Denbury, Inc. (DEN) Q1 2023 Earnings Call Transcript
Good day, ladies and gentlemen, and welcome to Denbury’s First Quarter 2023 Results Webcast. My name is Layla, and I will be your operator for today’s call. [Operator Instructions]. 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, and 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 want to remind everyone that today’s call will include forward-looking statements that are based on our best and most reasonable information. There are numerous factors that 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, and yesterday’s news release.
Also, 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; Nick Wood, SVP of Carbon Solutions; and Matt Dahan, SVP of Business Development and Technology are all here to participate in the Q&A.
With that, I’ll turn the call over to Chris.
Thanks, Brad, and good morning to all of you 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 [indiscernible] 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 2 carbon capture technologies, ION and Aqualung. We ended the first quarter with $672 million in liquidity and $68 million in debt, with a modest increase in debt from year-end primarily due to annual working capital outflows for bonus and ad valorum 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 predevelopment 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 Hills South, we are 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 2 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 to 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 will also improve our cash margins.
In addition, the CO2 we’re injecting is 100% industrial source, so 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 0 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, and 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 the 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 2 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 6 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-mile 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, and 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, the most 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 decarbonize in the future.
Thanks again for joining us today, and we’ll now open the call for your questions.
[Operator Instructions]. Our first question will come from Scott Gruber from Citi.
So I’m going to start on the recent news here that the EPA has signaled its intent to get promising to Louisiana with regard to Class VI well permitting. I think there’s a couple of extra steps here to jump through, including a comment here. But do you have a sense for when state officials in Louisiana could start processing permits, and any sense for what a reasonable timeframe could look like to execute the processing of a permit at the state level versus that kind of 2-year expectation at the EPA?
Yes, Scott, this is Matt Dahan. And we’re really pleased to see the EPA post Louisiana’s application on the Federal Register, which actually happened on the 28th subject to public comment, and then Louisiana following up with announcing a June 15 public hearing in Baton Rouge. Public comment stays open until the 26th of June, and then 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 will be running about the same timeframe initially is what the EPA would. But as time goes on, I think those processes will speed up significantly.
And 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.
And then just a question on the permitting process with the EPA. You’re now 6 months or so out from the initial submissions last fall. What’s been the feedback from the EPA at this juncture? And any updated color as to whether that kind of 2-year timeframe is still reasonable, whether it could be [indiscernible], just some updated thoughts there would be great.
This is Nick. Yes, so the EPA has been processing the permits in the same cadence that we expected them to. They showed 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. So we’re still looking at about a 2-year timeframe there.
Yes. And I guess the bottom line there, Scott, is just the engagement from the EPA has been solid. And so we feel good about where we are with the EPA. And to me, that’s a good start with the primacy for Louisiana looks like it’s coming. That’s just that much better.
Our next question comes from Nate Pendleton from Stifel.
Congrats on the new site and Class VI Permit submissions. Regarding your port-based leasing success, can you provide some color on the level of competition for sequestration sites in the market? And specifically, how are prices trending for core space? And how should we think about the availability of high-quality pore space along the Gulf Coast?
Yes. So Nate, this is Nick. I’ll take that question. So 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. So 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 we can actually take to the storage site, because that’s a big driver of their economic viability for that pore space owner.
And so Denbury brings a big advantage there. And so 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.
And in your release, you mentioned that capital is being deployed to expand current sites. Can you elaborate on the opportunity to expand those sites? And 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?
Yes. That’s a great point. This is Nick again. Yes. So we are continuing to expand our sites. We do that through additional acquisitions of offset acreage to the site. So if you think about the steps, the first step is to identify the large pore base owner and get a contract with them. And then from there, we continue to add to the continuous acreage that that initial owner is connected to 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 the lower range of the initial pore space that’s available along with the availability of injection. So as time goes on, you will probably see an increase in both pore space and injection rates.
Next question comes from Tim Rezvan from KeyBanc.
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. A lot of people believe this would be a quicker path to first revenue. So can you just kind of give an update on what you’re seeing and maybe why there’s a logjam, and how we could think about contracts getting over the finish line this year?
Sure. This is 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. So in some cases, we’ve been engaged for over 2 years. And so we see a lot of those projects coming to completion, hopefully maybe this year, but there’s chances that some of these projects take over 3 years to actually get to the finish line, and we’re happy to be with our partners that whole time.
So I guess we’ll stay tuned. And then I appreciate the comments on CCA. That was originally going to be my first question, or my second question. But I wanted to ask about the sequestration site. Obviously, it’s not going to be connected to an existing pipeline. 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?
Tim, it’s Nick again. Yes, so the Dorado site’s great. It is one of the big sites that we wanted to add to our portfolio for many reasons. And some of the things that might not be quite as clear as 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. And 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 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. So 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 million to $4 million a mile expectation and cost. I would say for this site, it’s probably on the lower side of costs, so that’s the range we’re thinking.
And then, Tim, this is Chris. I’ll 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. So moving down towards the Corpus Christi area is a part of that, and this helps us get there.
And then just the timeline that would take just theoretically, big-picture, to get something like that built and permitted.
So this is Nick again. I’m sorry. Tim, was that another question?
No, I was just trying to [indiscernible] big-picture.
So the thought is it probably takes us a couple of years to get the pipeline permitted and installed. The reality of what will happen is because we can probably move faster than, I’ll call it, the need from an emission standpoint. We would line up that investment with the need for the emissions moving down that pipe. So because we can kind of be on a quicker pace, it’s going to be really dependent upon when we have emissions coming to line when we actually start construction and finish it out.
[Operator Instructions]. And our next question will come from Sam Burwell from Jefferies.
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 $2 million to $4 million per mile rule of thumb would apply for a larger scale long-haul line? And 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?
Sam, this is Nick again. So in terms of replicating our network, we believe it will be challenging to do in general. There would be a lot of permits that are very tough to get through that we were able to accomplish 10 years ago-plus, in general. When you think about the replication of that line, the $2 million to $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. So we would expect it to be a bit higher than the $2 million to $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 2-year timeframe in terms of being able to permit and construct. When you’re going down a larger multistate connection, there will be a lot longer time line in accomplishing that.
Yes. And 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 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.
That’s really helpful. The follow-up would be sort of on Dorado. What can you comment as to the subsurface there? Is it similar to GCNP? And then, maybe zooming out a little bit, 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?
Yes, this is Nick again. And so 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. So 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 Louisiana pore space. The difference between the Louisiana space and the Texas pore space and availability is around the rules of actually owning the pore space. And so, Louisiana, there’s a bit more firmness around the surface owners owning the pore space. In Texas, that hasn’t necessarily been completed yet. And so, and which way that goes, whether it’s minerals in the surface, isn’t fully baked quite yet.
So 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.
Okay. Super quick follow-up on that would be, 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 the circumstance. So 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 side and where we’re going.
Our next question comes from Charles Meade from Johnson Rice.
Chris, I want to apologize ahead of time for what may seem like an elementary question about the whole Class VI permit process, but I think this would be helpful for 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? And then going back to your prepared comments, I think you said maybe 6 Class VI commits at your Leo location. Did I hear that correctly? And what drives the number of Class VI permits you need?
I’ll ask Nick to take that on as well.
Charles, it’s Nick. Thanks for the questions. And so, 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 6 months. And so 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 chart in terms of timing and kind of leads to a little bit of a longer-term process relative to what Denbury is doing.
But 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 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 Class VI 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, and that bypasses the need to potentially have to core and analyze that Class VI well after you have that permit to construct. And I’ll pause there to see if there’s any questions on that piece before I move to your second question.
No, that’s an excellent explanation. Please continue.
So when it comes to the Leo side and the 6 Class VI permits that Chris mentioned, what happens during the evaluation of a storage site is you have an area 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.
And so of course, what you want out of any given storage site is a lot of potential rate and a lot of storage availability. So when you see us put in multiple wells in a storage side, that means that we’re increasing the total rate that, that storage site can accommodate at this point in time, given the position we have.
So at this point in time, we have 6 wells here that you can think are going to generate somewhere between 500,000 tons per year to 2 million tons per year of injection rate. And so 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.
And I guess just fundamentally, Charles, you’re going to have a permit for a well. And so Nick’s talking about 6 wells, and so we have 6 permits.
And thank you for all that, Nick. That was a really helpful elaboration. And Chris, perhaps this follow-up might be maybe for you or Matt. You cited that the eventual rate for CCA would be, I think you said between 7.5 and 12,500 barrels a day. And I’m wondering if you can give us some indication on what are going to be the factors that determine where you wind up on that spectrum? And perhaps, given that I guess last quarterly call you talked about seeing CO2 early, and now we’re hearing that you’re actually going to get EOR volumes early. Does that bias you to one end of that spectrum or the other?
You bet, Charles. And I’m going to hand it over to David in a moment here to talk in a bit more detail about that. But bottom line, we’re excited about what we see. It’s also early days. And so there’s much to be determined, and you know how business works with some of these floods, and you really need to work the data as it comes in. And so with that, I’ll turn it over to David.
Yes. Good question, Charles. Thanks for asking that. So yes, we’re really excited about getting this first recycle facility commissioned, got that online, have introduced a few wells into that facility. I would say that this facility is in the heart of where we’ve seen some of that early CO2 arrival. And correspondingly, we’re seeing some indicators that’s going to help us to get to that point in the second quarter where we’re going to declare some EOR response within that particular recycle facility.
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 get to watch that and make the further assessment. Continuing on that path, we have 2 more recycle facilities coming into CHSU this year towards the back end of the third quarter, so it’s going to be later in the year. Once we bring those on, bring wells into those 2 independent systems, we’ll get to assess and see if our model, our expectation is on track.
Everything that we’ve seen so far tilts us to it is. It’s a solid plan right now, and every data point we’re acquiring confirms that. So real happy about that.
Those recycle facilities throughout time will be expanded. We’ll bring in additional compression. Now, as we move more CO2 through the system, that will expand our production capabilities throughout this area, ultimately targeting that 7,500 to 12,500 barrel a day window. There’s going to be some ebbs and flows in that throughout time as our development pace expands and goes a little faster or moderates throughout time. So that’s a general range to think about the long-term trajectory of how we’re going to produce this particular asset.
Yes. And 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. Well, I’m sure you guys are more eager for the data than I am. So I’ll look forward to hearing more of that on future calls.
We’re all eager for the data. That’s right.
We can take a question from Brian Velie from Capital One.
All my questions have been answered.
And there are no further questions on the line at this time.
This is Brad. Again, I just want to 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, and we look forward to connecting with you all. Thanks again.