evens now suggest?
Speaker Change: You know, the interesting thing about it, Neil, is as we look at our acreage out more toward the west relative to what I'm going to call sort of the historic core of the basin.
Speaker Change: In the historic core of the basin, we're, just due to the legacy development plan, we're probably more two-mile lateral development there.
Speaker Change: And so if you look at the three-mile laterals we can do out further in the west where we don't have as much legacy development and we're able to put the units together a little more differently, we see sort of, you know, really similar returns and investment opportunity between the two. And so that's a really neat thing about what we've been able to do as we moved over to a little bit wider spacing and longer laterals out in the western portion of the acreage is you're able to deliver returns that are pretty similar to the core.
Speaker Change: Now the underlying geology in the core continues to be better, and so for, you know, sort of same same, the core is the core, but we've been able to generate economic returns that are similar to the core, moving out west by drilling longer in space and a little wider.
Great. Thank you, Dan.
Thank you.
Speaker Change: Your next question comes from Scott Hanold of RBC. Please go ahead.
Speaker Change: that gave you confidence in, you know, now expecting similar EURs per foot. Just talk through, like, you know, some of the challenges or physical challenges that you have overcome as you obviously get out closer to the toe.
Speaker Change: Yeah, thanks, Scott. So I'm going to start off with this and then turn it over to Darrin for some color commentary at the end, but I think really, Darrin mentioned in his prepared remarks that getting out sort of to the full lateral length, and so cleaning out all the way to the toe has been a big thing for us, which the team has done a great job.
I guess for the first part of your question around...
Speaker Change: It's really just data, and so, you know, we needed to see well performance over time. We had hopes that we would be able to move this up from 80% of the third mile to 100% of the third mile, but needed to see the data and see how the wells actually performed.
Darrin Henke: And so now that we've got that data, we're very confident on how we look here and have been really, really pleased with what we're seeing from that third mile. So I'll turn it over to Darrin for incremental comments. Yeah, Scott. It was really...
Darrin Henke: Late summer of 23 in the third quarter that we started getting cleaned out all the way to TD
Darrin Henke: And so when a person looks at those wells that we've brought online really in the last 12 months or so, you see the benefits of that and the production as our engineers forecast the reserves look spot on to be 150% of a two-mile well for our three-mile wells.
So, same recovery on a per foot basis.
Speaker Change: Okay, thanks for that. And my follow-up is, you know, on the, I guess, three-year outlook, you know, a couple questions just to clarify.
Speaker Change: As you look at that, you know, there's two things that stand out to me. Number one, you know, Danny, you kind of mentioned...
Darrin Henke: You know, the $1.4 billion is kind of based on what you know today, can you give us some context of like, you know, is that, you know, contemplating all the full synergies or, you know, what is the benefit of getting the full synergies? Like, where could that go? And number two,
Darrin Henke: As you look at the mix of your properties across the Bakken, how do you think about the mix on a year-to-year basis as it progresses through it? Is it going to be pretty rateable, or is there going to be certain areas that get more focus in certain parts of the plan?
Speaker Change: Yeah, so I think as we look at the overall development plan, we're going to have, we've seen real benefit, I think, in having a little bit of a portfolio effect in how we deliver the plan. And so we've got the rigs and delivery and completion tours a little bit spread out across the field.
Speaker Change: will have and so I think we'll continue that really the underlying plan contemplates that as we move forward and so you know I think in in early time you know we we're we tilt in slightly to the legacy interplus acreage not dramatically but tilt in slightly to the interplus acreage as you would anticipate given that given that position but it's really a pretty spread-out plan over this three-year time frame
Speaker Change: With respect to opportunities to improve the plan, I'd say clearly...
Speaker Change: Service cost will follow activity, which will follow oil price. And so we'll see where overall pricing goes, which is going to set activity levels, and service cost will be penned off of that. And so I can't answer that question. What we've got contemplated in the plan currently is essentially what we're seeing currently in the latter half of 2024, and that's the well cost we have assumed in the plans as we move forward. So as we could see service costs come down, that would float through. If we see service costs move up, that could put upward pressure on us.
Darrin Henke: We've seen over the past year. Again, I don't see that slowing down any time soon, and so I think we're going to have some natural efficiencies that roll through the system. Last thing I'll mention is...
Darrin Henke: And so we're drilling one of those. We've spud one now. We'll see results. I personally have high hopes and expectations around four miles, but that's not contemplated in this plan at all. And so as we see a success with four-mile wells, potentially converting two-mile wells over to four-mile wells, that's just upside that we would see here as well.
Speaker Change: Yeah, just to clarify, the Synergy, is that fully in there, that you know, the Enter Plus, do you think you're pretty much at the full Synergy run rate that's inferred into that?
Speaker Change: So the $200 million plus synergies, of course only a portion of that is capital, but this does have the capital synergies we're anticipating from the Interplus plan baked into the system. What it doesn't have baked in is sort of the continuous improvement and efficiency improvement because at some point, you know, what's a synergy and what's just getting better? And what I know is we're just getting better.
Got it. Thank you.
Thanks, Scott.
Speaker Change: Once again, should you have a question? Please press star followed by number one. Should you wish to decline from the polling process? Please press star followed by number two. Your next question comes from Noah Hannes of Bank of America. Please go ahead.
Noah Hannes: Morning all. I was just hoping you guys could give us maybe some operational color around what you all were able to do with getting coil tubing out to TD on the extended laterals.
Speaker Change: Yeah Noah, good question. You know the, it really comes down to the bottom hole assembly that we use and in the fluid rates that we're pumping and in that really a lot of technical details that probably aren't appropriate for the call but needless to say our team is performing very
Speaker Change: very admirably in this area relative to our peers and someone might argue it's a competitive advantage for court. So I'll leave it at that.
Speaker Change: Makes sense. And then, you guys continue to mention that you're looking to incorporate three-mile laterals on legacy NRPLUS acreage. Is that in the program for 2025, or when should we start to think that those extended laterals on that acreage would be incorporated into the development plan?
Speaker Change: We are believers in three monolaterals, as I mentioned in my prepared remarks, that plan is working. We do have a portion of the Interplus asset, however, that is really...
Speaker Change: And you don't have an opportunity really to stack two 2-miles together. It's sort of a section of 2-miles that need to be developed 2-miles as we move forward.
Speaker Change: We'll see some of that roll through the system. We won't be able to transfer all of their wells over to 3-Miles until you'll see some of that in the 2025 plan, although where we have opportunity to move to 3-Miles, we'll do that as well. So I'd say it's going to be a mix, probably tilting more towards 2-Miles just because of that legacy development program that surrounds it, but you'll see some 3-Miles too.
Thanks.
Thank you.
Speaker Change: Our next question comes from Philip Johnston of Capital One. Please go ahead.
Philip Johnston: Hey, thanks for the time. I appreciate the color on the three-year outlook. Maybe just a follow-up on Scott's question in terms of some of the assumptions there. Just from a modeling standpoint, can you maybe talk about what that assumes in terms of, you know, average gross
Speaker Change: wells per year or gross lateral feet per year, however you guys think about it, as well as kind of average working interest per year. And are you expecting any significant variability in either of those metrics in any given year?
Speaker Change: Thanks for the question Phillips. I'm going to give you directional comments on this because we'll come out with specific guidance as we come out in February so really the intent of the three-year plan was to give directional guidance here so I'll talk directionally about what we're expecting as we move forward.
Speaker Change: We're expecting to see, as we've got the plan laid out currently, we're going to see, you know, I'd say our operated well count decreased slightly as we move forward. That's largely driven by increased lateral length, and so as we're drilling out further, you know, we don't need as many wells to roll through the system in order to deliver the plan, and so you'll see that creep down a little bit.
Speaker Change: and then a slight increase in our non-op. We just really brought a lot of non-op into the system with both the XTO acquisition and with Interplus. These are wells in the core of the field. They are really compelling investment opportunities and so we'll be putting a little bit more into those as we move forward.
Speaker Change: All right, sounds good, and I think you guys make a good point on these longer laterals, you know, having a positive impact here.
hired next to the three-mile spotters.
Speaker Change: as the program is made up with a larger portion of pre-myolaterals which have inherently shallower decline and we've sort of, you know, we've got a little bit of...
Speaker Change: certainly with the legacy Interplus asset that was a growing asset that we're going to more going more from a maintenance standpoint as we move forward so both of those things should be beneficial from a from a decline perspective.
Sounds good. Thanks, Jamie.
Thank you very much.
Speaker Change: Your next question comes from Oliver Wong of TPH. Please go ahead.
Good morning all and thanks for taking the questions.
Speaker Change: As it relates to SimulFrac, just any sort of color in terms of what percent of the program this could kind of migrate towards over the next 12 months.
Speaker Change: The 18 months and are these savings already included in the latest a set of DNC cost figures that you all provided last night?
Yeah, so as we look forward, Oliver, the...
Speaker Change: Next year's plan, we're probably looking at roughly one-and-a-half frack crews, and the one full-time dedicated frack crew, our plan is to do simul-fracks the entire year with that frack crew.
Speaker Change: So, and then the other crew will be more of a zipper frack crew, the half a crew.
Speaker Change: and I will tell you the feet per day that we're getting fracked.
Speaker Change: As we switch to simulfracking, the team is executing very, very well, and it's really eye-opening to see.
Speaker Change: The efficiencies that they've gained really in the last few months as we've expanded the simul-frac activity. So, we could even have more downward pressure on the amount of frac, total frac activity that we'll need relative to crews next year.
Speaker Change: That is in next year's plan. You know, like Danny said, we'll come out with more guidance next year directionally, though it is in the three-year plan.
Speaker Change: Thanks that's helpful and maybe just another second question just on the returns just wanted to kind of get a better understanding around the moving pieces here the shift definitely makes sense given move we've seen in the equity over the last few months but with the increased preference to the buyback is that going to be more viewed as something more programmatic?
Speaker Change: of a quarterly component now or is that something that's going to be more opportunistic in nature within the quarter?
Speaker Change: Thanks for the question Oliver. I'd say we've, you know, share repurchases have always played a part of our of our program and so as we've looked through this we've been, you know, really we've been repurchasing shares in all environments.
Speaker Change: And so I would say, as we look at the landscape now, we think it's a particularly compelling opportunity in the environment we're in, but we've always, we've been doing share repurchases all along the way.
Speaker Change: And so I would say in the near term, certainly we anticipate leaning very, very heavily into share repurchases. But I think share repurchases will always play a role within our overall framework.
Speaker Change: Absolutely, I think the only thing that I would add is that you know we with the Interplus transaction we just had times where we couldn't be buying shares and so it looked like we were leaning into the variable and that you know that actually wasn't the case it was just that we were unable
Speaker Change: to be buying at those times. And I would, you look back to the month of June, once we closed the transaction, you saw us, you know, buy heavily. And that, so that represented, you know, the entire quarter. June represented the entire quarter of buybacks that we did.
Perfect. Thanks for the time.
Thanks, y'all.
Speaker Change: Your next question comes from David Beckelbaum of TD Cowling. Please go ahead.
Speaker Change: Yeah, thanks guys for the time this morning. I just wanted to confirm as you think about the 25 through 27 plan, as you move into more of the NRPlus acreage, I guess as a wading
Speaker Change: and 2627. How do you think of it? Is the spacing going to be identical to the way that you're spacing some of the legacy cord wells and acreage now or is it going to be on tighter spacing just based on the development there?
Speaker Change: So, I think what you'll see, and I'll ask Darrin to comment on this as well.
Speaker Change: It will be similar to what we're doing on chord assets that are adjacent or in the same area as an interplus asset. But of course the spacing is going to change as you move across the field.
Darrin Henke: and so in as you're more in sort of the legacy core we've got slightly tighter spacing in those areas and there's a few even in some cases three forks opportunities that we see in the legacy core as well but it all has to do with the subsurface geology.
Darrin Henke: There's more oil in place in those areas and there's more separation between Three Forks and Bakken, so you just need to space those wells.
Darrin Henke: differently. We do have a preference for generally wider spacing than others than others within the basin because we think we actually get similar results but it's better capital efficiency.
Darrin Henke: So you'll see, I think you'll see similar spacing to what
Speaker Change: sort of ubiquitous spacing across the entire basin, but I'd ask Darrin to weigh in more.
Darrin Henke: Yeah, David, in the spirit of continuous improvement, now that we've combined, you know, our subsurface teams...
Darrin Henke: Legacy Cord and Interplus. We're really embarking on rolling up our sleeves and really looking at completion intensity coupled with well spacing. The two go hand-in-hand and it's an ever-evolving
Darrin Henke: solution that we're looking for. Obviously we're looking for the most capitally efficient solution, the fewest wellbores in the ground that can produce the reserves.
Darrin Henke: Most economically, most viably, that's what we're looking for. We don't think that we have the ideal solution today, and I'm not sure we'll ever get there. It's something that you've got to continuously improve and evaluate, and so we're right in the middle of that currently. But Danny hit the nail on the head.
Speaker Change: You know, a lot of the interplex acreage will have some three forks wells, and will also have some tighter spacing, is what one would expect.
All right, we're good.
Speaker Change: Maybe just to revisit, you know, obviously highlighting the the relatively advantaged base decline achieved this year You know, if you were to distill that down or kind of deconstruct what happened there Would you attribute most of that to the benefit of shallower declines from longer laterals on newer vintage models or has this been
Speaker Change: more optimized workovers and base management that, you know, we would expect obviously to continue in the ensuing years.
Speaker Change: So I think it's a combination of several things. It's one, we haven't been pushing a significant growth program through the system and so that's obviously helpful in moderating declines as we move forward.
Speaker Change: and the operating side of the business with making sure our downtime is low, that we're getting wells returned to production quickly obviously helps as well. And the larger component of three-mile laterals, which have inherently lower decline, is helpful also. I would say that last one we're just starting to see the impact of because if you think about it, you know, we've got...
Speaker Change: You know, thousands of wells in the basin in these three-mile laterals, we've got about a hundred of them. And so, they're newer wells and they're some of our more productive wells, but it still represents a fairly small fraction of the overall production base that we've got. So, it's a combination of things, including the wider spacing we've taken, that we've done over the last few years. So, it's a myriad of things, but the great news is it's all sort of, they're all combining to make that base decline lower, which is just making us a much more capitally efficient producer.
Appreciate the color, guys.
Thanks, David.
Speaker Change: Your next question comes from John Abbott of Wolf Research. Please go ahead.
John Abbott: Hey, thank you very much for taking our questions. So I want to go back to the base decline here.
John Abbott: I want to look at slide number five, where you just basically talk about the percentage of long lateral development, you know, 2022 was 13%, 2024 is 40% long lateral development. Granted, some of those wells in 2024, as you just mentioned, are just coming online. I guess my question, just sort of thinking about the basic line, if I went back to 2022,
Speaker Change: Could you just sort of remind us what your base decline rate was at that period of time versus the 35% that you show currently?
Speaker Change: for 2024, just to get a sense of the impact of longer laterals on your underlying decline rate.
Speaker Change: Yeah, I'd say a little, you know, probably a little higher than this. I can't give you a specific number. And I think, you know, the Interplus assets obviously clearly make this a little bit of an apples and oranges comparison because the decline rates there through the growth in their program is just really different than what the legacy core position had.
Speaker Change: understood and then my other question goes to to the spacing I mean you are more conservative
Speaker Change: on the spacing side there than some of the other folks out there and you've just discussed how the spacing could be different on the Enerplus assets.
Speaker Change: I guess the question here, Danny, have you been too conservative? Is there an opportunity to go back to some of these areas where you've made spacing assumptions, maybe to add additional wells? Is there opportunities in your mind for possible inventory expansion on the spacing side at this point?
Speaker Change: John I think you you bring up a great point and you know one of the things I
Speaker Change: I think in this business, having humility is a really, really important thing. And so we try to stay humble and know that we can always improve and get better. And that has...
Speaker Change: I think that lends itself to Darrin's comments earlier that the teams really have been rolling their sleeves up to go challenge these assumptions and try and figure out what is the most capitally efficient.
Speaker Change: Best way that we can go forward and develop this asset, and it could be that we have gotten slightly too wide.
Speaker Change: A small change in spacing could have a pretty significant impact in inventory and so we're looking into that now. I'll ask Darin to weigh in more, but I think developing, making sure we get this right or as right as we can get it is really, really important to us. Darin, any other comments?
Yeah, I just think, again...
Speaker Change: Spacing is also tied to completion intensity. They go hand-in-hand and a person's really got to look at both of those and look at recoveries on a DSU basis to really get a good handle on it and I never think we're optimized.
Appreciate it. Thank you very much for taking our questions.
Thanks, John.
Speaker Change: Your next question comes from Paul Diamond of Citi. Please go ahead.
Speaker Change: Part of the 50% of longer lateral development in the 25 to 27 plan or would that be incremental for whatever actually comes into fruition based on how the initial wells go?
Yeah, so four miles.
Speaker Change: Four-mile laterals are not part of our 25 to 27 plan at this point, and you hit the nail on the head. About half of our plan over the next three years are not long laterals. And so, as I think we'll be successful with four-mile laterals, I'm very confident in that area.
Speaker Change: where we can take two two-mile wells and make it a single four-mile well and that's absolutely going to improve the capital efficiency and the return of the single well bore being a four miles versus the two shorter laterals.
Speaker Change: Over and above that, where we can't necessarily take two wells and make one four-mile well, we're also looking at U-shaped wells, J-shaped wells.
Speaker Change: Different ways of increasing lateral lengths where we might be constrained to a two-mile DSU. If we can drill U-shape, J-shape, there's a lot of different shapes the industry is really trying right now. To get to three- and four-mile laterals, we also think that will improve our capital efficiency as well.
Speaker Change: So none of that is in the three-year plan at this point.
Speaker Change: So, Paul, I think that what you're pointing out is an exciting part. If we can move that 50% that's not longer lateral to a more capital-efficient longer lateral, there's just a lot of room for additional improvement in the plan going forward. And then the 4-mile lateral just potentially adds on top of that. One, it can help us get the 50% of 2-mile wells into something that's more capital-efficient.
Speaker Change: Or, if it's actually better than three-mile wells, perhaps you actually have another leg at the stool of additional capital efficiency improvements going forward as well. So there's two parts of that four-mile lateral that are exciting.
Speaker Change: Understood, appreciate the clarity. And just one quick bookkeeping item on the current hedge book, been picking up for the last few quarters. Is that more in reaction to your long-term view or a shift in strategy? I guess, how should we think about where the, I guess, where do you all think the right level is?
Speaker Change: No matter what the price environment is, just to make sure that we march forward with a little bit of protection. But we still continue to believe that people own us for the commodity exposure. And so what you really see in our program is a lot of upside and participation in oil price to the extent it moves upward.
Understood. Appreciate the clarity over there.
Thanks.
Speaker Change: Your last question comes from Noel Parks of Two Wee Brothers Investment Research. Please go ahead.
Thank you.
Hi, good morning
Speaker Change: You know, it came up briefly earlier, but I was wondering, how would a gas price rebound scenario sort of ripple through your realizations and your take-away? I don't know if there might be different effects on the east versus west parts of your footprint.
Speaker Change: Yeah, I wouldn't say that it's, you know, a function of our footprint. I really think it's just a function of the fixed price nature of the contracts, as I described in my prepared remarks. So, to the extent, you know, gas prices go up, you'll just see a high, you know, high torque to the upside on our realizations. I think there's some exciting developments in Canada, seeing gas, you know, potentially starting to move west and that LNG Canada facility next year. So, we think there's...
Speaker Change: Some positive tailwinds for gas pricing out of the Bakken as we look forward into next year.
Speaker Change: Drawing more gas volumes from Canada West will be potentially very beneficial to the Bakken Realization going forward and hopefully that stuff comes online middle of next year
Speaker Change: Great, thanks. I hadn't really thought about or heard that talked about a lot so that's really interesting.
Speaker Change: As far as the synergies that you've achieved with Enterplus, I imagine some of them are kind of more upfront, day one type savings. And could you just give a sense of what are the still remaining synergies to capture? Some of them have to do with contracts rolling off and so forth.
Speaker Change: things like the way we run rods in our wells. There's different practices between the two legacy organizations that we think will lead to fewer rod failures in the future. And so that's going to improve our work. That really probably won't start materializing until we get into next year.
and that we tail into our completions with regencode.
Speaker Change: And we think that helps keep sand from flowing back in the well bores, which really wreaks havoc with our ESPs and our run times there. And so fewer ESP failures, we also anticipate seeing in the future because we're taking our upfront capital and completion practices are a little different.
Speaker Change: We're a little different between the legacy organizations. So, you know, some of the capitals, some of the synergies baked into the plan, but still see some upside as we go into 2025 from an operational perspective.
Great. Thanks a lot.
Speaker Change: Thank you ladies and gentlemen. That concludes our question and answer session. I will now turn the conference back over to CEO Danny Brown. Please go ahead.
Danny Brown: Well, thank you, Dion. So, to close out, I want to let the organization know how grateful I am for their continued strong performance and dedication to continuous improvement.
Danny Brown: The Bakken is a world-class resource with strong economics, and as a premier operator in the basin, Chord sees a wide array of opportunities to drive efficiency and accelerate Chord's rate of change as it relates to economic returns and value creation.
Speaker Change: I want to thank all of our employees for their continued hard work and dedication. And with that, I appreciate everyone's interest and thanks for joining our call.
Speaker Change: This concludes today's conference. Thank you for attending. You may now disconnect your lines.