Good day, and welcome to the Chord Energy Fourth Quarter 2022 Earnings Conference Call. All participants will be in a listen-only mode. [Operator Instructions] 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.

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.

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.…

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…

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

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?

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.

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.

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?

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.

Very helpful. Thanks for your time.

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

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.

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.

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?

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.

Thanks for the detail’s guys.

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

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.

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.

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.

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.

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.

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

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?

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.

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.

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?

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.

Appreciate it. Thank you for taking our questions.

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

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?

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.

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.

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?

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.

Understood. Thanks for your time.

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.

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.

Conference is now concluded. Thank you for attending today's presentation. You may now disconnect.