Chord Energy Corporation (NASDAQ:CHRD) Q4 2022 Earnings Call Transcript

Chord Energy Corporation (NASDAQ:CHRD) Q4 2022 Earnings Call Transcript February 23, 2023

Operator: Good day, and welcome to the Chord Energy Fourth Quarter 2022 Earnings Conference Call. All participants will be in a listen-only mode. After today’s presentation, there will be an opportunity to ask questions. Please note, today’s event is being recorded. I’d like to turn the floor over to Michael Lou, Chief Financial Officer. Please go ahead.

Michael Lou: Thank you, Nick. Good morning, everyone. Today, we are reporting our fourth quarter 2022 financial and operational results. We are delighted to have you on our call. I’m joined today by Danny Brown; Chip Rimer and other members of our 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 references to non-GAAP measures and the reconciliations to the applicable GAAP measures can be found in our earnings releases and on our website. We may also reference our current investor presentation, which you can find on our website. With that, I’ll turn the call over to our CEO, Danny Brown.

Danny Brown: Good morning, everyone, and thanks for joining our call. I’d like to start of this morning, reflecting on an eventful of 2022, prior to talking about our fourth quarter results and ultimately our expectations for 2023. 2022 was a transformational year for our organization as we completed a merger of equals transaction to create Chord Energy, a company with substantial scale in the Williston Basin and one with an opportunity to create and extract significant value through operational and corporate synergies. Importantly, we executed this transaction while maintaining our commitment to balance sheet strength, capital discipline and to our shareholders, as we also announced a compelling and peer-leading return of capital framework.

In the months leading up to the merger and through the balance of last year, we laid the groundwork and began the process of integration and establishing how we would operate as a new organization. This integration process is now fully underway and for 2023, we are focused on delivering value from the best practices and synergies we have identified. As a reminder, through this process, Chord previously announced that we have increased our target annual synergies from the $65 million we originally targeted at the announcement to our current expectation of over $100 million per year. We expect to realize over 70% of these targeted synergies by the second half of 2023 with the remainder in 2024 and have incorporated these numbers into our guidance.

Taking the time and effort to establish what we believe are the best practices for the go forward organization, regardless of legacy practice, will make us a stronger company I want to thank the employees of Chord who through their commitment and dedication have placed us on such strong footing. The integration is going well and I remain excited about our future. Through the merger, we have 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 Chord’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 repurchase.

If you examine our program in more detail, you’ll see that our annualized base dividend of $5 per share had a yield of 3.8% and represents a 233% Cumulative increase over the past two years. A strong base dividend is a core part of a return of capital strategy and is designed to be resilient at low prices and sustainable through commodity cycles. And importantly, we believe our base dividend is very attractive versus both our peer group and the broader market. More broadly, our focus on strong shareholder returns was evident in 2022. On a pro forma basis, for the full year, Chord 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 7, severe winter weather and elevated downtime related to frac protect, negatively impacted volume delivery for the company. When combined, these impacts resulted in the delivery of approximately 3,200 barrels of oil per day less than the midpoint of guidance for the quarter. With a lion of share attributable to the severe winter weather in late December. The weather also delayed some of our capital activity and shifted completions into 2023, resulted 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 well performance, as our development program continues to deliver above expectations as can be seen on Slide 10 in our investor deck, which is partially attributed to our practice of wider well 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 repurchased about $152 million for an average price of about $110.24 per share. And currently have $273 million remaining on our $300 million share repurchase authorization. Given this level share repurchases and the adjusted free cash flow generating during 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 per share, this yields a total quarterly dividend of $4.8 per share. Turning to 2023. On a full year basis, we are expecting to deliver slight oil volume growth inline with consensus estimates. At a program level, Chord plans to complete and deliver 90 to 94 gross operated wells in 2023 with an average working interest of approximately 73%. Completions activity is concentrated in the second and third quarter of 2023 with over two-thirds of our turn in lines or tills expected during these quarters. The first quarter is expected to have only 13 back-end 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 for the year.

I mentioned downtime due to frac protect a little earlier on the call, and wanted to spend a moment discuss its impact on 2022 and our expectations for 2023, which is detailed on Slide 7 of our investor deck. As we previously discussed, delayed completions activity, whether due to inclement 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 2022, mechanical issues and weather delays, while developing and densely developed areas like Indian Hills, FBIR and Sanish, led to very high and extended frac protect downtime. For the 2023 program, completions are concentrated in relatively less congested areas, which makes frac protect less of an issue year-over-year.

Additionally, we expect downtime related to artificial lift to improve over the year into 2024, as we are implementing best practices from the merger. As we look at the capital investment landscape for 2023, 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 have experienced, we expect to invest approximately $825 million to $865 million of capital in 2023, which is inline with consensus once accounting for the roughly $20 million of capital pushed from the fourth quarter of last year, which I discussed previously.

Importantly, Chord’s program focuses on operational efficiency and consistency, which we believe not only supports cost effective operations, but also support safer operations. This operational efficiency is also supported by synergies derived from the merger and our development strategy. 3-mile laterals are a big part of the 2023 story as we are expecting 3-mile laterals to comprise approximately 50% of tills in 2023. We brought online our first 3-mile laterals in the second half of last year in Indian Hills and they are performing nicely. Slide 9 illustrates what we are seeing with 3-mile performance and culminates in an economic uplift of about 25 points when going from 2-miles to 3-miles. In total, Chord’s 2023 program is expected to result in a reinvestment rate of around 50% at $75 WTI.

Finally, I want to spend a moment on ESG and sustainability before passing it over to Michael. Following the closing of the merger, we posted a letter to our shareholders along with pro forma ESG metrics for the combined company. We’ve 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. Chord continues to have strong performance in GHG intensity and we see opportunities for further improvement. Additionally, Chord 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’ll continue to see our disclosure grow with a continued focus on improving performance across the board. I’ll now turn it over to Michael from for some additional updates.

Michael Lou: 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 $0.99 premium to the benchmark over the quarter. While this was slightly below fourth quarter midpoint guidance, pricing has been strong and we continued to expect that in 2023. NGL and residue 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. Residue 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 costs. 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. Chord 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. Chord excludes these charges in calculating adjusted free cash flow for the return of capital program as they are viewed as one-time cost 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. Our 2023 cash G&A guidance of $68 million reflects recurring operations only. Chord paid about approximately $10 million in cash taxes in the fourth quarter associated with the September monetization 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’re expecting about two to 8% of EBITDA at oil prices of $70 to $90.

Turning to liquidity, Chord 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, Chord is generating stronger 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. 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 Chord team who has come together and chooses to do the right — 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.

Q&A Session

Operator: Thank you. . First question will be from Derrick Whitfield and Stifel. Please go ahead.

Derrick Whitfield: Thanks, and good morning all. Perhaps for Danny or Chip. As you evaluate your inventory in 3-mile lateral results to date, how are you thinking about the implementation of 3-mile laterals over the next several years? With the — understanding that you’re meaningfully stepping up activity in 2023, could we see even a higher percentage of 3-mile lateral activity in 2024?

Danny Brown: Thanks for the question, Derrick. I’ll start off and then ask Chip to jump in with some additional color or commentary. I think when you look at the total amount of we have as an organization that we associate with 3-mile laterals, it’s roughly 50% to 60% of our inventory that’s left. And so, we will do maybe on the low end of that 2023 at about 50%. And so, you might see it increase a little bit, just because it comprises a little — 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 are at, the lease geometry that we are developing in and the infrastructure that is available to us at the time. So, I think that, 2023 plan at 50% is probably about what we will be doing as we move forward, maybe slightly higher in some quarters versus another. But I’ll ask Chip to maybe provide some more commentary.

Chip Rimer: Hey. Appreciate the question. And Danny, you’re right. If you look at what we are drilling versus what we are telling this year will be slightly higher than that. So, a little bit above that number, and we will be going across all parts of the basin there. So really looking forward to taking that capital efficiency that we are seeing right now and use that across the entire basin to really add value for the company.

Derrick Whitfield: Terrific. And for my follow-up, staying broadly on inventory. The focus of your communication has generally been on new wells, and thinking about the productivity some of your peers are experiencing with refracs. What are your thoughts on how investments in refracs in Sanish, let’s say, an area where the play was clearly developed in early, early times? How would that compare versus new development in other areas, particularly if you were to couple new development with recompletes, which would also give you the benefit of frac protect?

Danny Brown: Yes. Second great question. So yes, we are 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 Chord drill outs, the hydro lift systems, the mud systems are really allowing us to potentially look and gain some value on the refrac in the Sanish area, but also other areas that were probably completed back in 10 years ago, not with the completions that we had today. So, I think there is huge value. We will compare those compared to our entire inventory. But I’m excited where that potentially could go for the basin.

Derrick Whitfield: Very helpful. Thanks for your time.

Operator: Next question comes Neal Dingmann Truist Securities. Please go ahead.

Neal Dingmann: Good morning. My first question is on the Bakken takeaway. Specifically, particularly, it seems that the dips now have been quite good now for some time. I’m just wondering is this more result of just the takeaway contracts really just curious if there is been any change to your marketing group? You all done an excellent job there.

Danny Brown: Yes. Thanks, Neil. Yes, I think on the marketing side differentials have been strong in the basin. We think they will continue to. We have got a large takeaway capacity. And we are not filling that as a basin. So really there is a lot of competition that crude market is pretty robust on the back-hand side. And I think Bakken crude has really bid up, because it is a great barrel for the refineries. So, with all of that combined, strong takeaway, not way more supply or way more capacity than what we are 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.

Neal Dingmann: Great to hear. And then just second on the operating plan. Can you give us some color just on the regional operating plans? I’m just wondering how concentrated the drilling might be or what you consider sort of the optimal pad size?

Chip Rimer: Yes. Optimum pad size for us is typically a couple of wells to four wells of pad. We are going to be spread out to the entire basin. I think we have been concentrated in certain areas. It causes some frac protect things that Danny was talking about that I think we can spread this year. We are looking to fill our wells in the second and third quarter, which is a good time of the year with weather situations. And so, we are going to be across the entire basin spreading our work, that’s a nice thing about bringing two companies together and synergies to Chord to have that ability to do those things.

Neal Dingmann: Thanks for the detail’s guys.

Operator: Thank you. Next question will be from Phillips Johnston, Capital One. Please go ahead.

Phillips Johnston: Hey, guys. Thanks. The return of capital remains high and impressive. My question is on the mix. The fourth quarter return included $27 million of buybacks out of the $227 million total. So relatively light mix, despite what many would probably agree that as a cheap stock. Think the opportunistic approach is the right one, but I’m just wondering how you are thinking about the mix going forward and what it might take to sort of get more aggressive on the buyback.

Danny Brown: Thanks for the question, Phillips. So, I’d say just broadly speaking, we tried to learn some from the lessons of the past and one of those clearly is to avoid procyclical buybacks. And so that certainly goes into our thinking. We have 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 are trading at a discount to our peers. And so, we are really looking at dislocations on both of those items, not just a single item. And so, when we see that, 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 our — the discount to our intrinsic value, but also how we’re trading relative to our, to peers.

Phillips Johnston: Okay. Makes sense. And then maybe 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.

Michael Lou : Yes. 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 Bach end 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, as you think about it in higher gas price environments, you’re going to have a larger piece of that kind of going to that differential to hub in lower gas price environments. It’s going to be a little bit lower realization, because of that fixed component. 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.

Danny Brown : 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 a nuance from what you’ve seen from the companies in the past to where we are today.

Operator: Thank you. Next question will be from John Abbott, Bank of America. Please go ahead.

John Abbott : Good morning and thanks for taking my question. First question is on your outlook. So, looking to 2023, you’re going to — it looks like production is going to grow steadily up to the fourth quarter of looking at slide 11. With the move to more 3-mile laterals. How are you looking at oil in 2024, potentially, and how does the move towards more 3-miles laterals potentially impact your underlying decline rate?

Danny Brown : Great question, John. So, as we think about — as we think about the impact of the 3-miles laterals in 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 is a percentage of our new wedge production is probably going to be a little higher than it has been historically. And 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’ve delivered historically.

And so that’s going on in the backdrop, and is going to affect the entire field level production. At a 3-mile lateral level, what we would typically anticipate from a 3-mile lateral relative to a 2-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 2-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 wellbore. And so just the overall decline profile does change as you move from 2-miles to 3-miles, but there is other impacts of the field development that will also impact, what we deliver as far as a commodity mix.

And I’ll let Chip to weigh in with any additional color.

Chip Rimer: No, I mean, you are exactly right, Danny. And I appreciate the question. But it’s — whether it’s a 2-mile or 3-mile or we don’t overbuild our facilities, and so then we flow them back. We want to make sure we have sand maintenance and those kinds 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 will see that, that 3-miles stay up there for a lot longer than you would on 2-miles.

John Abbott : Appreciate it. And then for our second question, what are you seeing in terms of potential bolt-on? How would you describe potential bolt-on opportunity market at this point in time in the Bakken?

Danny Brown: 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, et cetera. So, it’s really a mix. And so, there is an opportunity set and as you expect with our footprint within the basin that is something we follow pretty closely. And if we see opportunities to do accretive bolt-ons that make us a better organization, that’s certainly something we are going to look at.

John Abbott : Appreciate it. Thank you for taking our questions.

Operator: Thank you. . Next question will be from Paul Diamond in the Citi. Please go ahead.

Paul Diamond: Good morning, all. Thanks for taking my call. Just a quick shift of conversation here to 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 current volatile pricing environment, and kind of how we should look about those going forward?

Danny Brown: I think as we think about those areas that are largely with on the slide highlighted in blue, we really do see those as long-term upsides 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 are 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.

Chip Rimer: I’d also say, Danny, gas capture is important to us. And so, we stay in the core areas. We have take away and those kind of things in the gas capture side. May be a little more limited on those other areas.

Paul Diamond: Understood. Thank you. Just for a quick follow-up. On Slide 7, you guys detail your kind of cadence of your till time as coming into 2023. I was curious if there was kind of the rationale for the year-over-year difference in Q4 ’22 versus Q4 ’23? Is that just operational playing? Or is there trying to avoid another weather incident or kind of just the thought process behind that?

Danny Brown: 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 — 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 through 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 and integrated view as an organization about how we really wanted to develop the asset moving forward, I think this timing of doing completions more toward the middle of the year concentrated in the middle of the year.

It just makes a little more sense from an operational perspective. As Chip noted, the weather is better during that timeframe. We are able to get a solid frac through during that timeframe, which we know delivers efficiencies. And so, you will 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.

Paul Diamond: Understood. Thanks for your time.

Operator: Thank you. This concludes our question-and-answer session. I’d like to turn the conference back over to Danny Brown, Chief Executive Officer for closing remarks.

Danny Brown: Thank you, Nick. To close out, we remain committed to our core strategy, which revolves around being strong capital allocators, retaining financial flexibility, exploring opportunities to continue to consolidate and having a robust return of capital program. We are doing this with a focus on sustainability and drive for 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 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.

Operator: Conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.