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Denbury Resources (NYSE:DEN)
Q4 2020 Earnings Call
Feb 25, 2021, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Greetings, and welcome to the Denbury Resources fourth-quarter 2020 results conference call. [Operator instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, John Mayer, director of investor relations. Thank you, sir.

You may begin.

Chris Kendall -- Director of Investor Relations

Good morning and thank you for joining us on today's call. Well, we are focused on 2021 and the great opportunities that lie ahead. I've spent some time reflecting on 2020 and the massive worldwide disruption caused by the pandemic, including the impact on our employees. As we conduct this call, it has been nearly a year since the onset of the pandemic.

And I'm incredibly proud of the dedication and resilience of our employees as they faced and conquered the challenges of 2020, all the while being concerned about the health and safety of their loved ones. Most of our corporate office staff has been working from home since the beginning of the pandemic, adapting to the challenges of interacting and collaborating in a different and unexpected manner with business results demonstrating, we did not miss a beat. Our field personnel have continued performing their daily jobs that are vital to the nation's energy supply in a safe and efficient manner. And our employees and contractors were safer than ever as we set another record low incident rate in 2020.

Through disciplined good health practices, COVID has had a relatively low impact on our workforce with very few severe cases. And I'm deeply grateful that no employees have been lost to the disease. Even as vaccinations are rapidly rolling out across the country, we all understand that we must remain diligent and disciplined. However, I'm increasingly confident that the worst of this is behind us.

2021 is going to be a great year for Denbury, but the challenges faced in 2020 and the incredible demonstration of resilience from our employees managing through and conquering those challenges is worth recognizing and reflecting on as we move forward. Again, I thank our employees for their dedication and commitment through a very difficult time. Turning to Slide 5. I'm excited to announce today that we'll be moving forward with our strategic Cedar Creek Anticline, CO2 EOR project in 2021, putting us on track to begin CO2 injection in the first half of next year, as we bring this massive oilfield into a new phase of its life, one with a negative carbon footprint.

I'll touch on this project more, a bit later in my comments. In our last quarter's call, I said that I did not believe there was another company in the E&P industry as well positioned as Denbury for continued relevance through the energy transition. And my belief has only grown over the last quarter. With focus and optimism growing on CCUS, we thought hard about what the scarce resource might be in this new industry.

I am increasingly convinced that the scarce resource is on the downstream side of the business, the ability to provide a high capacity, highly reliable, flexible CO2 transportation, and injection system with significant scale and expandability. Our Gulf Coast CO2 infrastructure provides just that. We move 10 million tons of CO2 through this 925 miles system annually, and have a quarter million tons of CO2 in the system at any point in time. We deliver one million tons to industrial customers.

And 9 million tons is injected annually into 10 different EOR fields. Also, we receive one million tons each year captured from industrial sources. The system has significant available capacity for additional captured CO2, and is incredibly expandable whether that be through adding horsepower, looping within our right-of-way or varying the flow direction at different locations in the system. We're very proud of the integrated system we have built and operated safely over many years, and we think it is an essential and ideally located resource to facilitate the growth that is needed in CCUS.

I see the opportunity set in front of us, expanding significantly with continued emphasis on reducing atmospheric CO2 emissions and an increasing realization that CCUS will be a key element in achieving CO2 reducing objectives. We are convinced that Denbury has the right focus, the right infrastructure and the right expertise to play a central role in the CCUS industry. CO2 EOR is a key component of CCUS. For Denbury's EOR fields, we inject more CO2 into the ground to recover oil.

Then the production of that oil will ever emit, even when including emissions related to the combustion of the finished oil products. When we use captured industrial source CO2 for EOR, the carbon footprint of the oil produced is significantly negative. We have termed this carbon negative oil, blue oil, similar to how hydrogen generated through a reforming process that captures and stores CO2 emissions is called blue hydrogen. We believe that blue oil will ultimately be a much sought after commodity that should receive premium pricing as it helps the end user lower their own carbon footprint.

Today, around 20% of our total production is blue oil. And we expect that proportion to increase over time on our path toward completely offsetting our Scope 3 emissions by the end of this decade. Looking at Slide 8. I'm very pleased with our results for the quarter and the full year.

Most importantly, we set yet another record for safety performance. We kept our employees and contractors safer than ever before, a particularly remarkable achievement considering the challenges we faced in 2020. We announced an acquisition of two EOR fields in Wyoming that will continue to strengthen our business in this region. We'll also improving our already low carbon footprint.

Our agreements to reacquire the NEJD and Free State CO2 pipelines, reduce debt and simplify our operations particularly important as we consider the utility of this expansive CO2 transmission system to a growing CCUS industry. Our operations team drove costs and spending lower in a tough commodity environment, taking both LOE and capital to low levels. Our cash costs remained low at $27.45 per BOE, resulting in a 36% cash operating margin and highlighting our ability to generate free cash, even in a low oil price environment. David will go into detail on our 2021 capital budget and production guidance but I'd like to highlight our projections for our 2021 cash flow relative to our planned capital budget.

At a $55 WTI price, we expect cash flow between $260 million and $300 million more than sufficient to cover our anticipated capital for the year. I'd also point out that the $100 million CCA CO2 pipeline investment in 2021 is a one-time item that positions the company for many years of strong free cash flow at a long-term $50 oil price, as our anticipated capital levels in the subsequent years are substantially lower. Turning to Slide 10. We plan for 2021 to be the key year in CCA's EOR development.

With all of the critical permits in hand and all of the pipe purchased and onsite, we expect to begin laying the 16-inch CCA CO2 pipeline from Bell Creek beginning around midyear, and further expect to begin injecting CO2 into the field in the first half of next year with first EOR production expected in the second half of 2023. We'll spend about $100 million this year on the pipeline and another $50 million on field development. We believe that we can ultimately recover over 400 million barrels of oil over all phases of this project. And because we will exclusively use industrial source CO2, the project is fully carbon negative, which I'll talk more about when reviewing the next slide.

The bar chart on the lower left of this slide shows the CO2 balance of the first two phases of the project. This project is carbon negative on a Scope 3 basis, injecting about 85 million tons of industrial source CO2 over the first two phases. We expect the impact on field production to be significant with a peak rate from Phase 1, adding about 10,000 barrels per day on top of the existing waterflood. That wraps up my prepared remarks.

And I'll turn the call over to David for an operations update.

David Sheppard -- Denbury Resources Inc. -- Analyst

Thank you, Chris, and good morning, everyone. While we experienced extraordinary operational challenges in 2020, our operations team delivered positive outcomes in all key performance areas. I'm pleased to share our solid fourth-quarter 2020 operational results, resulting in full-year outcomes of setting a Denbury record low annual total recordable incident rate, meeting the midpoint of our revised 2020 production guidance, managing capital spend to the lower half of the revised guidance range and driving lifting costs for our lowest levels since 2016. Production for the final quarter of 2020 was roughly 48,800 BOE per day.

And full your production was 51,151 BOE per day at the midpoint of our revised full-year guidance. The impacts of the global pandemic and resulting extremely low oil prices in the second quarter drove our operations teams to evaluate every barrel we produced making active decisions to shut in production that was uneconomic to repair are produced. Using conservative economic criteria as a guide, we have safely reactivated all economic production, and we will continue to evaluate the impact of changes in oil price to base our decisions to return additional economic to repair wells to production. At current oil prices, we are running between 15 to 16 workover rigs and anticipate a similar pace to keep up with repairs and reduce the minor backlog of economic to repair production.

Considering the last few years of capital investment below maintenance levels with 2020 being the lowest level in recent years, our production decline has been tempered by our low decline asset base and by investing in smaller scale high return projects. During the fourth quarter, we continued to see positive results from our limited 2020 growth capital spend, which included the Oyster Bayou A2 development project that has continued to respond as expected. We have also continued to see response from the Bell Creek Phase 6 development. As we look to 2021, we are targeting production between 47,500 and 51,500 BOE per day.

This guidance range incorporates the impact of winter storm jury, we experienced last week across our operations, most notably in our Gulf Coast region, with record low subfreezing temperatures causing power outages requiring the shutting in – of a number of our fields. We estimate the total annualized downtime from these storms at approximately 300 BOE per day, or approximately 1,200 BOE per day impact to the first quarter of 2021. We have since recovered from the shut-ins with limited remediation expense to bring these fields back online. Throughout 2021, we expect to continue to see response from the Oyster Bayou A2 project, our Bell Creek Phase 6 development and the stabilization of production in our Delhi Field with restoration of CO2 purchase following the completion of the Delta Pipeline repair.

We are excited about the upcoming edition of the Beaver Creek and Big Sand Draw fields to our portfolio with the acquisition scheduled to close within the next few weeks. And we look forward to our great operations teams beginning to look after these assets. Our total 2020 capital spending came in well below the midpoint of our 2020 revised guidance, landing right at $95 million. With most of the 2020 low level capital spend aimed at central operations activities during the second quarter and beyond, our teams focused on evaluating our existing tertiary fields for additional opportunities.

The success of the Oyster Bayou A2 development project executed in the second quarter of 2020 paved the way to fund additional development in this great field. In the first quarter of 2021, we plan to begin the second phase of the Oyster Bayou development project by executing the first of three separate development patterns in the A1 reservoir. The A1 development project utilizes the same geologic and reservoir model that was used to design the A2 development project, and with the positive results we've seen so far from the first phase, we expect to see similar results in the A1 development. During 2021, our baseline capital program will also include a pilot pattern for a new CO2 flood in our Tinsley field.

Our Tinsley field currently produces from the Woodruff reservoir and this CO2 pilot project will target the Perry reservoir via horizontal wells. The Perry development will be designed to utilize existing infrastructure at Tinsley minimizing F&D cost. If successful, the pilot creates a multi-year phase development program with a reserved potential of over 10 million barrels. Both the Oyster Bayou A1 development and the Tinsley Perry CO2 pilot projects provide the potential for reserve additions during 2021 and with success pave the way for future development projects in these fields.

Approximately $150 million over half of the 2021 capital budget is dedicated to continuing our long-term field development plans for CCA, EOR by completing the installation of the CO2 pipeline and beginning EOR facility construction and well work. Permitting for the project remains in good standing, and we are currently all forbid on the pipeline installation. For the fourth quarter, lifting costs landed just below $20 per BOE. The strengthening of commodity process in the fourth quarter provided an opportunity to execute profitable investments in LOE projects and contributed to higher costs in the LOE categories, highly correlated to oil price.

Additionally, the increase in CO2 from the cost from the third quarter was primarily due to reestablishing purchase at the Delhi Field after completing repairs to the Delta CO2 pipeline in the fourth quarter. The adversity we faced in 2020 has improved our ability to operate cost effectively. We have a better understanding of our flexibility to manage costs and have adapted daily work processes with new technology, enabling our teams to be more proactive and efficient. This adaptive approach at managing costs was evidenced in our ability to deliver a full year lifting cost at the lowest level it has been since 2016 at $19.60 per BOE on a normalized basis.

A great example of our drop to manage costs in new ways is evidenced about challenging the concept of non-controllable operating cost. In the fourth quarter, we started a program to actively manage our electricity usage and expect this program to positively impact one of our largest LOE spend categories, power and fuel. We are able to leverage our operations with large central facilities to hedge blocks of electricity, powering these facilities, and to focus on a reduction of electricity usage during peak grid demand, both of which dropped power costs lower. We have seen favorable results in the fourth quarter and we'll continue to see positive impacts of this program in 2021.

We will continue managing our costs by leveraging existing operations data and by investing in new technology where appropriate, by enabling and using real-time analysis along with enhanced field practices, we have improved our ability to identify and prevent well failures, resulting in record low failure rates in some of our largest conventional assets, indirectly impacting workover cost for years to come. We are building a project inventory for new digital transformation projects with the goal of improving our ability to make proactive and informed decisions. We developed the 2021 LOE budget incorporating the operational improvements gained in 2020, the addition of our new acquisition fields in Wyoming, as well as including expected impacts due to higher oil prices, including increased workover activity to maintain economic production, a higher cost of CO2 and supply chain industry pressures. We anticipate full-year LOE per BOE to be in the $22 to $24 per BOE range, which is in line with previous year's guidance when in similar commodity price environments.

Next, I'll turn it over to Mark for a financial update.

Mark Allen -- Executive Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

Thank you, David. My comments today will highlight some of the financial items in our release. Primarily focusing on the sequential changes from the third quarter of 2020, I will also provide some forward-looking guidance for 2021 to help you update your financial models. I'll start by discussing our debt profile and liquidity.

We ended the year with $70 million drawn on our $575 million senior secured bank credit facility, leaving us with approximately $482 million of liquidity after considering outstanding letters of credit. As discussed on last quarter's call, we restructured our two pipeline financing arrangements with Genesis resulting in the reacquisition of those pipelines. We paid $22.5 million to require the Free State CO2 Pipeline in the fourth quarter, and over the course of 2021, we will pay $70 million to satisfy our remaining obligation under the NEJD Pipeline financing lease. The $70 million would be paid in four equal quarterly installments at $17.5 million, the first of which was made on January 31.

Under our bank credit facility, our leverage ratio at year end 2020, based on total debt divided by annualized EBITDAX for the fourth quarter was less than half a term. If oil prices hold at or near current levels, we would expect our total debt balance to continue to decline in 2021, based on our expected level of free cash flow. Turning to Slide 18, fourth-quarter 2020 adjusted net income was $29 million or $0.58 per diluted share, better than analysts, consensus estimates. The primary difference between adjusted and GAAP net income for the quarter was $80 million of non-cash expense due to fair value changes in commodity derivatives.

On Slide 19, you can see that our non-GAAP adjusted cash flow from operations, which excludes working capital changes was $72 million for the fourth quarter, up $4 million from last quarter, we generated free cash flow of $53 million in the fourth quarter, after considering $19 million of capital expenditures. We had a working cash outflow of $64 million in the fourth quarter, due primarily to a cash payment of $52 million with the final settlement of a likely litigation matter associated with our Riley Ridge operations and helium supply contract, which is no longer in effect. For full year combined 2020, we generated free cash flow of $88 million, as we controlled costs and limited our development capital spending to $95 million, which was at the low end of our capital guidance range. In addition to our free cash flow from operations, we also realized proceeds of approximately $70 million from asset sales, consisting primarily of $40 million from our Gulf Coast farm down in the first quarter of 2020 and $29 million from our Houston area surface acreage sales.

Our fourth quarter average realized oil price of $44 per barrel, after hedges was up 2% from our realized price in the third quarter, due to higher NYMEX oil prices. Slide 20 provides a summary of our oil price differentials, excluding any impact from hedges. Our realized oil price averaged approximately $2 per barrel below NYMEX prices in the fourth quarter, which was down approximately $0.40 per barrel from last quarter, and at the low end of our guidance, we provided on last quarter's call. Looking ahead to the first quarter of 2021, we expect that our overall oil differential will improve somewhat in a range of $1.50 to $2 below NYMEX.

Slide 21 provides a review of certain expense line items. I will start with G&A since David already covered lease operating expenses. Our G&A expense was $18 million for the fourth quarter, an increase of $1 million from the prior quarter. Included in the current quarter amount was $8 million of stock-based compensation expense, primarily associated with performance-based equity awards issued in the fourth quarter.

The performance criteria for these new equity awards is based on Denbury stock price resulting in an accelerated expensing of these awards over the fourth quarter of 2020 and first quarter of 2021. As such, we expect stock compensation to be higher than normal in the first quarter of 2021, at approximately $17 million and total G&A to be in the range of $30 million to $35 million. After the first quarter of 2021, we would expect quarterly G&A to normalize at $13 million to $15 million with stock compensation making up $2 million to $3 million of that expense. Net interest expense was $1 million this quarter, a decrease of $7 million from last quarter, due primarily to the restructuring of our bond debt and our pipeline financing arrangements.

On the bottom portion of this slide, there is a detailed breakout of the components of interest expense. Capitalized interest was approximately $1 million for the fourth quarter and we currently expect our capitalized interest to be in the range of $5 million to $7 million for the full year of 2021. Our depletion and depreciation expense this quarter was $41 million, a slight increase from the prior quarter. We currently expect that DD&A for the first quarter of 2021 will be in the range of $42 million to 45 million.

My last slide provides a current summary of our oil price hedges. As you may recall, under our new bank credit facility, we were required to have hedges in place by the end of 2020, covering a certain amount of our approved production through mid 2022. We added those required hedges, which were mostly swaps during the fourth quarter and we were in compliance with those hedging requirements at year end. Using the midpoint of our production guidance, our hedges currently cover around 65% of our estimated 2021 production.

And now I'll turn it back to John.

John Mayer -- Director of Investor Relations

Thank you, Mark. That concludes our prepared remarks. Operator, can you please open the call up for questions?

Questions & Answers:

Operator

Thank you. [Operator instructions] Our first question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question.

Charles Meade -- Johnson Rice -- Analyst

Good morning, Chris, you and your whole team there.

Chris Kendall -- Director of Investor Relations

Hey, Charles.

Charles Meade -- Johnson Rice -- Analyst

Chris, it's great to see the CCA pipeline going forward and this has been a priority for you guys for years, and so it's great and certainly understandable given the strength of the oil price that you guys are moving forward. But I wondered if you could give us just a little sense of the deliberations you guys as a manager team and your board had together, particularly in light of your new board composition to go ahead and decide to do this right, do this, this quarter.

Chris Kendall -- Director of Investor Relations

You bet, Charles. Thinking about those deliberations, just broadly speaking there is great support for CCA across the management of the company. The negative carbon footprint that I mentioned earlier is an added benefit and it's something that we really wanted to highlight. So we see that as adding to that negative carbon footprint story that we're working so diligently toward.

So the real conversation I'd say centered around funding the project and whether we should fund that internally or look outside to add to that. And at least what we see right now, we think we can fund that internally, we're going to keep our auctions open, if we wanted to bring in some alternative financing, by the way we see it right now, it's something that – it's a good project, it keeps the EOR business stable and the primary capital that we'll spend on that is this year, after which it reduces to a lower level and spins off free cash for decades. And so we think now is the time and since that decision prices have only improved.

Charles Meade -- Johnson Rice -- Analyst

Right. And your point about that being a onetime capital item is a good point that deserves to be reemphasized. My second question, I wanted to ask about the 45Q final rules. I saw that news in mid-January with final rules.

And I'm curious if you could give a little insight, are there any remaining hurdles of there to actually you guys mentioned that, that you expect to see some more sanctioned projects – or I think that would be great, but are there any remaining hurdles post these final rules to start to open the gates on new capture projects?

Chris Kendall -- Director of Investor Relations

There are not Charles and that's why we're so excited about it. And it was in a pretty tough January for many reasons on January 13 to see that come through was just great news, because we saw that as a milestone that makes this whole next leg of CCUS work. So when I think about it, the tax credit levels of $35 for EOR reaching $50 for direct sequestration that will enable industry and ourselves to tackle a lower price wedge of the capture projects that are out there. Ultimately, we see that needing to grow and expand, but I think that just what this does for us and for the industries that can fit within that cost structure, such as ammonia or natural gas processing, we'll see some sanctions of those projects.

And like you mentioned, we're hopeful that we'll see the first of those sanctions beginning this year.

Charles Meade -- Johnson Rice -- Analyst

Got it. Lot's – some more questions, but I'll let someone else hop on. Thank you.

Chris Kendall -- Director of Investor Relations

Thank you, Charles.

Operator

Our next question comes from the line of Richard Tullis with Capital One. Please proceed with your question.

Richard Tullis -- Capital One Securities -- Analyst

Thank you, good morning to everyone there. Chris, following up on Charles' questions a bit. So the $150 million of capex associated with us, Cedar Creek Anticline for 2021. What do you anticipate the spend level – capex spend level would be for 2022 and 2023, as you move toward first oil in second half of 2023?

Chris Kendall -- Director of Investor Relations

You bet Richard, and we put a profile in the slide deck that demonstrates that, and really shows the high level where we are in 2021 and how that diminishes over time. And so, in there you can see both the Phase 1 spend that drops substantially, right now, we're showing Phase 2 coming in 2024, but even then the level of spend at that point is lower than we're talking about in 2021. So I'd say overall, you're going to see a number that is in the $50 million to $100 million range over the next 10 years or so. And you can kind of plot it out from what we've got on Slide 11 there, Richard.

Richard Tullis -- Capital One Securities -- Analyst

OK. And then going back to the carbon capture projects, as you mentioned in the press release, and then earlier in the call that you could see some carbon capture projects sanctioned in the coming year. Can you provide any more details there on what's driving that encouragement beyond the 45Q guidelines kind of being tightened up a bit with better clarity and transparency? Are you in discussions with some of the admitters near the Green Pipeline? And what level of CO2 admissions currently do you think could be sanctioned, say over the next 1.5 years close to the pipeline?

Chris Kendall -- Director of Investor Relations

You bet Richard, and there is a few things that I'm thinking about there, in a broad sense, certainly 45Q helps incentivize industries and companies to sanction those capture projects. In a – besides that there is tremendous public and investor pressure on companies and you're seeing much of that in the news over the past several months. So there are other incentives even beyond the 45Q that I think is driving some of these projects toward a sanction. From an internal standpoint, just the sheer number of inbound requests that we've had on volumes that are contemplated being captured, either from plants that are existing today, that want to add that capacity or new plants that would be built and would have capture – built into those plants.When we look across all of that, the numbers are striking and well beyond the stated capacity that we have in our pipeline, which is part of why we have emphasized just the various means we have of expanding that.

But I'd say it's a combination, we see some macro drivers and then we – and then just the specific conversations that we're having are pointing us toward that very optimistic view, that we'll start to see some of these projects being sanctioned this year.

Richard Tullis -- Capital One Securities -- Analyst

That's helpful, Chris, I'll jump back in the queue. Thank you.

Chris Kendall -- Director of Investor Relations

Thanks, Richard.

Operator

Our next question comes from the line of Brian Kuzma with Thomist Capital. Please proceed with your question.

Brian Kuzma -- Thomist Capital -- Analyst

Hey, Chris. Thanks for taking the call.

Chris Kendall -- Director of Investor Relations

Hey, good morning, Brian,

Brian Kuzma -- Thomist Capital -- Analyst

On the blue oil side of things, have you gotten any feedback in terms of you're able to capture the benefit of a lower CI in terms of a refinery feedstock or something like that with the – in the LCFS market or the Canadian CFS market, any early feedback on that?

Chris Kendall -- Director of Investor Relations

Great question, Brian. And there is no feedback, we're ready to share just yet. What I would say is when we step back and look at it, it takes a little bit for folks to understand how EOR can work that way. This is partly attributable to the great reservoirs that we have, particularly on the Gulf Coast.

And those great reservoirs for EOR, they take a lot of CO2, they just – it's just the nature of those fields. And so that balance that we have when we look at it in the aggregate and you come out negative is something that takes a little thinking to get your head around, but it is a fact, and it's the way that our business works. And so we have started working down that path in multiple different ways, including the areas that you mentioned, but it's still early days and it's something that I think that will – as we'll continue to work and talk about, and I think make some good progress on as the year progresses here.

Brian Kuzma -- Thomist Capital -- Analyst

Got it. That makes sense. I know it's still early for a lot of guys for implementing a lot of these processes and stuff. So right – context to them, I'm going to ask on the – like when you look at LCFS or Canadian CFS plus 45Q, and those credits are $250 a ton versus you can capture for 30 to 50 with hydrogen or renewable diesel or ethanol.

I mean, that's like a $200 a ton spread on your $18 million-plus ton system. You just reached absurd numbers in terms of a value here that could be captured, but – I mean that's almost $4 billion a year in credit value. Like it seems actually like you guys have the advantage here, not Reggie, not Plug, Valero, not air products, like you guys have the infrastructure that is scarce. So like, why don't you just go build it yourself? Have you thought about like, we'll build all of this stuff ourselves and they can just buy a low carbon product from us and we'll make it? And then you'd alleviate one of the negotiations with an emitter, you'll just do it yourself.

Chris Kendall -- Director of Investor Relations

Yes. That's a great question and a great thought, Brian. It's something that we have contemplated here as we've worked through, where are the best places for Denbury to be successful in the space, and I'd say that there is a spectrum. Certainly on one end of the spectrum, we can look at the areas where we've worked and invested over so many years and that fits very nicely in the transportation and storage.

Even the adjacencies to storage through sequestration being very related to what we do with EOR. At the end of the day, we're compressing CO2 to a liquid, we're injecting it into wells, in EOR, we're taking it back out for a short period before we put it back into the ground, with direct sequestration we're just leaving it in the ground. So we see that as very straight forward. But as we step back a bit and think about that scarce resource, which is why I mentioned it earlier in the call.

We think that this huge integrated system and the flexibility and expandability and reliability that it has can do a lot and open up a lot of doors. And so, we're still thinking through all of those things and including the possibilities that you mentioned.

Brian Kuzma -- Thomist Capital -- Analyst

That's great. It's a great opportunity set ahead of you guys, and we wish you luck.

Chris Kendall -- Director of Investor Relations

Thank you very much, Ryan.

Operator

Our next question comes from the line of Jeff Robertson with Water Tower Research. Please proceed with your question.

Jeff Robertson -- Water Tower Research -- Analyst

Thanks. Chris, one question on CCA, can you talk about the economics of production at CCA versus some of your Gulf Coast EOR projects?

Chris Kendall -- Director of Investor Relations

You bet, Jeff. And CCA has a different look to it than some of the Gulf Coast projects, I'll explain that here. Much of what we're doing on the Gulf Coast and indeed across our portfolio are smaller. I'd call them quick hit projects that are very high economics, very attractive at a wide range of prices.

And Matt and David and our team have been working very hard to develop those and get them into the queue. And we execute those every chance we get, just like the Oyster Bayou and Tinsley projects that David mentioned earlier. CCA is a very large, very long-term project. We see that the life of that project lasting decades.

And so when we've looked at the economics of CCA, we were burdening that with the pipeline installation, although that pipeline will be useful for many other purposes over time, just as we see with what's happening on the Gulf Coast right now. But when we roll all that in, we still at a $50 oil price see a mid-teens type of return. And I think that's attractive here because of the long life of the project. This will be – after this investment that we'll be making this year and the smaller investments in the following years.

We will be generating significant cash from the project as we continue to develop different phases through this field. Matt mentioned so frequently, just the expanse of the field, upwards of 100 miles from one end to the other. So there's just a lot to do there. But generally, that's the way I think about it.

Jeff is we have the higher burden initially, but many decades of free cash flow as time goes on. And then what I'd say on top of that is that every one of the subsequent projects that we see that are in CCA, then they have the advantage of getting that same higher return that we see from many of the smaller projects that we have in the rest of the portfolio here today.

Jeff Robertson -- Water Tower Research -- Analyst

Thanks. Is the capital for Phase 1 that you show in 2022 and 2023, is that, can you talk about how much of that is split between facilities versus any kind of – any well conversions you need to do to prepare wells to inject?

Matt Dahan -- Denbury Resources -- Analyst

Yes. This is Matt Dahan. I'll take that question. Certainly, we're not really drilling any new wells in the first phase to speak of, we're just using existing wells.

So most of the capex is associated with prepping wells for CO2 injection is associated injection lines, and then facilities work, which is really separation and compression. That's taking place. And as we build out the development, we just keep adding that type of spent.

Jeff Robertson -- Water Tower Research -- Analyst

OK. Last question, if I might. Chris, it sounds like you believe long-term, you could leverage the CO2 assets you will have in the Rockies for CCUS as well. Like you maybe a little bit differently than the Gulf Coast, but that there's that opportunity.

Mark Allen -- Executive Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

We do. And it looks different in that regions, Jeff, the emitters are not as dense as they are through that industrial corridor on the Gulf Coast, but there are certainly opportunities as we look at just what could be developed over time up there. And so we're focused honestly, on the same strategy up there.

Jeff Robertson -- Water Tower Research -- Analyst

Great. Thank you very much.

Chris Kendall -- Director of Investor Relations

Thanks Jeff.

Operator

Our next question comes from the line of Alex Vrabel with Bank of America. Please proceed with your question.

Alex Vrabel -- Bank of America Merrill Lynch -- Analyst

Hey, guys. Thanks for having me on the call.

Chris Kendall -- Director of Investor Relations

Good morning, Alex.

Alex Vrabel -- Bank of America Merrill Lynch -- Analyst

Hey. I just had a quick one. So when we think about this, this kind of end of decade goal of being negative on a Scope 3 basis, I'm just curious. I mean, can you quantify, what gets you there? Obviously, you mentioned you still have some capacity and expansion opportunities in the Gulf Coast infrastructure kind of area.

But would this involve additional projects or do you see kind of the existing portfolio getting you to Scope 3 by 2030?

Chris Kendall -- Director of Investor Relations

Good question, Alex, the way that I think about that. So as we sit here today with about 20% of our total production using industrial source or captured CO2. And once we close this Wyoming acquisition that is also using captured CO2, so that will take that up to 25%. We have a lot of our EOR production that's supported by natural source CO2 from our Jackson Dome field in Mississippi.

And part of the advantage that I see as we progress through the decade here, and as capture projects are sanctioned and developed and come online is that we can take captured volumes. And with our control of the natural source, we can literally slot them in and reduce our supply from the natural source. Every time we do that, we increase that proportion and get ourselves closer to that Scope 3 number. Generally, when I look at the numbers, if we're able to take that 20% today to 100%, by the end of this decade, we'll be at that point.

I think that on top of that, we'll be doing some other things through the decade. I sure hope we are where we're putting CO2 directly into storage. And so we will be able to make that impact as well. But when I look it, I see the majority or essentially getting there can be accomplished just through that offset that I mentioned earlier.

Alex Vrabel -- Bank of America Merrill Lynch -- Analyst

Got it. That's really good color. And I just want to quick follow up on the storage commentary. I mean, obviously, you've coined this term blue oil and mentioned that, you believe that that might mandate premium with users of that oil.

I'm just curious. I mean, I guess one quick one, has there been interest in that so far, are buyers willing to pay a premium? And secondarily, when you look at the carbon management business obviously, the economics today are what they are today, when you look out the curve, do you see that being something that's incremental to the base oil business or something that could potentially offset your uses of CO2? Thanks.

Matt Dahan -- Denbury Resources -- Analyst

Yes. This is Matt. I'll take the first part of that as far as interest in the concept of blue oil. Certainly, you can see that there are sectors – transportation sectors in particular that they could see something like that is beneficial.

The question is how do we get it from the crude barrel to a refined product. And that's kind of our next challenge.

Chris Kendall -- Director of Investor Relations

And then Alex, I'll take the second part of your question and really just thinking about how CO2 costs over time or the CO2 price over time can impact the oil business. I think it's a really interesting question. And certainly in the past with 45Q at a much lower level, industrial captured CO2 has been more expensive than our natural CO2. And CO2 in general is a cost burden on the oil business to the tune of about $4 a barrel for our EOR fields.

As we kind of think through how that can change over time, I think that we will see the cost of that captured CO2 actually becoming a revenue source, I really think that's the possibility there. Now, if that happens, the burden – the economic burden of the use of CO2 in these fields actually becomes a benefit. And I think that we would see some very attractive changes to the economics of EOR projects for new sanctions or for the ongoing operations of our developments. So early days that still has to work its way into the system but I certainly think that's a possibility.

Alex Vrabel -- Bank of America Merrill Lynch -- Analyst

Got it, guys. Thanks for taking my questions. I'll hop back in the queue.

Chris Kendall -- Director of Investor Relations

Right. Thanks, Alex.

Operator

Our question is a follow-up from Richard Tullis of Capital One. Please proceed with your question.

Richard Tullis -- Capital One Securities -- Analyst

Yes, just one more for me, Chris and Mark. Looking at M&A, of course you had the recent Rockies acquisition at an attractive price. What is your view on pursuing potential future acquisitions now that you have the higher capex commitment related to the CCA project?

Chris Kendall -- Director of Investor Relations

Richard, the way I think about that is we always want to have our eyes open for the right opportunities to add to the business in ways that make sense for our strategy. And certainly, it was easy to see how the Wyoming assets make a lot of sense there. EOR fields, we can apply our great EOR expertise to those fields. We use even more industrial source CO2 for those fields.

So it's something that fits very well within our profile here. What I'd say is that will be a bar that will be held as we look at any other opportunities to grow the business. Certainly, we want to keep the EOR business strong and we see ways of doing that organically just as I mentioned earlier through the CCA development continuing. But when we see outside opportunities, we'll take – we'll certainly consider them, but they'll need to fit within our strategy.

And then stepping back a bit, a large focus for us will be on growing this amazing opportunity in CCUS and so we'll want to balance that as well.

Richard Tullis -- Capital One Securities -- Analyst

All right. Thanks so much.

Chris Kendall -- Director of Investor Relations

All right. Thanks, Richard.

Operator

[Operator signoff]

Duration: 51 minutes

Call participants:

Chris Kendall -- Director of Investor Relations

David Sheppard -- Denbury Resources Inc. -- Analyst

Mark Allen -- Executive Vice President, Chief Financial Officer, Treasurer, and Assistant Secretary

John Mayer -- Director of Investor Relations

Charles Meade -- Johnson Rice -- Analyst

Richard Tullis -- Capital One Securities -- Analyst

Brian Kuzma -- Thomist Capital -- Analyst

Jeff Robertson -- Water Tower Research -- Analyst

Matt Dahan -- Denbury Resources -- Analyst

Alex Vrabel -- Bank of America Merrill Lynch -- Analyst

All earnings call transcripts

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