Denbury Inc. (NYSE:DEN) Q4 2022 Earnings Call Transcript

Denbury Inc. (NYSE:DEN) Q4 2022 Earnings Call Transcript February 23, 2023

Operator: Good day, ladies and gentlemen, and welcome to Denbury’s 2022 Results and 2023 Outlook Webcast. My name is Tia and I will be your operator for today’s call. I would like to now turn the conference call over to your host, Brad Whitmarsh, Head of Investor Relations. Please proceed, sir.

Brad Whitmarsh: Good morning, everyone, and thank you for joining us today. This morning, we’ve provided three news releases covering our fourth quarter earnings, 2023 outlook and an exciting CCUS update, as well as a supplemental presentation for your consumption. All of these items are available on our website at denbury.com, and I hope you’ve had a chance to review them. I want to remind everyone that today’s event 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 filings and today’s news releases.

Also, please note that during the course of today’s event we may reference certain non-GAAP measures. Reconciliation and disclosure relative to those measures is provided in today’s earnings release and slide deck as well. This morning our prepared comments will come from Chris Kendall, President and CEO; Mark Allen, CFO; David Sheppard, COO; Nik Wood, SVP of Carbon Solutions. Matt Dahan, SVP of Business Development and Technology, is all here to participate in the Q&A. With that, I’ll turn the call over to Chris.

Chris Kendall: Thanks, Brad. Good morning, everyone, and thank you for joining us on today’s call. Denbury is in an amazing position as we enter 2023. U.S. policy support for CCUS has never been greater and we are just scratching the surface of the scale we will see in CCUS. The combination of the 45Q CCUS tax credit and significant improvements in carbon capture technology is opening the door for a vast portion of current and future U.S. emissions to be captured economically. It is also clear today that the world’s need for secure sources of energy of all types continues to grow. In the past several years of underinvestment in global oil production have begun to put stress on the industry’s ability to supply the world’s recovering oil demand, resulting in a stronger price environment than we’ve seen for many years, and an imbalance that I believe could exist for some time.

Considering that backdrop, Denbury could not be in a better place. Our unique carbon dioxide infrastructure and expertise put us in the center of the exciting, high-growth CCUS story and we are just in the first chapter. Our long lived CO2 EOR focused oil business is providing an ever greater proportion of carbon negative blue oil, and our multiyear path toward development of the massive Cedar Creek Anticline EOR resource will reach a key milestone with first EOR production this year, beginning the first of many decades of significant production of carbon negative, high-margin oil from this great asset. Our extensive use of industrial sourced CO2 in our operations, which increased to 4.3 million tons in 2022, help the company once again achieve net negative Scope 1 and 2 emissions for the year.

Denbury is uniquely situated to play an important part in meaningfully reducing carbon emissions, while also providing a valuable, essential, low-carbon intensity energy source. This is an incredibly exciting time for the company. We believe that CCUS will be a high growth industry and a high growth business for Denbury. Underscoring that conviction, our results more than doubled our key CCUS goals for 2022, exceeding 20 million tons per year in cumulative transport and storage agreements and over 2 billion tons in force based agreements. We also believe that oil will be a vital part of the global energy mix for many decades and that Denbury’s blue oil produced through EOR using industrial sourced CO2 should be preferred as it is the lowest carbon intensity oil produced to date.

In 2022, we made investments in multiple attractive oil focused development projects and progressed our crown jewel CCA EOR project, which we expect to drive company production growth beginning this year as that flood ramps up, delivering 100% blue oil. In reaching these achievements, we have never lost sight of the business fundamentals. David will touch on this more. But keeping people safe remains our top priority. I’ve long said that, excellent safety performance is the foundation for excellent operations and our teams are proving this year-after-year. Our priorities for 2023 build on our 2022 successes. At CCA, we are preparing for our largest ever EOR development to start up in just a few months. We are investing in multiple high return oil-focused projects across our portfolio and we have more than doubled CCUS capital in line with our plans to rapidly grow that business.

I am more confident than ever that Denbury has the right strategy, the right people and the right assets to deliver transformational growth for our shareholders. I will now turn it over to Mark, who will go over our 2022 financial results and our 2023 outlook.

Mark Allen: Thank you, Chris, and good morning, everyone. Today, I’ll provide a brief overview of Denbury’s financial results for 2022, cover our capital allocation priorities as we enter 2023 and address a few guidance items. I will then hand the call over to David for an operations update and more information on our plans for next year. Our full year operating cash flow for 2022 was $521 million and $569 million before working capital changes. This cash flow was generated on an average realized oil price of around $94 per barrel before hedges and $75 per barrel after hedges. Cash flow before working capital changes significantly exceeded our combined oil and gas and CCUS capital expenditures, resulting in $136 million of free cash flow for the year.

$100 million of this free cash was returned to shareholders through the repurchase of about 3% of our outstanding shares at a purchase price below $62 per share. During 2022, we also allocated $34 million for plugging and abandonment costs, proactively addressing some of our more mature assets, and we invested $10 million on the CCUS front in the development of a greenfield blue ammonia project to be built near Donaldsonville, Louisiana. As we move into 2023, our capital allocation priorities are unchanged. First and foremost, the health of our balance sheet is our top priority, particularly as we move into periods of higher capital spend for CCUS activities. Last year, we increased the borrowing base of our credit facility to $750 million.

And at the end of 2022, we had only $29 million in bank debt. Financial liquidity at year end was a robust $711 million. So we are entering the current year in a very strong financial position. Based on our current 2023 projections, assuming a $75 per barrel oil price, expected cash flows are relatively balanced with our planned investments, which include a $510 million capital budget, $36 million of P&A activity and $17 million in CCUS equity investments. For sensitivity purposes, each $5 move in oil price results in approximately $45 million of additional cash flow. Secondly, we will maintain the strength of our base oil operations, targeting modest oil growth over the mid-term through investments in our CO2 flood at CCA and other high return oil weighted development projects.

Our investments in the CCA EOR project are focused on bringing Phase 1 of this new CO2 flood to production later this year and also be driving 2024 oil growth for Denbury. Thirdly, we intend to prioritize the growth capital needs for CCUS. As we laid out in our CCUS Business Outlook Event last year, we expect CCUS capital will continue to increase over the next several years, as we build out what we believe will be the industry’s leading CO2 transportation and sequestration network. Our 2023 CCUS capital budget is more than double from last year, and we foresee further expansion in 2024 and 2025, as we continue the planned build out of this amazing system. Finally, as cash flow is generated above and beyond our anticipated near-term needs, we will continue to focus on returning capital to our shareholders.

We do believe that securing some price certainty is prudent for our business, especially as we move into a period of higher capital spend for CCUS. For 2023, we have around 50% of our anticipated production covered by hedges. And in comparison to last year, our current year hedges are at higher prices and provide more upside exposure. For 2023, at an average oil price of $75 per barrel, we expect our hedges will benefit our cash flow by roughly $15 million, a nice change from last year. Next, I will cover a few items relative to our current year outlook. As you can find in our supplemental information, we have included a slide on guidance for capital production, oil price differentials and various costs. G&A is a cost that we currently expect to be up 10% to 25% from last year and is really impacted by two drivers.

One, a projected increase in headcount, particularly those supporting our CCUS long-term growth objectives; and two, the cumulative expense for long-term equity awards with 2023 being the third full year of expense, following emergence. We estimate that stock compensation expense will be between $22 million and $26 million in 2023, up from $16 million in 2022. On oil price differentials, we are guiding to a range of $0.50 to $1.50 below NYMEX. This is below the negative $0.10 differential we had in 2022. But going back a couple of years, we had differentials of minus $1.40 to $1.80 per barrel. The price we receive on various markets will depend on the underlying index, pricing formulas and market dynamics in the different locations. I would expect differentials to move around throughout the year, but the first couple of months of this year are likely on the wider side of our differential range with January coming in around $2 per barrel below NYMEX prices.

And on taxes, we expect our effective tax rate for 2023 to be Denbury statutory rate 25%, following our much lower effective tax rate in 2022 due to the offsetting valuation allowance release on certain of our deferred tax assets. I do expect very little cash tax this year, assuming an oil price of around $75 per barrel. As I turn it over to David, I want to emphasize that our strong financial position, gives us great confidence in our ability to execute our long-term strategy. David?

David Sheppard: Thanks, Mark, and good morning, everyone. My comments this morning will include 2022 safety performance, cover some highlights from last year’s capital program, provide an update on the CCA EOR project. And lastly, give some details on our 2023 outlook. I’m very proud of how our teams executed throughout 2022, and I am certainly excited for 2023 as we will start to see the fruit of our efforts including the milestone for CO2 production response at CCA. Safety and environmental stewardship will always be core to our operational success. For 2022, we achieved our second lowest combined company and contractor total reportable incident rate of 0.53, second only to the record low rate achieved in the previous year.

Earlier, Chris mentioned our overall net negative Scope 1 and 2 emissions for 2022, but it is also important to point out that we are highly focused on reducing our Scope 1 and Scope 2 emissions in absolute terms. While our full year emissions numbers are not yet finalized, through the end of the third quarter, we achieved a 2.5% reduction in our Scope 1 and 2 emissions compared to 2021. In our Wind River assets, we electively chose to shut down natural gas fired electricity generation and instead purchased low carbon intensity electricity from the grid, a great example of how innovative ideas helped drive this reduction. It was an extremely active year for us in 2022 as we drilled 19 new wells consisting of 12 producers and 7 injectors, the highest total in the last 4 years.

In addition, we operated on average 34 workover rigs through the year on both LOE and capital projects. As Mark referenced, we also executed over $34 million in ARO projects consisting of 144 P&A wells, temporarily abandoning 59 wells, along with 111 other projects including surface restorations and facility closures. A couple of the development projects that really stand out to me from our 2022 campaign are the SoSo Rodessa project in the Gulf Coast in the Beaver Creek E/F reservoir development in the Rocky Mountain region. At our Soso field in Mississippi where first EOR production began in 2007, we converted 13 wells in the mature portion of the Delhi CO2 flood to the Rodessa formation. Results have been outstanding as total production from the non-producers has climbed over 1,000 barrels per day, yielding a highly economic project within one of our most mature assets.

We expect response to continue and we will be adding another phase to this development in 2023. Our Wind River Basin assets in Wyoming have been another outstanding story for Denbury. You will recall that we closed the acquisition in early 2021 for around $20 million all-in. The assets were producing approximately 2,200 BOE per day at the time. And through our 2022 redevelopment activities in the Beaver Creek E/F reservoir as well as a realignment of the Big Sand Draw CO2 flood, we have increased production within these fields by over 70%, reaching a quarterly high in the fourth quarter of nearly 3,800 BOE per day. This is another example of the outstanding work taking place across the organization to identify new flood opportunities and create significant value from them.

As mentioned in our earnings release, fourth quarter production was slightly lower than planned, primarily due to severe winter storms that impacted both our Rocky Mountain and Gulf Coast regions. The production impact for 4Q was around 1,150 BOE per day, nearly all of that was back online by mid-January. As expected, fourth quarter oil and gas capital expenditures were our highest for the year at $121 million with the CCA EOR development representing more than 40% of our development capital spend in the quarter. Other key activities included a horizontal drilling program at Webster in the Gulf Coast and several wells in the CCA area focused on the Charles and Mission Canyon horizons. The Mission Canyon well came online near the end of the year with a balance of the other projects coming online in the first quarter of 2023.

The combined drilling program is estimated to produce around 900 BOE per day net annualized for 2023. I would now like to provide an update from the CCA EOR project, as we have had a full year of continuous CO2 injection into Phase 1. As a reminder, we started CO2 injection on February 1, 2022 and since then have injected a cumulative 1.45 million metric tons of CO2. We have been pleased to see CO2 well injection rates higher than we anticipated, which is generally positive sign for flood performance. As the injected CO2 has moved through the reservoir, we have observed CO2 arrival on the early end of our expectations in several producing wells, leading us to temporarily curtail production from those wells into slow CO2 injection rates in the surrounding areas, while progressing completion of the recycle facilities.

Curtailed volumes in the fourth quarter were around 500 BOE per day, and we anticipate these volumes to increase slightly in the first quarter of 2023. We expect to bring that production back online throughout the year, as we start up recycle facilities. The first of those facilities is expected to be operational later in the first quarter, with 3 additional facilities coming online throughout the year. We still expect Phase 1 initial EOR oil response in the second half of the year with production response ramping up over time as we bring additional recycle facilities online. While the exact timing of the production ramp will be calibrated by actual performance data as the flood progresses, our latest estimates have us around 750 BOE per day incremental EOR production response for the year, exiting the year near 2,000 BOE per day and reaching our expected 7,500 to 12,500 BOE per day range by late 2024.

Considering the CO2 injection performance, and early arrival indicators we have seen so far, we remain very confident in the resource and outlook for this multi-decade opportunity set at CCA. As Mark mentioned, detailed guidance for various 2023 metrics can be found in our earnings supplement. With respect to capital, we set the midpoint of our 2023 oil and gas capital expenditures at $360 million, consistent with our 2022 spending. Roughly 40% of this amount was planned for CCA EOR, including $15 million for capitalized pre-production CO2. Remaining capital for CCA will mainly be focused on installing recycle facilities I mentioned earlier, accelerating planned compression capacity expansion at these facilities, progressing additional well work to prepare all producers for CO2 response, along with installing additional infield flow lines.

Our non-CCA EOR oil and gas development activities include projects across both of our operating regions focused on new development at Beaver Creek and Eucutta as well as convinced from development in our CCA, Conroe and Webster fields. Production volumes for 2023 are expected to range between 46,000 to 49,000 barrels of oil equivalent per day. The midpoint of this range is up from our 2022 actuals, mostly due to the expected CCA EOR impact in the second half of the year. I expect we will see some minor fluctuations in our production profile for 2023 with the first quarter benefiting from some of our 2022 activities, and the fourth quarter seeing uplift from CCA. This should set us on a good path to have 2024 production ramping to over 50,000 barrels of oil equivalent per day.

Lastly, on to operating expenses, we anticipate unit costs to be slightly higher than the average rate in 2022, expected to range between $29 and $31 per BOE. The drivers of the increase are: first, the purchase price of the industrial sourced CO2 we receive under our contract with Air Products increase this year with the exploration of the legacy 45Q incentives at the end of 2022. Secondly, as typical for new EOR plugs, unit LOE at CCA will be temporarily higher during the initial stage of production. As CCAs production response ramps up materially throughout 2024, I expect that CCA will ultimately become a strong driver to reduce our overall corporate LOE per BOE. Wrapping up, I just want to comment on how pleased I am with where our business is headed, especially considering the industry challenges that we navigated through in the past year.

2023 will be a transformational year for our oil and gas business as we commence EOR production on responsive CCA. We are certainly strengthening the foundation of our company. I’ll now hand it off to Nik for an update on our carbon solutions business.

Nik Wood: Thanks, David. Good morning, everyone. Today I’m going to provide an outlook for our 2023 plans. But first, I want to take a quick look back at a very successful 2022. We announced six new CO2 transportation and storage agreements last year, bringing our cumulative CO2 offtake agreement volume to more than 20 million metric tons per year. We mentioned it before. But when you think about 20 million metric tons per year, that volume represents about half what is captured worldwide today. And clearly, we have plans to increase the size of our business to a scale much larger than what we assigned to date. In addition, we evaluated dozens of potential CO2 storage sites in 2022. And we executed agreements on six new sites last year.

Our storage portfolio at the end of the year included sites in Alabama, Mississippi, Louisiana and Texas, totaling more than 2 billion metric tons of CO2 storage potential. The relationships we are building with our emissions customers and pore space owners form the foundation of what we expect to be long-term mutually beneficial partnerships. To complete these agreements requires extensive collaboration throughout Denbury. This includes support from land, legal, government relations, regulatory, commercial development, engineering and accounting. Near the end of the year, we submitted our first three Class VI permits to EPA for our Alabama site. These permits were deemed technically complete by the EPA in January, and we expect to receive our first Class VI well permit approval within two years.

The permit included over 350 pages of technical evaluations, construction plans and risk mitigation procedures. Our experience with these first permits will accelerate submission of future Class VI permit applications. Building on our momentum from 2022, next, I’ll cover our outlook for 2023. This morning, we announced our 2023 capital budget of between $140 million and $160 million, which at the midpoint represents an $85 million increase compared to last year. The largest item in our budget is allocated to the acquisition of additional strategically located CO2 storage sites. The budget also includes stratigraphic test wells, acquiring important right of way and purchasing long lead time items. This morning, we also communicated our 2023 goals, which are highly aligned with the long-term objectives that we communicated in our CCUS Business Outlook last December.

Our first objective is to sign agreements with the industrial customers to reach a total of 30 million metric tons per year. Based on our extensive number of ongoing negotiations with both brownfield and greenfield customers, I’m encouraged with the opportunity to accomplish and once again hopefully exceed this year’s goal. As you may have seen in this morning’s announcement, we have signed two new transportation agreements for a total of 2.5 million tons per year. The first agreement is with HIF to move CO2 to their eFuels facility in Matagorda County, Texas. The second is with Monarch Energy to transport CO2 to their sites in Freeport and Beaumont, Texas. The second objective is to add multiple new strategically located, dedicated storage sites to our portfolio.

There are three distinct factors that make a storage site strategic for Denbury. First, some sites will improve our pipeline capacity because their placement serves as an offering for CO2 and pipeline segments that are approaching their current capacity. This will reduce the need for additional capitals for line loops or pump stations for that segment, while also increasing our reliability and total storage volume. Secondly, some sites will shorten the distance from emissions customers to our network. These sites will serve as stepping stones for the continual extension of our network. And finally, we will be securing sites in new markets outside the Gulf Coast. A good example is the storage site we announced this morning in the Rockies region.

This is our first Rocky Mountain dedicated storage site. It is located directly underneath our Greencore pipeline in Northeast Wyoming. You will see us steadily add strategically located storage sites over the year, progressing our plans to offer the most reliable and capital efficient CCUS network available. Our third key objective this year is to progress our EPA Class VI permitting with new applications and drilling test wells. We have set the goal for this year to submit permits on four additional storage sites. I expect we will have several permits submitted to the EPA before the midpoint of the year. We will also drill at least two stratigraphic test wells in support our Class VI permitting this year. And I’m pleased that our first whale is currently drilling on our Orion site in Alabama.

Our fourth goal is to continue to progress strategic partnerships. Today, we announced that we have made minor equity investments in two carbon capture technology companies. Our investments in ION Clean Energy and Aqualung, one an aiming based solution, and the other a membrane based technology, will expand the service offering that we can bring to our customers. These two companies are on the leading edge of reducing the cost of capture for a whole host of types and sizes of emissions. We look forward to working with both companies and providing our customers with the most economic and reliable CO2 take away solutions. The CCUS team is highly energized and excited to achieve our goals in 2023. CCUS is a transformative growth opportunity for Denbury, and we will do everything in our capacity to deliver it to our shareholders.

Operator, you now let’s open the call for questions.

Q&A Session

Operator: Our first question comes from Leo Mariani. Please unmute yourself to ask a question.

Leo Mariani: Wanted to just follow-up a little bit on the cadence of production in 2023. I think you sort of alluded to this a little bit in some of the prepared comments. But if I heard it right, that we expect, some growth in the first quarter on production as some of the wells that came on late in 2018 start to contribute. And it sounds like production might start falling a little bit in 2Q and 3Q of ’23 before it goes up in 4Q as a result of the production response from CCA. Is that generally right in terms of what I heard?

Chris Kendall: Hey, Leo, good morning. This is Chris. Absolutely. The way we think about it, you have an impact from the program that David talked about that will have somewhat of an impact on the early part of this year. And then the real driver is hitting the end of the year. And that ramp that we’ll see in CCA when we see that flood coming. So we expect most of that late in the year. And that’s kind of how it shapes up. But I’d say leading up to that it’ll be moderate changes throughout the year.

Leo Mariani: And then just wanted to follow-up on CCA. You guys talked in your prepared comments about getting some early CO2 breakthrough which you guys thought was an encouraging sign. Could you maybe kind of speak to maybe other analogs of the projects where you’ve had in the past? And if you’ve had a similar situation, what does that typically led to? Does that show that you guys are getting really good sort of miscibility of the CO2 and does that increase your competence on your ability to hit those volume targets, as you look out a couple of years, which obviously is significant growth there in CCA?

Chris Kendall: Sure, Leo. So I’ll say a couple of things and I am going to ask Matt to weigh in a bit more on what we’ve seen historically. But, I kind of think back on when we first started injection in this field in February of last year. And as you’ll recall, one of the first things we talked about was that the injection was going much better than we had expected. The flip side of that is that you’d see movement through the reservoir faster than we expected. And that’s a good thing. That’s on the high end of our expectations. It means the flood is working and moving in the right direction. And accordingly, we accelerated the recycle facilities, so we’d have those in place as close to the time as the arrival of CO2 as we could. And it’s right here right now. So that’s kind of how I see it. But I’ll ask Matt to weigh in on other thoughts that he’d add to your question.

Matt Dahan: Yes. Good morning, Leo. Yes, I mean, typically, we see every field just respond slightly differently. But great encouragement from CCA that, A, an injectivity is one of the big drivers of value. And we are very happy with what we are seeing there. And here we will know very shortly once those compressors come on about kind of what early response looks like. But all signs indicate we are on-track and ready to go.

Leo Mariani: Okay. It sounds like those compressors are getting ready to start up in the next couple of months. Is that right?

Matt Dahan: That’s right. We have the first of those this quarter. I think actually less than a month from today, we should have that operational, if all goes well.

Operator: Our next question comes from Charles Meade. Please unmute yourself to ask your question.

Charles Meade: Good morning, Chris and Matt, and the rest of Denbury team. I wondered if I could just actually pick up where you left off with blue oil. And forgive me if some of these questions are kind of basic. But I think that most of us on the call wouldn’t have the depth of experience with these CO2 jobs that obviously you guys do. Is it a right difference to make that these higher injection rates and seeing the CO2 which you are producing there sooner? Does that mean that the permeability is in the reservoir is higher than you modeled? And what suggestions does that beget? Does that mean that, possibly more oil was produced under primary recovery? Or does that mean that your CO2 is going to be more effective? Just tell me what kind of possibilities that opens up?

Matt Dahan: Yes. Charles, this is Matt again. I mean, you think about what we are flooding in CCA. CHSU itself is about 55,000 acres. So reservoir quality varies throughout the field, no doubt. We got a pretty good handle on how much oil was in place and how has much been produced. So that’s really not an issue. It’s just a little bit of variability across the field. Some wells take more injection than others and we will see response a little bit quicker in some areas. Not uncommon to what we have seen across our portfolio over the last two and a quarter century of what we are doing this.

Charles Meade: Got it. Thank you. And then if I can ask a question on the CCUS side of the business. And this is really about the Class VI well permitting. Can you — it seems to me that, with all the success that you guys have had on both signing up your storage sites and capture agreements, the connecting fees between those two, the injection permits really has moved more to center stage. And so I’m curious, is that the way it looks to you guys. And is the Class VI permitting process, is that on the critical path? Or is that is that the bottleneck now? Or if it’s not now, is it going to become that very soon?

Nik Wood: Charles, this is Nik. Thanks for the question. I think it’s an important topic to discuss on where the critical path lies. I want to first say that the Class VI progress is going great for Denbury right now. As you know, we’ve submitted our first Class VI well permit there at the end of 2022. And we are processing Class VI permits on all the storage sites that we’ve acquired so far, and the process is going great. What you can kind of think about is that as we went through the first permitting process, we’ve learned a lot. And so as the next permits come through, we’ll be going faster and faster. And as we progress through the year, I would say you can expect us to get a Class VI — at least one Class VI permit out about every quarter.

Those Class VI permits would be going both in Mississippi and Louisiana, and hopefully in Texas, as we progress some site acquisitions as the year goes on. And I’d still say we are on track for having Class VI storage very much available in multiple places in 2025. And so therefore, I don’t think that this necessarily will be the critical path for the whole CCUS value chain. I think that there’s going to be more time necessary for some other components to have to get executed on the capture side. So I think we’re going to be ready and willing to take the CO2 from our capture partners when it’s done.

Chris Kendall: And Charles, just this is Chris, just one thing I’d add to what Nik shared is, what we love about what Denbury is able to provide is not just this extensive portfolio of Class VI storage that he’s working towards right now that it’ll be incredible when those permits are approved, and we add those to that network. But what you have today is this fallback with a significant capacity within our EOR fields on the Gulf Coast to take CO2. And so our thinking is what we really want any industry who’s contemplating capturing their emissions and getting the tax credit, putting them into storage, is that we have a fallback that can release them to move forward with their project without the risk of waiting for a period on Class VI storage. So we think we have something pretty special that will have the Class VI storage out there, but a fallback that’s very much ready today as we speak, that it gives them the confidence to go forward.

Operator: Next up, we have a question from Sam Margolin. Please unmute yourself and ask your question.

Sam Margolin: Thanks a lot for taking the question. The first one is on the reserve extension. I guess this is a little more one-on-one on EOR for people more familiar with unconventional in the Lower 48. But you did report a reserve extension in upstream. And I was just wondering if you could talk about the mechanics of how that works and how it’s differentiated from I guess a normal E&P if it’s not – doesn’t seem like it’s an outcome of price. If it’s just based on CCA development timeline or if there’s something going on operationally that generates that?

Matt Dahan: Yes, Sam, this is Matt Daha. Yes, reserves increase certainly very pleasing what we saw this year. A lot of that driven by price, but we had some adds and revisions, David mentioned the strong performance at our Wind River assets, in particular, Beaver Creek. So we had some additions there, along with performance in the Gulf Coast and those redevelopment projects. The price was a significant driver in our reserve increase.

Sam Margolin: I see. Okay. Thank you. And then just a quick one on CCUS and equity investments you made on the capture technology players. I’m wondering if that’s a proactive effort to maybe capture more of a fee pool opportunistically or if there is feedback from emitters that they are looking for more of a full value chain solution, and it’s in the best interest of driving the volume target to take on that position. Thank you.

Matt Dahan: I mean, as always — this is Matt again, Sam, always a part of our plan to work the entire value chain of CCUS. When we look — we did a deep dive into the different technologies that were available, who’s the big players in each of them. They do — the two investments we made do service different parts of this business. So ION really, on the larger side, particularly on post combustion capture. These are bigger 0.5 million to 1 million ton or better. And Aqualung being a membrane driven company, they are really focused on stuff below the 0.5 million mark even as low as in the tens of thousands. So they do capture different targets. But what they do add to us is a couple of things. One, they have been out, chasing emitters and talking to them and some folks we have overlapped with and some we haven’t.

So that expands our opportunity set there, to be the off taker of that CO2. And then as we work with emitters and looking what they have done by themselves to progress capture. In some instances, we can point them in a direction that is perhaps going to save them some money both on the CapEx and OpEx side, as these technologies have really proven that they are on the low end of the capture cost.

Operator: Our next question comes from Nathan Pendleton. Please unmute yourself and ask your question.

Nathaniel Pendelton: Good morning. Thanks for taking my question. Maybe for Nik regarding your Class VI permit, can you speak to the event path going forward for your Orion development and potential timing given that there is only one other operator with a completed permit in the EPA region for that we can see at least? Also beyond receiving the initial permit, what are the milestones that your team working towards to achieve commercial injection?

Nik Wood: Sure. Thanks for the question, Nathan. So the steps that we go through to get any general permit, I’ll quickly go through and then kind of emphasize the next steps there on Orion. So we spend months preparing the permit to build the geo models and doing the simulation reservoir work and doing a lot of evaluation of the particular site, characterizing the site, defining emergency procedures and things of that nature. And then once we submit the permit, we have a bid or pay iterative process with the EPA, where they will ask us a few questions, and then that leads to a milestone called kind of the verdict of completeness. And so when we get done with the completeness, the EPA then goes back to really dig into all the details of the site and we will receive questions back and forth from the EPA from this point forward.

We expect the timeline from now until we receive the permit to construct the Class VI well, which will be the next milestone, to be about a year. We are hoping it’s going to be about a year, maybe it’ll be a little faster. But from that back and forth, we will receive this Class VI permit to construct. And at that point, we will drill our first Class VI well. That drilling procedure should take about a month. Once we drill the well, because we already have the core and because we already have a lot of seismic that we have been able to purchase on the site, we’ll be able to move relatively quickly. We will drill the well and do some injection testing for the EPA that we will deliver back to them and also can deliver to ourselves and run our evaluation and make sure that some of our predictions match what we expected before which we are highly confident in since we deal with a lot of these reservoirs frequently and have them for about 20 years.

So we know pretty well on how the injection will go, and how some of those tests will turn out. But from that point, we will receive the Class VI permit to inject. We expect that to take anywhere from six months to a year from the time that we receive the Class VI permit to construct. Once we have the Class VI permit to inject, we of course will have the ability to start moving CO2 into our storage intervals. All of that time, in parallel, we will be building our commercial business. So we will be building up the volumes not just with the Orion site, but for all the sites that we have in our portfolio, which will mean effectively coming to milestones around definitive agreements for having offtake for CO2 for transportation storage.

Nathaniel Pendelton: And then regarding CCUS in the Rockies, can you speak to how you view the supply of anthropogenic CO2 compared to the demand for both your EOR developments and now your new CCS site? Based on the structure of legacy contracts, would you potentially inject CO2 from existing industrial sources? Or can you provide any color on some of the most promising sources you highlighted on Slide 20?

Nik Wood: Oh, yes, so we’re very excited about our new site underneath our Greencore pipeline there in the North region. It gives us a very economic dedicated storage site there in the Rockies to really utilize that 400 miles of CO2 pipeline, we already have in the ground there as well. We have a lot of emissions around that 400 miles of pipe like we have probably not quite as much as in the Gulf Coast but a lot of missions there near us. A lot of those missions are coal fired power generation, that are diligently working to get their economics to capture that CO2 to economically work underneath the current 45Q. We are — this site should be very helpful to making those economics a reality because it should be one of the most economic available sites to put CO2 in the ground in the Rocky region, if not the most economically viable dedicated storage site in the region.

So we’re very happy to be able to provide that. We also see a big market in the soda ash industry. We’re exploring opportunities with that with the company right now. So there’s a whole new kind of market that really we don’t see a whole lot of in the Gulf Coast, they’re opening up in the Rocky Mountain region. There’s also emissions associated with a lot of gas processing in the area. That type of CO2 emission capture source is probably economic right now. And so we will be working with those companies very soon to work out how we might be able to bring those emissions into our system. And then one final point there is, there’s a lot of greenfield development in the Rockies. There’s — we’ve already signed the term sheet with a hydrogen production project there in the Rocky Mountain region that we’re excited to bring into our system.

But there’s also a new hydrogen hub that is expected to go in South Central Wyoming that we are looking very hard at and working with that group to bring the CO2 emissions into the system.

Chris Kendall: And Nathan, this is Chris. Just one thing I’d add to that description that Nik shared. It’s just the unique advantage that we have with this pipeline network both in the Rockies and in the Gulf Coast. The expansiveness of those systems allows us to put sequestration sites very close to the pipe. Anyone who comes into our system can touch those sites even if they are not anywhere near the sites themselves and we are doing that over and over again. And I just think it’s a great advantage that we have as a system and you’re seeing just an example through what Nik was describing right there.

Operator: Next up, we have a question from Sam Burwell. Please ask your question, Sam.

Sam Burwell: Hey, guys. I wanted to ask a question about like what’s your latest estimate of maintenance CapEx in the EOR business? I mean, the 2023 budget if you back out the $145 million for CCUA, you get to $215 million. Is that the right number to think about? I mean, does that change once CCA is online? And if — like, maintenance CapEx isn’t the right way to think about it. I just want to better frame how we should model EOR CapEx going forward as the CapEx on CCUS ramps up?

David Sheppard: This is David. I’ll take that question. Yes, maintenance CapEx, we generally think about it around, I’d say, $225 million give or take for our base business right now. We have been, I guess, saying around $200 million historically. We have seen inflation and some other impacts there that have lifted that number to some degree. So, we are really excited that CCA, it does come on, we are going to be able to make some decisions on investment paths in the future in our business. But that would be the general kind of run that I would use, thinking for that base maintenance capital.

Sam Burwell: Okay. Great. That very helpful. Follow would be on the incremental off take to get to the 30 MTPA by the end of this year. Understand, you don’t want to give specifics and there is only so much you know at this time. But, could you give us your best guess as to, like, how that ultimately gets achieved? Is it a few fairly large projects, maybe not the size of ace, but multi MTPA projects or a lot of small ball, like, fairly small projects, but you can really get a lot of those signs or something in between? Just how should we expect that to be achieved over the course of this year?

Nik Wood: Hi. Thanks for the question. Yes. This is Nik again. So the way we plan on thinking about that is, right now we are engaged with well over 50 different emission sources, approaching more towards the 100 emission sources, both greenfield and brownfield projects, and they are all moving at different paces. And sometimes they — sometimes one accelerates a lot faster than the other, so we don’t know exactly which one will come on next. But we definitely see the end game here in 2023 as getting to that 30 million tons per year. We are very excited about the 2.5 million tons per year we have already signed. We are engaged with many projects that are in the same realm of the type of scale that you see there. But we also have some very large projects that compete kind of with the size of the project you indicated before that we have signed with Clean Hydrogen Works.

And so it may go either way and it may be both greenfield and brownfield projects that come into the system. In any case, we’re happy to accommodate any of those projects. We think our system is flexible enough to handle any type of scale that would — that may come in at any given point. We’re able to accommodate that different varying scale with any of our storage and any of our hydraulics that go through our pipeline. So we’re happy to accommodate whoever goes first. And we don’t really prioritize one versus the other, other than trying to accommodate everyone’s schedule.

Chris Kendall: And Sam, that is, Chris. I just think, based on what Nik said, just the opportunity set both on the brownfield and greenfield side that we see is enormous. The amount of emissions that are out there right now is enormous and the greenfield projects that are incentivized through energy transition policy, also enormous. It’s just a really big opportunity set.

Operator: Next up, we have a question from Jeoffrey Lambujon.

Jeoffrey Lambujon: Just a couple on the CCUS side for me. So the first one is just on the CapEx outlook here over the near-term. I guess first was hoping we could break down the 2023 outlook there for CCUS specifically in some more detail, just maybe speaking out the different buckets are contributing this year. And then second, wanted to focus on the magnitude of 2024 and 2025, as you all see things today, just with all the processes that are ongoing in the background as you all spoke to and just as we think about those years being relatively heavier in comparison to the annual average, which you all put out there, back in December?

Nik Wood: Jeoffrey, this is Nik, again. Sure. The breakdown of the capital this year, where we’re looking at the $150 million of CapEx on CCUS is mostly focused on storage sites, and I’ll say mostly focused on the acquisition of storage sites. So we’ll continually add to our strategic located portfolio, dedicated storage. And that usually includes an upfront bonus that goes into play. And that’s the large portion of our $150 million. But within that, you can also think about all the previously acquired storage sites that we have as having kind of a pre-injection payment, or maybe you can think of it as a rental that will be ongoing. So as we continue to acquire these sites, we have these rental payments that come into play, that’s also associated to dedicated storage, so we can keep that option to develop any one of these sites over time.

So that’s another portion. We will be drilling strat wells, there’ll be a varying amount of strat wells that we may or may not drill, depending upon what we think we need to drill based on the evaluations that are ongoing on our Class VI permitting process. So we could spend a good amount of money drilling the stratigraphic well tests across our portfolio of storage sites. So that’s another big a big bucket. We also have a bit of land work that’s ongoing to continue to acquire additional acreage on storage sites we’ve already acquired. So when we announce these storage sites we usually give an acreage position that’s associated to the amount of total storage associated with that site. As you can imagine, there’s a lot more storage sites we had in the offset acreage to that particular storage site.

So what we do is we continually acquire additional small leases that are connecting up to that site and continue to add to the total storage available for that site. We don’t necessarily announce every time we continue to add those smaller portions, but just know in the background that these store sites are continually growing. So those are the big items that go into the storage side of the business. I want to also point out that we will be spending a good amount of money on acquiring strategic right of way. And that’s really important because, right now, we are getting to the point where we need to start some big progress on putting in pipe to connect our emitters and our storage sites up to our system. And we are happy to do that. And so what we are doing right now is, going out and doing the due diligence on who owns right of way that will attach our 900 miles of pipe to those storage sites in those emitters and bind that.

And so once we have that acquired, we will be buying the pipe and installing it. And so this year, we will have a lot of that right of way purchase. But as we move into the ’24 and ’25 time period, you will see us buying high. And so that will be a big addition to the kind of $150 million you see this year, that’s kind of the continuation in growth of last year. We will have this additional amount of capital necessary to buy the materials that are necessary for us to build this business. And so the building and installation of that pipe will come into play in the ’24 or ’25 timeframe, and that will make them a bit heavier on the capital side.

Jeoffrey Lambujon: Understood. That’s really helpful. And then maybe just a quicker follow-up here thinking about some of the operations that will take place on those storage sites over the next couple of months thinking about the strat wells that are planned for the year. Can you just speak to expected learnings as you make progress on those and how that will form plans for developing those sites?

Nik Wood: Yes. So as we drill these strat wells, we will be learning about the seals and the permeability and the reservoir characteristics of our storage site. That will inform a few things. One, it will add to our confidence that we have on the seals already. So we have been working in these areas for, like we have mentioned, for two decades. And we know these seals, we know these shield barriers, we know these formations really, really well. But what we want is to absolutely verify them. So these test wells will allow us to do that. It’ll allow us to core the formations and analyze them to verify that, that seal is containing. So that’s point note 1. And then the next point is, understanding of the injection rate that comes with each one of these wells in the store sites.

That will allow us to plan for the right amount of wells in the future. So as we sign our emissions, we will always be staggering out our well development for each storage site, based on the information we gained from the stratigraphic well test. A lot of times, we know really well, what our injection rates are going to be because we are injecting in hundreds of wells that are in the same type formation across the Gulf Coast. So there is not — we have kind of really learned. But we do expect to potentially get surprises. And if we do, we will accommodate those surprises with additional wells, if necessary or maybe less wells, if we find out that we are actually getting higher injection rates than expected.

Operator: Next up, we have a question from Tim Rezvan.

Tim Rezvan: Hi. Good afternoon, everybody. I think we’re on the hour. I’ll keep it quick. First question was a clarification. You talked about that 30 million tons per annum target. Is that an incremental 30 or is the goal to get from 20 to 30 this year? A – Nik Wood It’s another aggregation, Tim. So it would be to get to 30 in the aggregate.

Tim Rezvan: Okay. Okay. I appreciate that. And then on this CCA EOR ramp, just so I’m clear, we talked about a potential 2,000 barrels a day exit rate in 2023. And if I heard you correctly, you said you thought you could hit peak production at the end of 2024. So is that a kind of, I know each flood is its own entity. Do you expect a linear ramp? And then or are there certain kind of milestones with compression or other things? And then how do we think about the existing production there? Would that be unimpacted by the CCA ramp?

David Sheppard: Hey, Tim, this is David, I’ll take that question. Yes, we do — at CCA expect to be at an exit rate of around 2,000 barrels a day, at the end of the year. And as we go throughout 2024, thinking that we will actually be in our bandwidth of 7,500 barrels to 12,500 barrels near the end of 2024. So, what the characteristics of that ramp is going to look like, just be real candid, as we see response from producing wells, we’re going to make decisions to focus CO2 injection in certain areas and pull levers, if you will, to optimize the flood. So, it’s going to have some choppy character. It will not be a perfectly linear ramp, but I do think you’re going to see a general overall uplift. If I’m putting together a model, from your perspective, from that 2,000 to that — in that gateway of 7,500 to 12,500 barrels per year.

Chris Kendall: Yes. And, Tim, this is Chris. And the only thing I’d add to what David shared is that that’s not necessarily the peak. It’s that range that’s — that we’ve targeted, but we’re going to keep working it. And as David said, depending on the performance that we see, and how we can do with the CO2 that we’re injecting there, we could do even better over time, depending on how that all goes.

Jeoffrey Lambujon: And has conventional production, I’m sorry, is that impacted at all?

David Sheppard: Yes, I was about to jump in and add on to that. We talked about the 400 barrels — or 500 barrels, excuse me. That has been impacted in the fourth quarter. That will roll back in to the system here, as we turn on these recycled facilities. Chris talked about the first ones going to come online within a March here, so just within a few weeks, as we expect a few of those barrels to roll back in into the system. We haven’t touched all of CHSU and all of the lab yet in our conversion process of that base waterflood production, now we will maintain it and continue on.

Operator: And our last question comes from .

Unidentified Analyst : Thanks for getting me on. I’ve got two here. First one, just want to get your updated thoughts on your expectations for the expected IRS guidance on 45Q? I think that’s later this spring. Because as it stands, your offtake agreements are left over to greenfields, rather than brownfields that defined the broader market opportunities. So I’m wondering if this is going to shift? And if not, why not?

Chris Kendall: This is Chris. So I, we’re interested in seeing what the IRS guidance looks like as well. We have a couple of good markers out there. First is the IRS guidance around the original 45Q program that came out in 2020. And, what I see so far everything that we are hearing, I don’t really see anything that makes me think that there would be a significant shift in how that would work, compared to what we have seen before. But it is the U.S. Government and we will just have to see what comes out there. We will stay engaged and work within that.

Unidentified Analyst: Got it. I appreciate that. My second one is a follow-up to Sam’s question. When you guys define maintenance capital of 225, I’m wondering if that includes CCA and does it in fact hold production flat? And I asked the question, because spending has been around this level, yet production has been trending lower.

Chris Kendall: Yes, you bet. And the way I think about that, Clay, is that, the — we look at maintenance capital over a number of years and if you take any particular year, it may be higher or lower just depending on what led up to that year. With CCA, of course, we start my thinking of new greenfield type EOR projects as being gross capital. And that would come in outside of a typical type of maintenance run rate. But then, I’d expect it to feather in to that maintenance capital over time. So if you look at where we are today, we have spent many years, I think nine or so years since we last brought a new flood on. And so we have been working with existing fields that we have over that time. Now we have a new field that we are going to be working and a whole new set of opportunities kind of along the lines of what David mentioned with those Wind River assets and what we can do with those.

I still think it works that way. It’s just looking out in any particular year is going to be a little different, just depending on what led up to the year and the specifics of what we did during that year.

David Sheppard: And I’ll just other short comment to that, just as our base production rate rises, as CCA performance come into the mix and our base that maintenance capital level will rise to keep that production level flat.

Operator: There are no further questions at this time. I will now hand over to Brad Whitmarsh for closing remarks.

Brad Whitmarsh: Sure. Thanks. I want to thank everybody for joining us today on this webcast. Should you have any follow-up over the coming days, please don’t hesitate to reach out to Beth and I. Thanks again for joining us.