Good morning, and welcome to the Chord Energy’s Second Quarter 2023 Earnings Results Conference Call. Please note, this event is being recorded. I would now like to turn the conference over to Michael Lou, Chief Financial Officer. Please go ahead.

Thank you, Megan. Good morning, everyone. Today, we are reporting our second quarter 2023 financial and operational results. We're delighted to have you on our call. I'm joined today by Danny Brown, Chip Rimer, and other members of the team. Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings releases and conference calls. Those risks include, among others, matters that we have described in our earnings releases, as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During this conference call, we will make reference to non-GAAP measures, and reconciliations to the applicable GAAP measures can be found in our earnings releases and on our website. We may also reference our current investor presentation, which you can find on our website. With that, I'll turn the call over to our CEO, Danny Brown.

Thank you, Michael. And thank you to everyone who's joining our call on what I know is a very busy morning. So with that, in addition to discussing our quarterly results and expectations for the balance of the year, I'd also like to briefly recognize what Chord has done over the past 12 months to integrate two premiere Williston Basin operators and form a new, stronger, and more resilient organization. While integration is never easy, I am very proud of what the team has accomplished, including fulfilling our commitment to capitalize on the best practices of the two legacy organizations and using that to capture and expand significant financial and operating synergies. We've also been very focused on our shareholders. One year ago, we rolled out what we believe to be a peer-leading return of capital program that showed our commitment to both the balance sheet and to delivering returns to our investors. For the 12 months from July 1, 2022, to June 30, 2023, we’ve returned $1.1 billion in the form of dividends and another $198 million via share buybacks, including aggressively repurchasing steeply discounted shares shortly after the transaction closed. We've also strengthened the portfolio, including closing the XTO bolt-on acquisition on the one-year anniversary of close and selling non-core assets, streamlining our operations and directing focus to where we have scale and competitive advantages. I'm also very pleased to announce that we've added a key member to our executive team, Shannon Kinney. Shannon joins us as our Executive Vice President and General Counsel and brings over 20 years of legal experience with her most recently from ConocoPhillips, where she was Vice President, Deputy General Counsel, and Corporate Secretary. We are absolutely thrilled to have Shannon as part of the team and look forward to working with her and benefiting from her expertise as we move forward. Now, turning our attention to the quarter, the organization once again delivered strong operational performance, resulting in oil and total volumes above expectations. This volume delivery was underpinned by very solid performance from new wells, the underlying asset base, and acceleration of turned-in-lines or TILs early in the quarter, while NGL and gas realizations were softer sequentially. Michael will provide more detail on this topic shortly. Capital and other items were generally right in line with expectations and guidance. Taking all of this into account, we generated $116 million of adjusted free cash flow during the quarter, which, as presented in our deck, does include the removal of around $11 million of capital booked from non-operated wellbores that had been sold and which will be reimbursed to us. Given this free cash flow generation and in keeping with our return on capital framework, we declared a variable dividend of $0.11 per share with a base dividend that remains unchanged at $1.25 per share. As a reminder, the aggregate variable payment of approximately $5 million is the difference between 75% of the $116 million of adjusted free cash flow generated in the second quarter minus the base dividend of approximately $52 million minus $31 million of second-quarter share repurchases. In other words, the variable dividend is designed to make up any difference between our target and free cash flow payout, and the amount distributed through base dividends and share repurchases. As I've said before, we believe our capital return program is peer-leading and demonstrates our commitment to both capital discipline and shareholder returns. As we noted last quarter, we aimed to increase share repurchases as our percentage of return capital in recognition of the discount that we believe our stock trades at relative to peers and our intrinsic value. Accordingly, in the second quarter, share repurchases accounted for almost 90% of capital returned after our base dividend. Looking forward, we will continue to be opportunistic with share repurchases and return capital through a mix of base dividends, share repurchases, and variable dividends. Now shifting topics to development, as most of those on the call know, 3-mile laterals are an important part of our program in 2023 and beyond. So I want to spend a little time discussing our latest performance and what we're expecting going forward. To date, we've drilled around 13 3-mile laterals, and when combined with the 17 wells from 2022, I'm encouraged by the performance we've seen so far. More specifically, we are seeing improving performance on well delivery and are clearly seeing a strong contribution from the productive portions of the lateral once that rock is stimulated and cleaned out. Slide nine of our presentation shows we have materially reduced drilling times for 3-mile wells over the past few years and are now running a little ahead of schedule. On the cleanouts, we've also made steady improvements and have generally been able to stimulate and access the vast majority of the 3-mile laterals. As a reminder for 3-mile wells, we are assuming a 40% EUR uplift for a 50% longer lateral and about 20% more drilling and completion costs. Said another way, we're assuming the third mile is only 80% as productive as the first two miles. In practice, what we're seeing is a volume response proportional to the percentage of the third mile that's cleaned out. So a 50% longer well that was cleaned out all the way to the TIL is generally delivering an approximately 50% uplift in EUR. In some instances, we've been unable to clean out a small portion of the TIL, and that can lead to a reduction in productivity for the last mile. But once again, we've anticipated this with our 80% production assumption. We provided more performance analysis on slide nine of our investor presentation, which shows the 3-mile wells are clearly outperforming 2-mile wells in the same area. Additionally, as you can see on the left side of slide 10, we performed a study using tracers to determine which portions of the lateral are contributing to production at specific points in time. For this test, initially, the total well was intentionally not cleaned out. We observed a strong production response from the stages that were cleaned out plus one or two stages further in the lateral, despite using dissolvable plugs. We returned to the well 10 weeks later to clean out the TIL stages and subsequently saw a strong production response from the previously unclean portion of the wellbore. Given the large number of potential 3-mile laterals, the quarter has an improved capital efficiency opportunity; these laterals represent the results we are seeing are exciting and our execution performance has been improving. We believe spending a little more time to ensure that our coiled tubing drill-outs, which is a very low-cost operation, are effective all the way to the TIL could allow us to increase the 80% efficiency number for the third mile of the lateral, which would obviously enhance our capital efficiency even further. Finally, on slide 11, you can see that in aggregate, our well performance is running slightly favorable to expectations. This can be attributed to the effectiveness of the three-mile laterals we just discussed, as well as our practice of wider well spacing, both of which we believe improve per well recoveries, increase capital efficiency, and reduce variability of performance across the asset. Moving on from development, concurrent with second-quarter results, Chord announced the sale of additional non-core properties for proceeds of approximately $29 million. This includes approximately $11 million of capital reimbursement for non-operated spinning we had not budgeted for 2023. Given this capital will be reimbursed and was not part of our original guidance, we excluded it from adjusted free cash flow and CapEx for the purposes of the second-quarter capital return. As you can see in our deck, the well volumes associated with these non-core sales approximate 500 barrels of oil per day. For clarity, these 500 barrels of oil per day are not associated with the non-operated wellbore sales but are associated with scattered legacy wells outside the Williston Basin. Year-to-date, Chord has announced over $64 million of non-core asset sales. We've updated our full-year guidance to reflect these asset sales and production gains from the XTO bolt-on acquisition, which is contributing approximately 3,000 barrels of oil per day in the second half of 2023. This bolt-on was an excellent supplement to our core inventory and demonstrates natural synergies from our scale position in the Bakken, which is now over 1 million acres. We added approximately 123 net locations, and importantly, we were also able to convert six Chord two-mile DSUs into three-mile DSUs. This further enhanced the economics of the deal, which is immediately accretive to cash flow, free cash flow, and our return metrics. In light of the above, we have updated our full-year capital forecasts to a range of $850 million to $880 million. Excluding the $11 million of reimbursed non-operating capital, the midpoint of annual CapEx investment increased approximately $20 million, largely due to additional drilling and completions activity associated with maintaining a larger production base moving forward. A brief update on ESG: Chord expects to publish its first sustainability report as a combined company in the third quarter of this year. My thanks to the team for putting together a great piece of work, and we will highlight our continued focus on improving safety and emissions and our commitment to continuous improvement and other aspects of sustainable operations while proudly delivering the energy the world needs. To sum things up, the assets are performing well, we are substantially through merger integration and have become a stronger organization than either legacy company. We have a compelling financial outlook and are keenly focused on continuing to deliver and support high levels of sustainable free cash flow as we move forward. I'll now turn it over to Michael for some additional updates.

Thanks, Danny. I'll highlight a handful of key operating and financial items for the second quarter and discuss our updated 2023 guidance. As Daniel mentioned, oil volumes were strong in the second quarter, about 1.5% over midpoint guidance. Total volumes were above the high end of guidance driven by NGL volumes. As we saw Bakken midstream providers pivot from ethane rejection in the first quarter to ethane recovery in the second quarter. This led to higher NGL volumes but weaker realizations as ethane became a larger portion of our overall NGL barrel. In addition, NGL realizations were impacted by a combination of lower Conway prices and impacts associated with our TNF fees. Our TNF fees are allocated based on a percent of gas and NGL revenues. With lower residue gas prices in the second quarter, NGL realizations were disproportionately impacted quarter-over-quarter. We have updated realization guidance to reflect recent market conditions. It seems like NGL prices hit a bottom in late second quarter and are improving into the third quarter, along with higher Henry Hub gas prices. Clearly, the Bakken has higher gathering and processing fees versus other basins. This drives higher operating leverage, which hurts realizations for both NGLs and gas in times of weaker pricing but should improve quickly as prices recover. Our 2023 activity schedule is similar to what we expected earlier in the year. TIL activity is concentrated in the second and third quarters, leading to sequential production increases in the third and fourth quarters. As Danny mentioned, we added some frac activity to the fourth quarter; however, most of the wells will not be cleaned out until early 2024, so there's no volume impact in 2023. Turning to cash costs, LOE was a little below midpoint guidance, while GPT was above. Beginning in the second quarter, we converted a crude oil marketing contract from a sales contract to a transportation contract. From an operating profit standpoint, the result of this change is neutral, but it does result in higher GPT but also higher crude oil realizations. We've updated our guidance to reflect this change going forward. Production taxes were 8.4% of oil and gas revenue, which was at the higher end of our guidance range. In North Dakota, production taxes on gas are volume-based, so better than expected gas production, coupled with weaker prices, resulted in a higher reported production tax as a percentage of revenue. As gas prices recover, it will drive a lower percentage of revenues. In addition, oil continues to become a larger portion of revenue and is taxed at a higher rate than gas and NGLs. Our forward guidance reflects oil's higher contribution to revenue as well as an escalation in North Dakota gas extraction tax in July. Chord cash G&A expense was $17.7 million in the second quarter, within the guidance range. Our 2023 G&A guidance remains unchanged at $63 million to $73 million. Chord paid no cash taxes during the second quarter, and in the second half of the year, Chord expects cash taxes to approximate between 0% and 10% of second-half EBITDA at oil prices between $70 and $90 per barrel. Our full-year capital budget guidance was increased about $20 million at midpoint, mostly reflecting higher fourth-quarter frac activity associated with the XTO bolt-on. Turning to liquidity, Chord’s borrowing base remains $2.5 billion, elected commitments remain at $1 billion, with nothing drawn as of June 30. Cash was approximately $215 million as of June 30, which is net of the final cash payments made to XTO for the bolt-on deal that closed on June 30. In closing, the Chord team continues to execute well and drive strong returns, which supports our sustainable free cash flow profile, as well as our peer-leading return of capital program. Our team continues to drive a more capital-efficient program in the Bakken, and this has led to our superior returns for our shareholders. As a result, we have returned about $28 of cash per share to shareholders in the last 12 months, along with $200 million of share buybacks. This has driven a total shareholder return of approximately 57% since the merger closed last July. We are incredibly proud to be a safe and reliable low-cost provider of energy, which contributes to a better world. We're also proud of the entire Chord team, who continued to show care for each other and our communities, and the courage to always do what is right. With that, I'll hand the call back over to Megan for questions.

The first question comes from Scott Hanold with RBC Capital Markets. Please go ahead.

Thanks, and good morning. I was wondering, Dan, can you give some more details on cleaning out the total of those three-mile wells, just out of curiosity. Can you give us some sense; like when you do that, does it take longer or more cost to make sure it's properly cleaned out? And when you do get that contribution, typically, does that influence IP rate? Is it more of a shallower decline that ultimately leads to the higher EUR?

Thanks for the question, Scott. I'm going to take a stab at this, and then I'll ask Chip to weigh in for additional color if we need to. But to go with the second part of your question first, as we think about 3-mile laterals in general, the early IP rates, and that early time production really isn't too different from what we see with 2-miles. We're not really designing larger facilities; we just ended up running that production flat for a longer period of time with the 3-miles going 2-miles. Ultimately, the decline is shallower on a 3-mile than a 2-mile because you just have more reservoir feeding in over time. Generally speaking, there isn't a big uplift in IPs on 2-miles versus 3-miles, but there is definitely a better EUR and clearly much more capital efficiency. From a cleanouts perspective, that's actually one of the really exciting things for me; the part of the operation that involves getting out to the TILs with the coiled tubing operations is one of the lowest-cost portions of the operation. Spending a little time getting further to ensure we get cleaned out all the way to the end doesn't cost us very much at all. However, it can deliver significantly improved volume contribution from that end portion of the well. So, yes, not a whole lot of incremental cost there. There may be times when we don't get 100% of it cleaned out, but spending a little longer to clean out the entire lateral has a big opportunity to move that 80% contribution from the third mile up closer to 100% contribution to that third mile, which will be fantastic. So I'll let Chip weigh in as well.

Yes, Scott, this is Chip. I agree 100% with what Danny said — flatter for longer, of course, versus the IPs. We've run tests to see what dissolvable plugs were doing and whether we have a clean wellbore or not. We will be able to identify and ensure we're knocking this out as quickly as possible. For a very small additional amount of time, we can hopefully get all of the wellbore cleaned out successfully.

That sounds good. And then I guess a question that leads me to the next is as you think about getting more of these three-milers online, and obviously with a little bit more back half or early momentum as you get 2024, what does that say about the capital efficiency of the program going into 2024? Should we be able to see a little bit of an improvement on that given those two factors? Coupled with I guess OFS cost reductions, it seems to be moving in your favor?

So, Scott, as we look forward, clearly, we're driving capital efficiency in all aspects of our business. This additional opportunity we see with the 3-mile laterals and the coil tubing drill outs that we just discussed obviously helps with that. In a deflationary environment with oilfield services, I'd say, we're seeing some encouraging signs; however, it's still a bit early to fully roll that into our planning process. We've got line items that are certainly lower, but we also have some line items that are higher. Labor costs tend to be sticky, and the recent recovery in oil prices is likely to provide some support to service costs as well. We're seeing encouraging signs technically, but I’m not ready to complete that transition yet. We’re working on developing a plan that's essentially a maintenance-level plan versus our current year, and we'll be ready to talk about it later this year, probably detailing specific guidance in early 2024.

Our next question comes from Derrick Whitfield with Stifel, please go ahead.

Thanks. Good morning, all. Congrats on another strong quarter. For my first question, I wanted to build on Scott's question. Given the proof of the tracer data that you show on slide 10, does that bias you to inch up your recovery assumptions for the last mile?

I'm sorry, say that one more time, Derrick.

Sure, given the proof of the tracer data on slide 10 of your presentation, does that bias you to inch up your recovery assumptions for the last mile of the lateral?

I think as we get more data on this, that would be the implication. That 80% recovery vision for that last mile, if we're successful in getting all the way out to the toe, as we have been able to on our last six wells, will show results coming through that. This could allow us to start moving that 80% recovery rate for the last mile up closer to 100% recovery, which is the goal here.

Thanks, Danny. As my follow-up, I'd like to ask about the AMD environment in the Williston at present. Are you seeing greater deal flow now that the well has stabilized and private equity is seemingly trending affluent?

From my perspective, there's always been a bit of chatter in Williston across various asset types, from small asset trades to private equity opportunities. I haven't noticed a significant uptick, just a steady flow of evaluation of options, and we keep our ear to the ground. We feel like we are a natural consolidator within that basin and are attentive to what’s going on. As you saw with the XTO acquisition, we believe when opportunities come that align with our objectives, those moves will relate to value for the organization and for shareholders.

Our next question comes from Neal Dingmann with Truist. Please go ahead.

Good morning, guys. Could you tell me what's driving — you still see some remarkable results in Indian Hills? I'm just wondering if that's from water spacing, laterals, efficiencies, if you could just point to the details there?

Thanks, Neil. In Indian Hills, it's a good location in the basin. We have spread those wells out wider and have moved more toward 3-mile laterals. So it's a combination of subsurface quality, wider spacing, and the 3-mile laterals. A slide in the deck shows some of the variant contributions, but we are happy with what we're seeing there.

Neal, you're exactly right. That slide on page nine shows what's happening there. We're taking that knowledge of spacing and longer laterals to other areas across the basin, so we anticipate seeing continued positive results as we move forward.

Yes, it really seems to be working well, guys. Just to follow-up on shareholder returns, Danny you talked about this in prepared remarks. As you look ahead, does this mean you'll diverge from what you were previously doing? Are you thinking about more of a formulaic plan?

As we discussed last quarter, we felt we were being restrictive in how we were judging our performance relative to others. We believe from an intrinsic value standpoint that we're a pretty compelling opportunity. Opening the aperture allowed us to do more share repurchases, which is a slight departure from our earlier focus. We see this as part of our commitment to a strong return program. Our strategy is rooted in ensuring we maximize our intrinsic value and effectively manage our capital return initiatives.

Our next question comes from Philip Johnston with Capital One, please go ahead.

Hey, guys. Thanks. Your CapEx guidance implies that we'll see a fairly large reduction in spending in Q4. Can you provide some context there? How should we think about what that means for production momentum going into next year?

Thanks, Philip. Early in the year, we set guidance based on a program where we started with one frack crew. We added a frack crew as we moved into the warmer months. For the second and third quarters, we ran two frack crews, but in the first and fourth quarters, we'll run only one due to winter weather in North Dakota. This drop-off explains the reduction in capital, and we will continue to drill wells into the fourth quarter while resuming capital activity as conditions allow. We recognize this creates cyclicality in our production profile but believe this is a more capital-efficient approach to managing our program.

Looking into next year, do you think about a three and a half rig program or so? On the mix of three-mile laterals, do you think it will be similar to this year around 50%, or will it be significantly different next year?

I believe the three-mile lateral program will be similar to this year, as we are still determining the specific DSUs we’ll be drilling. From a drilling perspective, I anticipate we will run around a four-rig program next year.

Our next question comes from Oliver Huang with TPH. Please go ahead.

Good morning, Danny, Michael, Chip and team. Thanks for taking my questions. I wanted to hit on the drilling side of things. The improvements had been sizable over the last six months on the three-mile laterals. How much more running room do you see on this front? Or has the low-hanging fruit already been captured? How should we think about potential dovetails into year-end if the accelerated pace continues? How might this help the 2024 program?

It's Chip Rimer. I appreciate the question. I'm really excited about what the team has done here. Prior to the merger, the average drilling time was around 17 days. Through the best practices we adopted, we are bringing various improvements from fluids to bottom-hole assembly designs, each tweak brings us efficiency boosts. I'm excited for what our teams are doing on the drilling side. The low-hanging fruit may be harder to recapture, but we continue to refine operations.

Thanks, I appreciate the color. On the facility side, as you begin more activity in areas like Red Bank, Painted Woods, and Foreman Butte, is the facility infrastructure in good shape? Or are we looking at increased constraints on the three-mile lateral wells, given the other areas with potentially less historic activity?

Oliver, that’s a great question. We are cautious in our planning and drilling to ensure we have the necessary infrastructure for takeaway volumes, whether through our gathering systems or long-haul pipelines. I don't anticipate significant constraints due to our development strategy.

The strong inventory across a large portion of our acreage allows us to drill in various locations, helping to minimize infrastructure constraints. Spreading the program across a larger area benefits every pipeline as we manage our operations.

Gas capture is also a priority, and we aim to keep those gas capture numbers high to avoid concentration in any one area.

Our next question comes from John Abbott with Bank of America. Please go ahead.

Good morning, and thank you for taking our questions. My first question is on GP&T. I understand that if you're going to understand the accounting change, there's no impact on margin. But why make the change if there's no benefit to you? What is the benefit of switching from the sales to the transportation contract? Could we see a better realization versus just assuming neutrality?

That's a good question, John. The contract is a form of our operational changes. I don't believe it changes our overall margins. We have raised GPT a bit, as we have experienced in that specific deal. It pushes the GPT up while also achieving higher crude oil realizations. This allows us to adjust our operations according to market variability.

Very helpful. Could you also provide your latest thoughts on cash tax guidance for the second half of the year? I understand it's between 0% to 10%?

For cash taxes in the latter part of this year, we're looking at 0% to 10% of EBITDA at oil prices between $70 and $90 per barrel. Going forward next year, we see it in the same $70 to $90 range, probably between 4% to 11%. We'll be cash tax-paying going forward, but this should be the general range to consider.

This concludes our question-and-answer session. I would like to turn the conference back over to Danny Brown, Chief Executive Officer, for any closing remarks.

Thanks, Megan. To close out, I just want to thank the employees of Chord for their commitment and dedication to our organization. Last year was a pivotal year for our company, and I know the team worked hard to integrate our predecessor companies and put us in a great position to succeed moving forward. To our investors, I'd say Chord is positioned to deliver value for its shareholders through disciplined capital allocation, efficient operations, and maintaining a strong balance sheet while remaining committed to responsible operations. Thanks, everyone for joining our call.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.