Denbury Inc (DEN) 2022 Q4 法說會逐字稿

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. (Operator Instructions)

I would like to now turn the conference call over to your host, Brad Whitmarsh, Head of Investor Relations. Please proceed; sir.

Good morning, everyone, and thank you for joining us today. This morning, we provided 3 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 these 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 and Nik Wood, SVP of Carbon Solutions. Matt Dahan, SVP of Business Development and Technology, is also here to participate in the Q&A.

With that, I'll turn it over to Chris.

Thanks, Brad. Good morning, everyone, and thank you for joining us on today's call. Denbury is in amazing position as we entered 2023. U.S. policy support for CCUS has never been greater. And we are just scratching the surface of the scale we'll 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. 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 source CO2 in our operations, which increased to 4.3 million tons in 2022, helped the company once again achieved 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 source CO2 should be preferred as it is the lowest carbon intensity oil produced today.

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 by 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're preparing for our largest ever EOR development to start up in just a few months. We're investing in multiple high-return oil-focused projects across our portfolio. And we've 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.

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 entered 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 flow 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 and 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 our $510 million capital budget, $36 million of G&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 midterm 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 ultimately 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 has more than doubled 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 will be up 10% to 25% from last year and is really impacted by 2 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 in various markets will depend on the underlying indexes, 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's statutory rate of 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 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?

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 first 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 recordable 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 and the Beaver Creek EF reservoir development in the Rocky Mountain region.

At our Social field in Mississippi, where first EOR production began in 2007. We converted 13 wells in the mature portion of the Bailey CO2 flood to the Rodessa formation. Results have been outstanding as total production for 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'll be adding another phase of 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 EF reservoir as well as the realignment of the Big Sand Draw CO2 flood, we've increased production within these fields by over 70%, reaching a quarterly high in the fourth quarter of nearly 3,800 BOE per day. This was 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 the severe winter storms that impacted both our Rocky Mountain and Gulf Coast regions. The production impact for 4Q was around 1,250 BOE per day and nearly all of that was back on along 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 the 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 on 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 a 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 recycled 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 recycled 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 recycled 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 of capitalized preproduction CO2. The 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 compare to oil 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 on the 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 operating expenses, we anticipate unit cost 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 source CO2 we received under our contract with Air Products increased this year with the expiration of the legacy 45Q incentives at the end of 2022.

Secondly, as typical for new EOR floods, unit LOE at CCA will be temporarily higher during the initial stage of production. As CCA's 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 response at 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.

Thanks, David. Good morning, everyone. Today, I'm planning 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 6 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've 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 have signed to date.

In addition, we evaluated dozens of potential CO2 storage sites in 2022. And we executed agreements on 6 new sites last year. Our stored 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 core-based 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 3 Class VI permits the EPA for 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 2 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 2 new transportation agreements for a total of 2.5 million tons per year. The first agreement is with HIF to move CO2 to their e-fuels facility in Matagorda County, Texas. The second is with Monarch Energy to transfer CO2 to their sites in Freeport and Beaumont, Texas.

The second objective is to add multiple and new strategically located, dedicated storage sites to our portfolio. There are 3 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 capital for line loops or pump stations for that segment, while also increasing our reliability in 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 Street ship. 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 4 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 2 stratigraphic test wells in support of our Class VI permitting this year. And I'm pleased that our first well 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 and 2 carbon capture technology companies. Our investments in ION Clean Energy and Aqualung, one, an amine-based solution and the other a membrane-based technology will expand the service offering that we can bring to our customers.

These 2 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 takeaway solutions.

The CCUS team is highly energized and excited to achieve our goals in 2023. CCUS is a transformed growth opportunity for Denbury. And we will do everything in our capacity to deliver it to our shareholders.

Operator, we'd now like to open the call for questions.

(Operator Instructions) Please note that this call is being recorded. (Operator Instructions) Our first question comes from Leo Mariani.

I 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, do we expect some growth in the first quarter on production as some of the wells that came on late in '22 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?

Leo, 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 rounds 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 will be moderate changes throughout the year.

Okay. That's helpful. 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 and projects where you've had in the past? And if you had a similar situation, what has 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 confidence on your ability to hit those volume targets as you look out a couple of years, which obviously is significant growth there in CCA?

Sure. Leo, so I'll say a couple of things and I'm 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. 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 floods working and moving in the right direction.

And accordingly, we accelerated the recycled facilities. So we'd have those in place as close to the time as the arrival of the CO2 as we could. And it's right here right now. And 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.

Leo, yes, I mean, typically, we see every field just respond slightly differently. But great encouragement from CCA that, a, injectivity is one of the big drivers of value and we're very happy with what we've seen there.

And here we'll know very shortly once those compressors come on about kind of what early response looks like. But all signs indicate we're on track and ready to go.

Okay. And it sounds like those compressors are getting ready to start up in the next couple of months. Is that right?

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.

Our next question comes from Charles Meade.

Good morning, Chris and Matt and the rest of Denbury team. If I could just actually pick up where you left off with Leo and forgive me if some of these questions are kind of basic. But I think that most of us are on the call we don't have the depth of experience with these CO2 thoughts that obviously you guys do.

Is it the right effect to make that these higher injection rates and seeing the CO2, which you're producing more or sooner. Does that mean that the permeability is in the reservoir is higher than you modeled?

And look, what suggestions does that begin? 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.

Yes, Charles, this is Matt again. Yes, I mean you think about what we're flooding in CCA, CCUS itself is about 55,000 acres. So reservoir quality varies throughout the field, no doubt. And we got a pretty good handle on how much oil was in place and how much has 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'll see response a little bit quicker in some areas. Not uncommon to what we've seen across our portfolio over the last quarter or century doing this.

Got it, thank you. And then if I could ask a question on the CCUS side of the business. And this is really about the Class VI well permit. It seems to me that with all the success that you guys have had on both signing up storage sites and capture agreements, the connecting piece between those 2, 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 the bottleneck now? Or if it's not now, is it going to come that way soon?

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 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 1 Class VI permit out about every quarter. Those Class VI permits will be going both in Mississippi and Louisiana and hopefully, in Texas as we progress some site acquisitions as the year goes on.

And I 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 that 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 time.

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 will 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 is contemplating, capturing their missions and getting the tax credit, putting them into a 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 gives them the confidence to go forward.

Next up, we have a question from Sam Margolin.

The first one is on the reserve extension. I guess this is a little more 101 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 -- it doesn't seem like it's a price, if it's just based on CCA development time line or if there's something going on operationally that generates that?

Yes, Sam, this is Matt Dahan. 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.

I see. Okay. And then just a quick one on CCUS and the 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's feedback from emitters that they're 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?

Yes. 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 2 investments we may 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 tonne or better. And then Aqualung being a membrane-driven company, they're 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've been out chasing emitters and talking to them and some folks we've overlapped with and some we have it. So that expands our opportunity set there to be the off-track for that CO2. And then as we work with emitters and looking at what they've 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 really proven that they're on the low end of the capture cost.

Our next question comes from Nathan Pendleton.

Maybe for Nik, regarding your Class VI permits, can you speak to the event path going forward for your Orion development and potential timing given that there's 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 other milestones are, your team working towards to a cheap commercial injection?

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 bit of an 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 time line 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're hoping it's going to be about a year; maybe it will 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 would 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've 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 kind of deliver to ourselves and run our evaluation and make sure that some of our predictions match what we expected before, which we're highly confident in since we deal with a lot of these reservoirs frequently and have been for about 20 years.

So we know pretty well on how the injection, 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 6 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 and storage.

That's really helpful. And then regarding CCUS and 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 CCUS site? Based on the structure of legacy contracts, would you potentially inject CO2 from existing industrial sources? Or could you provide any color on some of the most promising sources you highlighted on Slide 20?

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, and 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 as in the Gulf Coast, but a lot of emissions there near us. A lot of those emissions 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. We've already signed a 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're looking very hard at and working with that group to bring those CO2 emissions into the system.

Yes. 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're not anywhere near the sites themselves and we're 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.

Next up, we have a question from Sam Burwell.

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 CCA; 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?

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, but we've seen inflation and some other impacts there that have lifted that number to some degree.

So we're really excited the CCA does come on. We're going to be able to make some decisions on investment paths in the future in our business. But that would be the general run that I would use thinking for that base maintenance CapEx.

Okay, great. That's very helpful. Following to the -- on the incremental offtake to get to the 30 MTPA by the end of this year. I understand you don't want to give specifics, since there's 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 the signs or something in between? Just how should we expect that to be achieved over the course of this year?

Thanks for the question. Yes, this is Nik can. So the way we plan on thinking about that is, right now, we're 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, 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 endgame here in 2023 as getting to that 30 million tons per year. We're very excited about the 2.5 million tons per year we've 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 signed with Clean Energy 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 in any of our hydraulics that go, through our pipeline. So we're happy to accommodate whoever goes first. And we don't really -- we don't really prioritize one versus the other, other than trying to accommodate everyone's schedule.

Yes. And Sam, this 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.

Next up, we have a question from Jeoffrey Lambujon.

Just a couple on the CCUS side to me. So the first one just on the CapEx outlook here over the near term. I guess, first, I was hoping you could break down the 2023 outlook there for CCUS specifically in some more detail.

Just maybe speaking how the different buckets are contributing this year. And then second, I 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 which you all spoke to.

And just as we think about those years being relatively heavier in comparison to the annual average, which I'll put out there back in December?

Thanks, Jeoffrey. This is Nik again. 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. And so that's another portion.

We will be drilling strat wells. There will 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 these stratigraphic well tests across our portfolio of storage sites. So that's another 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'll 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 continuing 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 storage sites are continually growing.

So those are the big items that go into the storage site of the business. I want to also point out that we will be spending a good amount of money on acquiring strategic right away. And that's really important because right now, we're getting to the point where we need to start making some big progress on putting in pipe to connect our emitters and our storage sites up to our system.

And we're happy to do that. And so what we're 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 buying 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'll see us buy pipe. And so that will be a big addition to the kind of $150 million you see this year, that's kind of the continuation and growth of last year.

We'll 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-'25 time frame and that will make them a bit heavier on the capital side.

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 inform plans for developing those sites?

Yes. So as we drill these strat wells, we will be learning about the shields 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 shields already. So we've been working in these areas for like we've missioned for 2 decades. And we know these shields, 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 will allow us to core the formations and analyze them to verify that that shield is containing. So that's point number one.

And then the next point is, -- understanding the injection rate that comes with each one of these wells in the storage 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 tests.

A lot of times, we know really well what our injection rates are going to be because we're injecting in hundreds of wells that are in the same type of formation across the Gulf Coast. So there's not -- we've kind of relearned.

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're actually getting higher injection rates than expected.

Next up, we have a question from Tim Rezvan.

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 million or is the goal to get from 20 to 30 million this year?

It's another aggregation, Tim. So it would be to get to 30 million in the aggregate.

Okay. Okay. I appreciate that. And then on the CCA EOR ramp, just so I'm clear, you talked about a potential 2,000 barrel 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 un-impacted by the CCA ramp?

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, think of it that we will actually be in our bandwidth of 7,500 barrels to 12,500 barrels near the end of 2024. So what the character 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 it together a model from your perspective from that 2000 to that, in that gateway of 7,500 to 12,500 barrels per year.

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 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.

And this conventional production I'm sorry, is that impacted at all?

Yeah, I was about to jump in and add on to that. We talked about the 500 barrels excuse me, that has been impacted in the fourth quarter. That will roll back into the system here as we turned on these recycled facilities.

Chris talked about the first one and it's going to come online within March here so just within a few weeks. So we expect a few of those barrels to roll back into the system. We haven't touched all of CHSU and all of Lob yet in our conversion process of that base water-flood production that will maintain and continue on.

And our last question comes from Clayton Lechleiter.

I appreciate it. Thanks for getting me on. I've got 2 here. First one, I 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 level 2 greenfields rather than brownfields that define the broader market opportunities. So I'm wondering if this is going to shift and if not, why not?

Thanks, Clay. This is Chris. So 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're hearing, I don't really see anything that makes me think that there will be a significant shift in how that would work compared to what we've seen before. But it is the U.S. government. And we'll just have to see what comes out there. We'll stay engaged and work within that.

Got it, I appreciate that. My second one is a follow-up to Sam's question. When you guys define maintenance capital at $225 million, 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.

Yes, you bet. And the way I think about that, Clay is that the -- it's -- 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 by thinking of new Greenfield type EOR projects as being growth capital. And that would come in outside of a typical type of maintenance run rate.

But then I'd expect it to feather into that maintenance capital over time. So if you look at where we are today, we've spent many years, I think, 9 or so years since we last brought a new flood on. And so we've had -- we've been working with existing fields that we have over that time.

Now we have a new field that we're 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 at 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.

And I would add one more comment to that. Just as our base production rate rises, as we see CCA performance come into the mix, then our base maintenance capital level will rise to keep that production level flat.

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

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.