Good day, ladies and gentlemen. Welcome to Denbury's First Quarter 2023 results Webcast. My name is Layla. I will be your operator for today's call. At this time, participants are in listen-only mode. Later, we will conduct a question-and-answer session. I would now like to turn the conference call over to your host for today's call, Brad Whitmarsh; Head of Investor Relations. Please proceed, sir. Good morning, everyone. Thank you for joining us today. I hope you've had a chance to review the earnings release and the supporting materials that were issued yesterday afternoon. These items are available on our website at denbury.com. I wanna remind everyone that today's call will include forward-looking statements that are based on our best and most reasonable information. Numerous factors could cause actual results to differ materially from what is discussed on today's call. You can read our full disclosures on forward-looking statements and the risk factors associated with our business in the slides accompanying today's presentation, our most recent SEC filing in yesterday's news release. Please note that during the course of today's event, we may reference certain non-GAAP measures. Reconciliation and disclosure relative to these measures is provided in today's earnings release as well. This morning, our prepared comments, which are estimated at approximately 10 minutes, will come from Chris Kendall, our President and CEO. Mark Allen, CFO, David Sheppard, COO, Nikulas Wood, SVP of Carbon Solutions, and Matthew Dahan, SVP of Business Development and Technology, are all here to participate in the Q&A. I'll turn the call over to Chris. Thanks, Brad, and good morning to all of you who are joining us today. I'll make a few opening comments, and then we'll open the call for your questions. Looking back, it's now been 3 years since the enhanced 45Q CCUS tax credit was published in the Federal Register. Our vision at the time was that Denbury's deep CO2 expertise and our extensive strategically positioned CO2 infrastructure would propel us into leadership in a new high-growth CCUS industry. 3 years later, we are well along that path. Denbury's unique and important role in the industry is more clear today than ever, and our view of the possibilities and value of this business has only grown greater. This is all on top of an already strong EOR business. It is an incredibly exciting time to be at Denbury. This morning, I will focus on three primary areas: highlights from our first quarter results, an update on good progress on our CCA enhanced oil recovery development, and new accomplishments toward advancing our CCUS strategy. We've had a great start to the year. Denbury delivered strong first-quarter operating and financial results across the board. Our safety performance continued near record levels, and production, pricing, and all of our cost items were in line with our annual guidance. Operating cash flow before working capital changes totaled $140 million for the quarter, exceeding our development capital expenditures by $20 million. We also spent nearly $9 million in our asset retirement program for our most mature fields and invested $7 million through equity investments in two carbon capture technologies, ION and Aqualung. We ended the first quarter with $672 million in liquidity and $68 million of debt, with a modest increase in debt from year-end, primarily due to annual working capital outflows for bonus and ad valorem tax payments. Sales volumes in the first quarter averaged around 47,700 Boe per day, up more than 1,000 Boe per day sequentially, with the various ins and outs described in more detail in our earnings release. Bottom line, we are on track with our plan, and we see production relatively flat in the second quarter. On the capital front, $510 million remains our midpoint for the year, and we expect capital to be modestly higher in the second quarter, with CCUS being the primary driver, including anticipated storage site acquisitions, such as the one we just announced, and other pre-development spend. In early April, we took advantage of strong oil prices to round out our hedge portfolio in the second half of 2023 and to layer in additional hedges in 2024. Turning to the Cedar Creek Anticline, we are very pleased with what we've seen so far on the CCA EOR project. With our first recycle facility online at Cedar Hill South, we're monitoring production performance associated with this facility and now expect to see first EOR production this quarter from this game-changer asset. Our team is now commissioning the second CO2 recycle facility, and two more are scheduled to be brought online late in the third quarter. We still anticipate incremental EOR production to ramp to around 2,000 barrels per day by the end of this year and to peak in a range of 7,500-12,500 barrels per day in the latter part of 2024. I'm extremely proud of the work our team is doing at CCA. As a reminder, CCA is the largest EOR project we've ever worked on, with 400 million barrels of potential recovery. It will drive 2024 and 2025 production growth for our company, and as it ramps, it'll also improve our cash margins. In addition, the CO2 we're injecting is 100% industrial source. All of the new volumes are expanding the scope of our carbon-negative blue oil operations. CCA will be a significant contributor to our overall goal of being Scope 3 net zero by the end of this decade. As the CCA project highlights, the EOR side of our business is fundamental to the execution of our CCUS vision. Denbury has the near-term ability to take upwards of 10 million tons of captured industrial CO2 per year into EOR. Our EOR business provides strong cash flow that can be deployed in CCUS investments. It supports the development of the technical and operating capabilities as well as the pipeline infrastructure necessary for CCUS. The unique combination of these competencies, capabilities, and assets sets Denbury apart in the industry. Our 2023 CCUS activities are highly focused on both expanding our dedicated CO2 storage network and continuing to build the scale and diversity of our CO2 transportation and storage agreement portfolio. During the first quarter, we drilled our first stratigraphic test well at the Orion site in Alabama in support of our Class VI process. We were pleased to see reservoir characteristics very consistent with our expectations. We should receive detailed core analysis later this year, which will further confirm our understanding of the subsurface as we progress this storage site with the EPA. We expect to continue to drill stratigraphic test wells on our lease storage sites to support the Class VI process with at least two additional wells planned this year. Since quarter end, we finalized an agreement for a 30,000-acre, 115-million-metric-ton dedicated CO2 storage site in Matagorda County, Texas. Adding this site to our network provides additional flexibility and redundancy in removing CO2 from the high-emissions, Houston area. In addition, it facilitates access to multiple emission sources, e-fuels customer plant sites, and EOR development opportunities while serving as a stepping stone to additional opportunities further along the Texas Gulf Coast. Last week, we submitted six well permit applications to the EPA for Class VI CO2 injection at our LEO site in Mississippi. LEO is directly underneath our NEJD Pipeline, an example of the great advantages afforded by our over 900 mi Gulf Coast CO2 pipeline network. The LEO site, leased from Weyerhaeuser, provides tremendous competitive advantage and flexibility for our CO2 network, leveraging our infrastructure footprint in Mississippi. We expect to submit Class VI permits for additional sites at a cadence of about 1 site per quarter over the next several quarters. Nick and his team are in extensive discussions and negotiations to provide CCUS services for multiple customers with both brownfield and greenfield projects, my confidence level in reaching our cumulative 30 million metric ton per year target by the end of the year is high. As a reminder, these agreements can be for combined transportation and storage, transportation only, or even the complete chain of capture through storage. With the industry's only dedicated CO2 pipeline network in the Gulf Coast, we remain ideally positioned to service the growing market for CCUS solutions. We believe that Denbury's vast CO2 pipeline network, combined with multiple strategically located dedicated storage sites and reinforced by over a dozen EOR CO2 injection sites, will provide customers the most efficient, diverse, and the most reliable CO2 transportation and storage service in the Gulf Coast. As I mentioned at the outset, it's a very exciting time here at Denbury. Our EOR business is generating strong cash flow, and we expect to see incremental production from our CCA EOR project this quarter. At the same time, we're making rapid progress on building the industry's leading CO2 transportation and storage network. I can't think of a company better positioned to deliver the energy we all need today while decarbonizing the future. Thanks again for joining us today, and we'll now open the call for your questions. We will now begin with the Q&A session. Please note that this call is being recorded. Questions will be answered in the order they are received. We will now pause a moment to assemble the queue. Our first question will come from Scott Gruber from Citi. Yes, good morning. Morning, Scott. I want to start on the recent news here that the EPA signaled its intent to give primacy to Louisiana, you know, with regard to Class VI well permitting. I think there are of a couple extra steps here to jump through, including a comment period. Do you have a sense for when state officials in Louisiana could start processing permits and any sense for what a reasonable timeframe, you know, could look like to execute a, you know, the processing of a permit, you know, at the state level versus that kind of two-year expectation at the EPA? Yeah, Scott, this is Matthew Dahan. We're really pleased to see the EPA post Louisiana's application on the Federal Register, which actually happened on the 28, subject to public comment. Louisiana following up with announcing a June 15 public hearing in Baton Rouge. Public comment stays open till the 26is of June, they start the final process and codification of the rulemaking process. Our expectation is we may be towards year-end or early 2024 that primacy is officially granted. I think from a processing standpoint, I would imagine that as Louisiana gets up to speed, they'll be running about the same timeframe initially as what the EPA would. As time goes on, I think those processes will speed up significantly. Scott, I'd just add to Matt's comment there. I mean, we're thrilled to see yet another step that opens the pathway for CCUS to broadly accelerate, as it needs to, just with the opportunity set that we see out there, one more step like this is a very positive thing in our view. Got you. Just a question on the permitting process with the EPA. You're now, you know, six months or so out from the initial submissions last fall. What's been the feedback from the EPA at this juncture? Any updated color as to, you know, whether that, you know, kind of two-year timeframe is still reasonable, whether it could be. Just some, you know, updated thoughts there would be great. Hi, this is Nick. Yeah. The EPA has been processing the permits at the same pace that we expected them to. They show that they go through the verification of completion at about the same timeframe we expected. We see that they are going through the details at about the speed we expected. We're still looking at about a two-year timeframe there. Yeah. I guess the bottom line there, Scott, is just the engagement from the EPA has been solid. We feel good about where we are with the EPA. To me, that's a good start with the primacy for Louisiana. Looks like it's coming. That's just that much better. Very good. Appreciate the color. We'll turn it back. Thanks, Scott. Thank you. Our next question comes from Nathaniel Pendleton from Stifel. Morning, congrats on the new site and Class VI permit submission. Thanks, Nate. Nate, good morning. Regarding your pore space leasing success, can you provide some color on the level of competition for sequestration sites in the market? Specifically, how are prices trending for pore space? How should we think about the availability of high-quality pore space along the Gulf Coast? Hi, Nate. This is Nick. I'll take that question. In terms of competition for pore space, there is high competition for pore space. What Denbury brings is the advantage of being able to talk about the volumes we can bring to that pore space. When we're in negotiations, there's a series of different variables that the pore space owners are looking for. I would say the main one is the amount of volume you can actually take to the storage site, because that's a big driver of their economic viability for that pore space owner. Denbury brings big advantage there. That's that drives our success. We expect to continue to be successful there. You'll see us continue to add to our portfolio of storage sites. When it comes to the variance of pore space charges, it's been pretty steady. Thanks. Appreciate the color. In your release, you mentioned that capital is being deployed to expand current sites. Can you elaborate on the opportunity to expand those sites? Knowing that storage calculations are often conservative using the DOE methodology, as you learn more about a reservoir, do you expect the storage capacity and potentially injectivity estimates to increase? Yeah, that's a great point. This is Nick again. Yes. We are continuing to expand our sites. We do that through additional acquisitions of offset acreage to the site. If you think about the steps, the first step is to identify the large pore space owner and, you know, get a contract with them. Then from there, we continue to add to the contiguous acreage that initial owner is connected to increase the total pore space amount. In regards to your second question around the conservative nature of the evaluation of the storage site, I would say you're accurate in that the upfront science usually puts what I'll call kind of a lower range of the initial pore space that's available, along with the availability of injection as time goes on, you will probably see an increase in both pore space and injection rates. Great. Thanks for taking my questions. Thanks, Nate. Our next question comes from Tim Rezvan from KeyBank. Good morning. Morning, Tim. I just had a question on, sort of the state of the brownfield market. I know in my discussions with you all in the past, folks have been a little bit frustrated. There haven't been more contracts that have gotten over the finish line. You know, a lot of people believe this would be a quicker path to first revenue. Can you just kinda give an update on what you're seeing and, you know, maybe why there's a logjam and how we could think about contracts getting over the finish line this year? Sure. This is Nick. Hi, Tim. This is Nick. I'll take that question. We're currently engaged and have been engaged with many brownfield projects. I would say it's about half of the portfolio or pipeline of projects we have going through the system right now. I think we've explained it before as it's like remodeling a house versus building a house, where a lot of the brownfield developers have to go in and rearrange their process, which takes a bit of extra time to evaluate and to make sure that their economics match up to what they expected as they started the scoping exercises of the project initially. I would say that right now, we've seen a lot of great progress with a lot of brownfield projects that we've actually been engaged with for multiple years now. In some cases, we've been engaged for over two years, and so we see a lot of those projects coming to completion, hopefully, you know, maybe this year. There's chances that some of these projects take over three years to actually get to the finish line, and we're happy to be with our partners that whole time. I guess we'll stay tuned. That's fair. I appreciate the comments on CCA. That was originally gonna be my first question or my second question. I wanted to ask about, you know, the Dorado sequestration site. Obviously, you know, it's not gonna be connected to an existing pipeline. You know, if that were to develop, can you talk about kind of the cost or the time it would take to sort of build that potential extension to that area? Hi, Tim. It's Nick again. The Dorado site's great. It was one of the big sites that we wanted to add to our portfolio for many reasons. Some of the things that might not be quite as clear is the positioning on that site is great for our portfolio. The reason is it does a few things for us. One, that extension brings us into new markets, both in capturing emissions, also additional storage sites that could be acquired nearby. It also brings us closer to EOR fields that we can develop. Finally, it adds to kind of the path that we might go on to continuing down Corpus. With any storage site, the benefits come with, you know, adding the total storage that's in our portfolio. In this particular case, the position of the storage site allows us the opportunity to go bidirectionally at a point that has a lot of expected emissions coming in. What that does is it allows us to have a high capacity increase to our total network. That's kind of the reasoning behind the Dorado site's position and why it's so valuable. I'll say from a cost standpoint, it's about 60 miles away, and we'll stick with the $2 -4 million a mile expectation in cost. I would say for this site, it's probably on the lower side of cost. That's the range we're thinking. Tim, this is Chris. I'd just add to that, just strategically, when we look at where we are and where we want to be, we love the footprint that we have, but we also think that that backbone really sets us up to extend into some key emissions areas. Moving down towards the Corpus Christi area is a part of that, and this helps us get there. Okay. I appreciate the color. Just the timeline it would take, just theoretically, big picture, to, you know, to get something like that built and permitted? Yeah. This is Nick again. I'm sorry. Tim, was that another question? No. Okay. No, just any big picture comment. Yeah. The thought is it'd probably take us a couple years to get the pipeline permitted and installed. The reality of what will happen is because we can probably move faster than the I'll call it the need from an emissions standpoint. We would line up that investment with the need for the emissions moving down that pipe. Because we can kind of be at, on a quicker pace, it's gonna be really dependent upon when we have emissions coming to line, when we actually start construction and finish it out. Okay. That makes sense. Thank you for the comments. Sure. Thanks, Tim. As a reminder, if you have a question, you may raise your hand by using the Raise Hand feature at the bottom of your Zoom window or by dialing star nine, if you've joined us today by phone. Our next question will come from George Burwell from Jefferies. Hey, guys. I'll actually steal Tim's line of questioning, but apply it to perhaps like a larger-scale pipeline. I know you guys have been asked about replacement value for the pipeline system in Green in the past, but curious if that two-four per mile rule of thumb would apply for a larger-scale long-haul line. Then any sort of commentary you could give about the permitting process, time to plan, anything on it from a timing perspective, and really, like, how would that process differ from the process that you guys undertook in the late 2000s when you built Green? Hi, George Burwell. This is Nick again. In terms of replicating our network, we believe it'd be challenging to do in general. There'd be a lot of permits that are very tough to get through, that we were able to accomplish, 10+ years ago, in general. When you think about the replication of that line, the $2 -4 million a mile, we believe would be potentially a little bit light, in the sense that there are a lot of crossings that we're able to, I guess, not have in our shorter extensions that you would have to go through when traversing, the territories that we go across in replicating that line. We would expect it to be a bit higher than the $2 -4 million a mile. In terms of permitting, there's a lot of different agencies that come into play depending upon where you're at, when you're permitting a pipeline. I'd say that you can think about the short pipelines that we're dealing with, when we're connecting either emitters or storage sites as being in the two-year timeframe, in terms of being able to permit and construct. When you're going down a larger, you know, multi-state connection, there will be a lot longer timeline in accomplishing that. Yeah. Sam, I just think that along the lines of what Nick said, when we stay in the local and regional level, it's one thing, but as we expand into something that's as that is broader than that, I mean, honestly, we see how that's working across the country even here today. That's part of what makes us feel so good about that framework that we have in place right now. Okay. That's really helpful. Following would be sort of On Dorado, what can you comment as to the subsurface there? Is it similar to GCMP? Maybe zooming out a little bit, like, would you comment on how the storage space that's available in Texas might differ from what's available in Louisiana and Mississippi and Alabama? Hi there. Yeah, this is Nick again. The subsurface for Dorado is very much like the pore space that we've acquired on most all of our other sites. It's what we think of as a flat reservoir. It doesn't have a lot of dip to it. The pore space is attached to a saline aquifer, so there hasn't been a lot of well penetrations, which is a very big deal when you're evaluating a storage site, because there wasn't oil and gas necessarily development through that particular area. Very promising there. Just in general, the actual storage intervals and the sandstones that we're dealing with in Texas look very much like the Louis-Louisiana pore space. The difference between the Louisiana pore space and the Texas pore space and availability is around the rules of actually owning the pore space. Louisiana, there's a bit more firmness around the surface owners owning the pore space. In Texas, that hasn't necessarily been completed yet. Which way that goes, whether it's minerals on the surface isn't fully baked quite yet. The way we accommodate that issue is we look for pore space that has both the surface and the mineral owners, and we acquire those sites, which is the case in Dorado. Super quick follow-up on that. Would the, like, surface and mineral rights being more aligned in Louisiana, does that make it easier to lease in Louisiana in general? I would say that it makes it easier to target large areas to lease because you have a surface owner that doesn't necessarily have to have the mineral owner be the same group to acquire that particular storage site. I will point out that in general when Denbury is looking to acquire storage sites, we still want those incentives to be aligned. We want everyone to win in this circumstance. Generally, we look for places where the surface and mineral owner are the same group, so that we can acquire and feel good about the storage site and where we're going. Okay, awesome. Thanks for indulging my third question. Thanks, Sam. Our next question comes from Charles Meade from Johnson Rice. Good morning, Chris and Nick, and the rest of the Denbury team there. Hey, Charles. Chris, I wanna maybe apologize ahead of time for what may seem like an elementary question about the whole Class VI permit process, but I think that this would be helpful to me and probably to a lot of other people listening to this call. Can you give us a little bit more detail and context about how many stratigraphic wells you need to drill in order to support a Class VI permit? Going back to your prepared comments, it sounds like you said I think you said maybe six Class VI permits at your Leo location. Did I hear that correctly? What drives the number of Class VI permits you need? Yeah, you bet, Charles. I'll ask Nick to take that on as well. Hi, Charles, it's Nick. Thanks for the questions. When it comes to stratigraphic well tests, generally each storage site that we develop will most likely take one. I will say that they aren't absolutely necessary for the Class VI process. What generally happens during the Class VI process is that you submit your permit, you get the completion verified. You then go to a point where you have this back and forth with the EPA or whatever regulatory agency you're dealing with that has questions on the technical evaluation. You then get to the point where you have a permit to construct. Once you have permit to construct, you then actually take a drilling rig and go drill the well that it will be the Class VI well. At that point in time, most groups are taking the core and then sending it off for analysis, which usually takes around six months. They have to usually have that full analysis done at that point in time. That then kind of puts an additional, I'll call it, task in the Gantt chart in terms of timing, and kind of leads to a little bit of a longer-term process, relative to what Denbury is doing. Generally, that's where the core would be taken. At that point in time, you get the information back from the core, and then you then have some injection testing you have to do. From that point, as long as everything comes in as you expected, you then get the permit to inject and begin injection. In our case, what we're doing is we're speeding up the classic permit process by drilling stratigraphic wells early because we can get that permit early. We can get the stratigraphic permit to go drill a well, gather that core, and send it to have it analyzed in parallel to those other steps that are taking place at the EPA. That bypasses the need to potentially have to core and analyze that Class VI well after you have that permit to construct. I'll pause there, see if there's any questions on that piece before I move to your second question. No, that's an excellent explanation. Please continue. All right, great. When it comes to the Leo site and the six Class VI permits that Chris mentioned, what happens during the evaluation of a storage site is you have an area of review where you do a very detailed geologic study of the pore space, and then you run reservoir simulation across that pore space to watch how the CO2 will move throughout the system. As you're doing that, you optimally place wells within that pore space to make sure that the pressure and the CO2 traveling through the pore space stays contained within the area you want. Of course, what you want out of any given storage site is a lot of potential rate and a lot of storage availability. When you see us put in multiple wells in a storage site, that means that we're increasing the total rate that storage site can accommodate at this point in time, given the position we have. At this point in time, we have, you know, 6 wells here that you can think are gonna generate somewhere between 500,000 tons per year to 2 million tons per year of injection rate. That's just for the current position. As you can imagine, we're continuing to add to that position, which will add to the availability of additional injection as we continue. I guess just fundamentally, Charles, you're gonna have a permit for a well. Nick's talking about six we lls, and so we have six permits. Got it. Thank you for all that, Nick. That was a really helpful elaboration. Chris, perhaps this follow-up might be for you or Matt. You cited that the, you know, the eventual rate for CCA would be, I think you said between 7.5 and 12.5 thousand barrels a day. I'm wondering if you can, if you can give us some indication on what are gonna be the factors that determine where you wind up on that spectrum, perhaps, you know, given that you've I guess last quarterly call, you talked about seeing CO2 early, and now we're hearing that you're actually gonna get EOR volumes early? Does that bias you to one end of that spectrum or the other? You bet, Charles. I'm gonna hand it over to David in a moment here to talk in a bit more detail about that. You know, bottom line, we're excited about what we see. It's also early days. There's much to be determined. You know how business works with some of these floods, and you really need to work the data as it comes in. With that, I'll turn it over to David. Good question, Charles. You know, thanks for asking that. Yeah, we're really excited about getting this first recycle facility commissioned. You know, got that online, have introduced a few wells into that facility. I would say this facility is in the heart of where we've seen some of that early CO2 arrival. Correspondingly, we're seeing, you know, some indicators that's gonna help us to get to that point in the second quarter where we're gonna declare, you know, some EOR response within that particular recycle facility. You know, we're currently commissioning a second recycle facility that's in near proximity, same field, CHSU. We will bring those wells into that system and, you know, get to watch that and make the further assessment. You know, continuing on that path, we have two more recycling facilities coming in to CHSU this year towards the back end of the third quarter, so it's gonna be later in the year. You know, once we bring those on, bring wells into those two independent systems, we'll get to assess and see if our model or our expectation, you know, is on track. Everything that we've seen so far, you know, tilts us to it is, you know, it's a solid plan, you know, right now, and every data point we're acquiring, you know, confirms that. Real happy, you know about that. Those recycle facilities, you know, throughout time will be expanded. We'll bring in additional compression. You know, as we move more CO2 through the system, that will expand our production capabilities, you know, throughout this area, ultimately targeting that 7,500-12,500 barrel a day window. There's gonna be some ebbs and flows in that, you know, throughout time as our development pace expands and goes a little faster or moderates throughout time. That's a general range to think about the long-term trajectory of how we're going to produce this particular asset. Yeah. Charles, I think just as we go forward, every quarter, you'll see us update with new data points, as David mentioned, and hopefully be able to tighten what admittedly is a fairly wide range as you pointed out there. I'm sure you guys are more eager for the data than I am, so I look forward to hearing more about that on future calls. We're all eager for the data. That's right. All right. Thanks, guys. Thanks, Charles. Operator Layla, I think we've got maybe 1 more question in the queue? Yes. We can take a question from Brian Velie from Capital One. All of my questions have been answered. Thank you very much. Thanks, Brian. All right. Thank you, Brian. No further questions on the line at this time. Thank you. Yeah, this is Brad. Again, just wanna thank everyone for joining us today. Should you have any follow-up over the coming days, please don't hesitate to reach out to Beth or myself. We look forward to connecting with you all. Thanks again.