Q4 2022 Chord Energy Corp Earnings Call

Have placed us on strong footing.

Speaker 1: for commitment and dedication have placed us on such strong footing.

Speaker 1: The integration is going well and I remain excited about our future. Through the merger, we've created a better company with a strong financial outlook capable of supporting high levels of sustainable free cash flow at prices much lower than current market benchmarks. And CORD's solid outlook allowed us to enact a progressive shareholder returns framework which resulted in returning over 75% of adjusted free cash flow in the second half of 2022 through a combination of base and variable dividends and opportunistic share repurchases. To examine our program in more detail, you'll see that our annualized base dividends are

Speaker 1: CORE generated approximately $1.3 billion of adjusted free cash flow and returned over $1.2 billion, or approximately 93%, through dividends, cash merger consideration, and share repurchases. Turning to the fourth quarter, last night we announced our operating and financial results, and as noted in the release and our presentation on slide seven, severe winter weather and elevated downtime related to FracProtect negatively impacted volume delivery for the company. When combined, these impacts result in the delivery of approximately 3,200 barrels of oil per day less than the midpoint of guidance for the quarter, with the lion's share attributable to the severe winter weather in late December . The weather also delayed some of our capital activity and shifted completions into 2023, resulting in us investing about $21 million less in the fourth quarter than originally planned. Correspondingly, this reduced capital investment resulted in delivering higher free cash flow than anticipated for the quarter. Most importantly, we continue to be very pleased with the underlying wealth performance...

Speaker 1: as our development program continues to deliver above expectations as can be seen on Slide 10 in our investor debt, which is partially attributed to our practice of wider world spacing, which we believe improves per well recoveries and reduces variability of performance across the asset. From a return of capital perspective, in the fourth quarter, we repurchased $27 million worth of stock at an average price of $133.30 per share. This means that over the course of 2022, we've repurchased about $152 million for an average price of $110.24 per share, and currently have $273 million remaining on our $300 million share repurchase authorization. Given this level of share repurchases and the adjusted free cash flow generating through the quarter, for the fourth quarter of 2022, we have declared a variable dividend of $3.55 per share. When combined with the base dividend of $1.25, this yielded total quarterly dividend of $4.80 per share. Turning to 2023, on a full year basis, we are expecting to deliver slight oil volume growth in line with consensus estimates. At a program level, court plans to complete and deliver 90-94 gross operated wells in 2023 with an average working interest of approximately 73%.

Speaker 1: Completion's activity is concentrated in the second and third quarter of 2023, with over two thirds of our turn lines or tills expected during these quarters. The first quarter is expected to have only 13 back in weighted tills, and volumes are affected by this completion timing as well as the lingering weather downtime we saw in January . But production is expected to increase sequentially each quarter with fourth quarter of 2023 volumes being the highest of the year. I mentioned downtime due to frack protect a little earlier on the call and wanted to spend a moment discussing its impact on 2022 and our expectations for 2023, which is detailed on slide seven of our investor deck. As we previously discussed, delayed completions activity, whether due to inclinations, weather conditions, or mechanical issues, impacts the volume delivery of not just those wells that are delayed, but also those surrounding wells that are shut in from a precautionary standpoint until nearby completions activities has concluded. In 2020, 2022, mechanical issues and weather delays while developing and densely developed areas like Indian Hills, FBIR, and Sandwich led to very high and extended frack protect downtime. For the 2023 program, completions are concentrated in relatively less congested areas, which makes frack protect less of an issue year over year. Additionally, we expect downtime related to artificial lip to improve over the year and end of 2024 as we are implementing best practices from the merger. As we look at the capital investment landscape for 2023, recently, a video has neither entered any places now, and included to final our research software of the STEP, ST?? stage, so I would now invite you to subscribe for more details on the individual with new ideas and nod your follow up.

Speaker 1: There is obviously uncertainty related to service prices, which are dependent on various supply and demand variables that I won't discuss in depth on this call. While there are some signs that pricing has plateaued in certain areas, I would note equipment utilization remains high and pricing remains elevated. Taking our best view, which does incorporate significant year-on-year inflation that we've experienced, we expect to invest approximately $825 million to $865 million of capital in 2023, which is in line with consensus once accounting for the roughly $20 million of capital pushed from the fourth quarter of last year, which I discussed previously. Importantly, CORD's program focuses on operational efficiency and consistency, which we believe not only supports cost-effective operations but also supports safer operations. This operational efficiency is also supported by synergies derived from the merger and our development strategy. Three-mile laterals are a big part of the 2023 story, as we're expecting three-milers to comprise approximately 50% of Tills in 2023. We brought online our first three-mile laterals in the second half of last year in Indian Hills, and they are performing nicely.

Speaker 1: Flying Dine illustrates what we are seeing with three-mile performance and culminates in an economic uplift of about 25 points when going from two miles to three miles. In total, COARDS 2023 program is expected to result in a reinvestment rate at around 50 percent at $75 WTI. Finally, I want to spend a moment on ESG and sustainability before passing it over to my board. Following the closing of the merger, we posted a letter to our shareholders, along with the pro-former ESG metrics for the combined company. We provided this information in the interest of transparency. And to remind the market we are dedicated to providing robust disclosure and improving our performance in these areas. And in 2023, we plan to resume publishing a full sustainability report.

Speaker 1: COARD continues to have strong performance in GHG intensity, and we see opportunities for further improvement. Additionally, COARD has improved freshwater intensity and remains focused on the safety of our employees and contractors and maintaining strong corporate governance. In short, over time, you will continue to see our disclosure grow with a continued focus on improving performance across the board. I'll now turn it over to Michael for some additional updates. Thanks, Danny. I'll highlight a handful of key operating items for the fourth quarter and also discuss a few of our 2023 guidance items. Crude realizations remain at a premium to WTI, and our pricing averaged a 99 cent premium to the benchmark over the quarter. While this was slightly below fourth quarter midpoint guidance, pricing has been strong, and we continue to expect that in 2023.

Speaker 1: NGL and residual gas pricing deteriorated sequentially, reflecting falling benchmark pricing. NGL prices fell more than WTI sequentially, which resulted in lower NGL realizations as a percent of crude. Residual gas pricing was weaker than expected, primarily reflecting increased regional gas competition resulting from a warm start to the winter. LOE averaged $9.87 per BOE for the fourth quarter toward the high end of our guidance as the volume disruptions increased per unit cost. For full year 2023, we baked in some of the inflation that we saw on the production side in 2022 into our guidance. Production taxes were approximately 8% of oil and gas revenue in line with guidance. In 2023, we expect this to go down modestly, reflecting lower trailing WTI pricing, which recently lowered the North Dakota oil tax rate back to early 2022 levels.

Speaker 1: The CORD cash G&A expense was $22.4 million in the fourth quarter, which was a little higher than expected due to conforming the two companies' accounting policies. The number excludes about $12 million of cash costs associated with the merger. CORD excludes these charges in calculating adjusted free cash flow for the return of capital program as they are viewed as one-time costs associated with integrating the merger. At this juncture, we believe the majority of merger-related expenses have been taken in the second half of 2022, although we expect about $9 million of merger-related expenses to hit 2023 for things like relocation and severance.

Speaker 1: Our 2023 cash GNA guidance of $68 million reflects recurring operations only. Core paid about approximately $10 million in cash taxes in the fourth quarter associated with the September modernization of $16 million Crestwood units. These cash taxes were excluded from our adjusted free cash flow calculation given they are not associated with continuing operations. In 2023 we estimate no cash taxes in the first quarter and for subsequent quarters we are expecting about 2 to 8% of EBITDA at oil prices of $70 to $90.

Speaker 1: Turning to liquidity, CORT has nothing drawn on its $2.75 billion borrowing base, which has elected commitments of a billion dollars. Cash was approximately $593 million as of December 31st as well. In closing, CORT is generating strong returns, which supports our sustainable free cash flow profile and feeds our robust return of capital program. We demonstrated this with approximately $1.3 billion of free cash flow in 2022 and over $1.2 billion returned to shareholders.

Speaker 1: Our operations team continues to improve the asset base demonstrably through spacing and longer laterals which drives a longer, more predictable and more economic inventory life. To close, we are incredibly proud to be a safe and responsible low cost provider of energy which fuels a better world and we are also proud of the entire core team who has come together and chooses to do what is right for each other, the company and our communities. With that, I'll hand the call over to Nick to open the line for questions.

Speaker 1: Thank you. Well, now begin the question and answer session. Ask a question and you may press star than one on your touchtone phone. Do this speaker phone please pick up your answer before pressing the keys? So, it's all your question, please press star than two. This time we'll pause on the paralegal symbol of rust. First question, we from there with the oldest people. Please go ahead. Thanks, and good morning, all. Perhaps for Danny or for Chip, is you evaluate your inventory and three mile lateral results to date? How are you thinking about the implementation of through mile laterals over the next several years?

Speaker 1: with the understanding that you're meaningfully stepping up activity in 2023, could we see even a higher percentage of three-mile lateral activity in 2024? Thanks for the question, Derek. I'll start off and then ask Chip to jump in with some additional color commentary. I think when you look at the total amount of inventory we have as an organization that we associate with three-mile laterals, it's roughly 50 to 60% of our inventory that's left. And so we'll do maybe on the low end of that in 2023, at about 50%. And so you might see it increase a little bit just because it comprises a slightly higher percentage of our total inventory that's left as we move forward. But I think it really will be a little bit dependent upon our development plans for the year, the specific areas they're at, the lease geometry that we're developing in, you know, and the infrastructure that is available to us at the time. So I think that 2023 plan is at 50% is probably about what we'll be doing as we move forward, maybe slightly.

Speaker 2: Thank you. Thank you.

Speaker 3: Yeah, second great question. So yeah, we're definitely looking to that. We've already challenged ourselves a little bit in the sanitary doing some of those things. I think with some of the new technologies with the coil drill outs, the hydro lift system, the mud systems are really allowing us to potentially look and gain some value on the refrax in the sanitary area, but also other areas that have were probably completed, you know, back in the 10 years ago, not with the completions that we have today. So I think there's huge value. We'll compare those compared to our entire inventory, but I'm excited where that potentially could go for the basin.

Speaker 3: Yeah, a second great question. So yeah, we're definitely looking into that. We've already challenged ourselves a little bit in the Sani East Area doing some of those things. I think with some of the new technologies with the coil drill-outs, the hydro lift systems, the mud systems are really allowing us to potentially look and gain some value on the refracts in the Sani East Area, but also other areas that were probably completed back in the 10 years ago, not with the completions that we have today. So I think there's huge value. We'll compare those compared to our entire inventory. But I'm excited where that potentially could go for the basin. Very helpful. Thanks for your time.

Speaker 3: Thank you, Derek. Thank you. Next question will be from the gentleman, Truo Securities. Please go ahead. Morning, all. My first question is on the BOCOM takeaways. Physically, you know, talking to you guys, it seems that the diffs now have been quite good now for some time. I'm just wondering, is this more result of just the takeaway contracts or really just curious if there's been any change to your marketing group? You all have done an excellent job there. Yeah, thanks, Neil. Yeah, I think on the marketing side, differentials have been strong in the base and we think they will continue to. We've got a large takeaway capacity and we're not filling that as a basin. So really, there's a lot of competition. That crude market is pretty robust on the back end side and I think BOCOM crude is really bid up because it is a great barrel for the refineries. So with all that combined, strong takeaway, way more capacity than what we're supplying right now, that all leads to kind of a really nice setup on the crude side. So I think we will see continued crude realizations that are strong for a while. Great to hear. And then just second one on the operating plan. Thanks, Paul.

Speaker 3: I think the opportunistic approach is the right one, but I'm just wondering how you're thinking about the mix going forward and what it might take to sort of get more aggressive on the buyback.

Speaker 1: Thanks for the question, Phillip. So, you know, I'd say just broadly speaking, you know, we tried to learn some from the lessons of the past and one of those clearly is to avoid pro-cyclical buybacks. And so that certainly goes into our thinking. We've got a pretty disciplined view on how we think about share repurchases. As you noted, I think importantly we view them opportunistically, not really programmatically. And I'd say we would define that opportunity as a combination of when our shares are trading under what we think our intrinsic value is at conservative pricing and when we're trading at a discount to our peers. We're looking at dislocations on both of those items, not just a single item.

Speaker 3: And so when we see that, you know, depending upon the magnitude of those dislocations, I think you'll see us be pretty aggressive. Certainly there was an example of that last summer. But really it's not just the discount to our intrinsic value, but also how we're trading relative to our peers. Okay, makes sense. And then maybe a question for Michael. You referenced the wide gas differentials embedded in the 23 guidance. I think you said that's a result of gas on gas competition in the basin. But I was wondering if you could maybe give us a little bit more insight as to what the drivers are there and what's different about this year versus the past few years. I recognize there's a fixed cost component that's coming into play relative to lower NYMEX prices, but the 40 to 50% of NYMEX realization seems pretty low considering that production in the basin hasn't really been growing. Yeah, it's a great question, Phillips. And I think you hit on both of them. One, there is some kind of regional competition with Canadian Gas for the Bakken that we experienced there in the fourth quarter. And then on top of that, it does have to do with that fixed component, that fixed cost component that you're talking about. And so if you think about it, in higher gas price environments, you're going to have a larger piece of that going to...

Speaker 3: that they're for actual to have in lower gas price environment it's going to be a little bit lower realization because that six components. So there's going to be some of it has to do with kind of where we are on the gas on the actual gas price. It's lower today and the strip has it at a lower level. So that means that the realizations are going to be lower as well. And then the historical periods aren't comparable just given the fact that we just switched from two stream to three streams. So there's just a little bit of nuance from what you've seen from the companies in the past where we are today. Sure. Yeah. Okay. Thanks. Thanks. Thanks, Ellen. Thank you. Next question, please join in. Thank you for America. Please go ahead. Hey, good morning. Thank you for taking our questions. The first question is on your outlook. So looking to 2023, you know, you're going to look like production is going to grow steadily up to the fourth quarter of looking at slide 11. With the move to more three mile ladders, how are you looking at oil in 2024 potentially? And how does the move towards more three mile ladders potentially impact your underlying decline rate?

Speaker 1: Great question, John . So as we think about the impact of the three monolaterals and oil delivery in the basin, I'd say it's not just about the length of the wells, but also about where we're drilling within the basin. And so an important sort of overlying factor is the fact that we're moving into oilier areas of the basin generally, and so we're anticipating that our oil cut as a percentage of our new wedge production is probably going to be a little higher than it has been historically. So you've got the broad basin and our historic legacy development where our GORs are increasing slightly, and then that's being offset with a wedge program that's delivering slightly more oil than we would have delivered historically. And so that's going on in the backdrop and going to affect the entire field level production. At a three-mile lateral level.

Speaker 1: What we would typically anticipate from a three-mile lateral relative to a two-mile lateral from a production delivery standpoint would be sort of similar production over early time. We don't really upsize the facilities. We don't pull those wells a whole lot harder than we do two-mile laterals, but what we see is that they run flat for a longer period of time before they start to decline, and then those decline rates are a little shallower because you have a longer lateral feeding into the well bore. And so, just the overall decline profile does change as you move from two miles to three miles, but there's other impacts of the field development that will also impact what we deliver as far as a commodity mix. And I'll ask Chip to weigh in with any additional color. No, I mean, you're exactly right, Danny. I appreciate the question, but it's... Whether it's a two-mile or a three-mile, we don't overbuild our facilities, and so then we flow them back. We want to make sure we have sand maintenance and those kind of things that we flow back, choke them back in the right level, and they tend to stay flatter for longer, so that's what we see, so you'll see that.

Speaker 1: that three milers stay out there for a lot longer than you would on two miler. Appreciate it. And then for our second question, what are you seeing in terms of potential bolt-off? How would you describe the potential bolt-on opportunity market at this point in time in the Bakken? So from bolt-on opportunities, we continue to see a mix of different opportunities in the basin, whether it be small asset packages, potentially larger asset packages, private organizations, etc. So it's really a mix. So there is an opportunity set, and as you'd expect with our footprint within the basin, that is something we follow pretty closely. And if we see opportunities to do a period of bolt-ons that make this a better organization, that's certainly something we're going to look at.

Speaker 3: Appreciate it. Thank you for taking our questions. Thanks, John . Thank you. Again, if you have a question, please pass it on to one. Next question will be from Paul Bonn and the city. Please go ahead. Good morning, all thanks for taking my call. Just a quick shift of conversation, which would be a bit more of the longer term development plan. Slide 6, you referenced some kind of areas that are more in the longer term upside for optionality and development. Just want to get your ideas of how you guys think about those as far as priorities and you know, in current and in the current volatile pricing environment and kind of how we should look about those going forward.

Speaker 3: I think as we think about those areas that are largely on the slide highlighted in blue, we really do see those as long term upside for us. They don't play a role in our current development plan. We are typically looking at investing in our, one, opportunities that are near infrastructure, then two, opportunities that deliver the highest returns to us. And so we view those as upside. We're going to monitor development in those areas that we see others doing. It will help inform our views moving forward. But we really do look at that as long term upside and that's not part of our near term development plan. I should also say Danny, gas capture is important to us. And so we stay in the core areas we have, we take away in those kind of things on the gas capture side. They may be a little more limited on those other areas. Understood. Thank you. Just for a quick follow up, on slide 7, you guys detail your kind of cadence of your tilt timing coming into 2023. I was curious if there was a...

Speaker 1: Kind of the rationale for the year over year difference in Q422 versus Q423, is that just operational planning? Or is that trying to avoid another weather incident or kind of just the thought process behind that? So I'd say if you think about the 2022 plan, the 2022 plan was really a continuation of the legacy plans between both legacy organizations. And so when the merger, you know, both legacy organizations had a bit of a back end weighted program. And so when you combine the two companies, those plans, which is where we had permits, we had rig contracts, we had completion crew contracts, that really just sort of perpetuated through the balance of the year, leading to the sort of the timing that you see noted. As we were able to take a view, an integrated view as an organization about how we really wanted to develop the asset moving forward,ework from the mandate goes on and committee spend no more than a quarter of it from scratch. So that's what our problem is today. Then we have setbacks, resilience associated with the

I think this timing of doing completions more toward the middle of the year, concentrated in the middle of the year, just makes a little more sense from an operational perspective. As Chip noted, the weather is better during that time frame. We're able to get a solid frack crew during that time frame, which we know delivers efficiencies. And so you'll see that program is a little bit different than it has been than it was last year, but it's really just a product of us being able to sit down as a combined larger organization and put together a schedule that makes sense for us, relative to schedules that made sense for the two legacy companies independently.

Understood. Thanks, your time. Thanks, Paul. Thank you. This concludes our question and answer session. I'll like to turn the conference back over to Mr. Dany Brown, T.C. Exept, and Officer Hoover closing remarks. Thank you, Nick. To close out, we remain committed to our core strategy retaining financial flexibility, exploring opportunities, continue to consolidate and having a robust return of capital programs.

We are doing this with a focus on sustainability and drive our further improvement across every aspect of our business. We are now over six months into the integration and remain as excited as ever about the opportunities in front of us for our shareholders, employees, communities and other stakeholders. Thank you again for your, thank you again to our people for driving this progress and making it happen. Your efforts are sincerely appreciated and with that I'll conclude by also saying thank you to those joining our call. Thank you for the day's presentation. You may now disconnect.