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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good morning, and welcome to the Occidental’s Fourth Quarter 2020 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note, this event is being recorded.
I would now like to turn the conference over to Jeff Alvarez, Vice President of Investor Relations. Please go ahead.
Thank you, Andrew. Good morning, everyone, and thank you for participating in Occidental’s fourth quarter 2020 conference call.
On the call with us today are Vicki Hollub, President and Chief Executive Officer; and Rob Peterson, Senior Vice President and Chief Financial Officer.
This morning, we will refer to slides available on the Investors section of our website. The presentation includes a cautionary statement on slide 2 regarding forward-looking statements that will be made on the call this morning.
I will now turn the call over to Vicki. Vicki, please go ahead.
Thank you, Jeff, and good morning, everyone.
2020 was a year of extreme volatility for our industry and the world. With the year now behind us, our operations have returned to a normalized activity level in support of stabilizing our full year production at our fourth quarter 2020 rate.
We entered 2021 with an improved financial position by taking the necessary steps to protect our asset base and derisk our balance sheet. I’m particularly proud of our teams who leveraged our technical expertise to mitigate production decline while relentlessly lowering costs. The capability of our outstanding employees to consistently deliver remarkable results safely was key to our ability to navigate the challenges of the last year as well as the challenges presented by the winter storm last week.
This morning, we’ll provide the details of our full year 2021 plan. This plan maintains our best-in-class capital intensity, even with the modest activity increase we started in the fourth quarter of 2020. We’ll also provide an update on our divestiture and deleveraging progress as well as reviewing our financial results and guidance for the year ahead.
Throughout 2020, we focused on maintaining the integrity of our production and asset base as well as lowering overhead and operating costs. Our achievements have positioned us to build on our track record of operational excellence and efficiency gains as we stabilize production in 2021.
In the fourth quarter, our businesses continued to outperform and generate momentum for a strong start to this year. We exceeded our production guidance while continuing to deliver lower-than-expected operating costs for the quarter. Our oil and gas operating cost of $6.80 per BOE and domestic operating costs of $6.05 per BOE continued to demonstrate the lasting impact of our cost reduction measures as our domestic operating costs were significantly below our original expectations for the year.
Although our activity slowed in the second and third quarters, our teams did not miss a step as we normalized activity in the fourth quarter. Our onshore domestic assets went from running 22 drilling rigs in the first quarter, down to zero in the second quarter and then returning to 11 rigs by the end of the year.
Operationally, we continue to outperform our expectations and deliver efficiency improvements with new drilling and completion records. Our Texas Delaware and DJ Basin teams demonstrated our consistent drive for efficiency by exceeding our original well cost synergy targets in the quarter, an achievement we’re very proud of.
No matter how favorable or challenging the environment in which we operate, we never take our eye off safety. Many of our teams tied or set new safety records last year, while our Company-wide performance was our best ever as we simultaneously worked to minimize the risk from COVID.
We transitioned into 2021 with an improved financial position, having achieved our divestiture target for 2020. We closed approximately $2.8 billion of asset sales, $2.4 billion of which closed in the fourth quarter. In 2020, we utilized the divestiture proceeds to strengthen our balance sheet by reducing debt and liabilities by approximately $2.4 billion and $300 million, respectively.
We also completed a successful refinancing program, extending approximately $7 billion of debt maturities. Together, these achievements place us in a strong position for the year ahead, so we can focus on reducing debt and improving our business while maximizing the value of our unmatched asset base.
The progress we made last year in reducing operating costs will continue into 2021 as the synergies we delivered and the vast majority of our additional cost savings remain in place. These savings are now embedded in our ongoing operations. We expect to deliver overhead of $1.8 billion, which represents full retention of all synergies and a significant portion of our additional cost reductions. We’ll continuously seek new opportunities to lower costs and expand margins as we move forward. We expect to spend $2.9 billion of capital in 2021 to sustain our production at our fourth quarter production rate.
Our plans are based on a $40 WTI price environment, and we are prepared to flex spending lower, if necessary. If oil prices continue to improve this year, we will not increase capital in support of production growth. The flexibility and optionality that our scale and asset base provide are often underappreciated. We are equipped to adjust to future potential commodity price dips or regulatory changes while being positioned to leverage the benefits of future price uplift. Likewise, our capital and spending plans retain a high degree of flexibility, allowing us to adapt to a changing macro environment.
The level of capital spending required in 2021 to sustain our production demonstrates our ability to deliver best-in-class capital intensity even in a period where we are not growing production. Leveraging our technical expertise, particularly in subsurface characterization, enables us to drill the best wells while we continue to pursue new ways to lower costs with the goal of spending less to produce more barrels. The efficiency of our capital development, coupled with our low base decline and our relentless pursuit of maximizing every barrel from our existing wells, allows us to hold our production flat with capital of $2.9 billion in 2021.
We are pleased with the progress achieved to date in closing divestitures and reducing debt, especially given the challenging market in 2020. We exceeded our $2 billion divestiture target with the closing of the mineral and surface acreage in Wyoming, Colorado and Utah as well as our onshore assets in Colombia. Post Colombia, we are targeting an additional $2 billion to $3 billion of asset sales to be announced by mid-2021. We are making progress towards this new target and have already closed approximately $350 million of transactions.
As we near the end of our large scale divestiture program, we will continue to balance transaction timing with price realization. We’ll not sacrifice value to close transactions quickly. As commodity prices continue to strengthen, we expect the value that buyers place on assets to adjust accordingly. We will always prioritize obtaining value for our shareholders over meeting a deadline or divestiture target, which we’ve imposed upon ourselves.
As Rob will speak to you in a moment, our debt reduction efforts, combined with our ability to refinance $7 billion of near-term maturities over the last year, places us in a favorable position. We continuously review our portfolio to ensure we have the optimal mix of free cash flow generation, capital efficiency and low decline assets. We now have one of the best portfolios in Oxy’s 100-year history, but this doesn’t mean that we have stopped looking for opportunities to improve our asset base. We frequently complete acreage trades to core up positions and operatorship, and on occasion, may pursue opportunities where we see outstanding value in a bolt-on acquisition. For example, we recently exercised a preferential right to increase our working interest in the Lucius project, which we operate in the Gulf of Mexico. We expect that our investment will pay back in slightly over a year in a $40 oil price environment.
Our oil and gas highlights slide includes just a few of the many achievements our business delivered in the fourth quarter. Even during a period of increasing activity, we continue to improve uptime and reduce time to market by lowering drilling and completion times. This includes our Gulf of Mexico operations, who beat their previous spud to first production record by three days. Additionally, we’ll continue to push the envelope on driving out cost and achieved our original capital synergies for well cost savings in the Texas Delaware and DJ Basin, almost one year ahead of schedule. And we are pleased to have been awarded a new concession onshore Block 5 in Abu Dhabi, which is adjacent to onshore Block 3 where we’ve been conducting exploration work. Following the award of Block 5, we made a multi-reservoir discovery in Block 3. We still have more exploration and appraisal work to complete, but are highly encouraged by the results to date.
Last year, we communicated a revised framework for excess cash flow, which prioritizes maintaining our low-cost production base, reducing debt and strengthening our balance sheet. Our cash flow priorities remain unchanged as we do not anticipate growing production for at least this year. Our immediate goal is to continue reducing debt, and with the support of the strengthened balance sheet, return capital in a more meaningful way to our common shareholders.
I’ll now hand the call over to Rob, who will walk you through our financial results and guidance for the first quarter and full year ahead.
Thank you, Vicki.
In the fourth quarter, we announced an adjusted loss of $0.78 per share and a reported loss of $1.41 per share -- per diluted share. The difference between our adjusted and reported results is primarily due to an approximate $850 million loss on sales related to the carrying value of assets divested during the quarter.
As Vicki mentioned, our achievements last year contributed to the improved financial position that we have today. And reducing our debt by $2.4 billion and refinancing $7 billion of near-term maturities in 2020, we have significantly derisked our financial profile. This is especially relevant considering we are targeting an additional $2 billion to $3 billion of divestitures post Colombia.
In 2020, we repaid or extended almost $6 billion of 2021 maturities to $2.7 [ph] billion of 2022 maturities and more than $250 million of 2023 maturity. This leaves us with less than $375 million of remaining 2021 maturity. We repaid over $9 billion of debt over the last 18 months, lowered outstanding principal to approximately $35 billion. While we were able to adequately manage this level of debt in a mid-cycle environment, our focus remains on debt reduction and strengthen the balance sheet to provide stability throughout the cycle.
As we guided our fourth quarter, capital spending increased from the third quarter to support normalized activity levels ahead of 2021. Even as activity levels increased in the fourth quarter and we returned to paying deferred dividend and cash, we still generated approximately $800 million of free cash flow driven by the strong operational performance of our businesses and our focus on improving margins. We entered 2021 with $2 billion of unrestricted cash on hand.
We are pleased with our progress in increasing our share price since our last earnings call. Our shares have traded above the $22 strike price of the warrant we issued last year. And the shares trade above the warrant strike price, warrant holders gain the right but not the obligation to exercise those warrants and purchase OXY shares for $22. As of January 31st, approximately 12,000 warrants have been exercised, resulting in about 12,000 new listed shares. As additional warrants are exercised, we allocate the resulting cash proceeds to debt reduction.
We are beginning to benefit the activity added in the fourth quarter. As there’s often a lag between the change in activity and resulting impact on production, we expect our first quarter production to be slightly lower sequentially when compared to our fourth quarter of 2022 -- 2020. The expected production decline in the first quarter is due to the timing lag in adding activity as well as the impact of the recent storm on our operations and turnaround activity at Al Hosn and Dolphin.
Our first quarter production guidance includes a 25,000 BOE per day impact due to unprecedented weather event in Texas last week. Although the storm had a meaningful impact on our Permian production, we expect the impact to be temporary as our operations recovered quickly. While our ultimate ability to recover barrels lost during the winter storm will determine if we were able to reach precisely our full year guidance, we anticipate the full year production will be essentially equivalent to our fourth quarter rate, excluding Colombia.
Going forward, we have combined Permian Resources and EOR into single Permian entity as it relates to providing guidance and reporting results. As we further integrate our Permian operations and low-carbon strategy in oil and gas, we anticipate increased opportunities in sharing of resources. We are also guiding the Gulf of Mexico separately to provide additional clarity on seasonal production variances as we get encountered [ph] by this asset.
Our focus continues to be improving items we can influence, such as growing our cash margin through operational improvement and lowering expenses. We recognize there are certain noncash items that we have less influence over and forecast an increase in non-cap expenses this year. On a per barrel basis, we expect DD&A will rise due to higher completion rates as reserve decreased during the year. When we issue our 10-K, we would disclose the lower reserve position, reflecting significantly lower commodity price environment during 2020 and activity level lower than we had forecasted at the end of 2019.
Our 2021 capital plan slide provides details by asset and investment. The production and capital guidance we provided for the first quarter and full year take into account the regulatory environment as we understand it today. Our high-quality asset base provides us flexibility to adjust activity and capital allocation as the environment may change. If a significant change to the regulatory environment occurs, we will provide an update to our guidance as warranted.
For the full year, our capital plan includes running 6 rigs in Texas, Delaware, 1 in New Mexico, 4 in the Midland Basin and 2 in the Rockies. The drillship and return to the Gulf of Mexico late last year is expected to remain active throughout 2021. The flexibility embedded in our capital plan, combined with the financial improvements made last year, have placed Occidental in a much stronger position for the years ahead. While we still have work to do to strengthen our balance sheet, we now have the necessary runway to continue optimizing the performance of our assets while improving our financial position.
I will now turn the call back over to Vicki.
…to the recent regulatory actions that the social cost of carbon and methane have become increasingly important for our industry, and we have been active and engaged in being part of the solution. Our low-carbon strategy enables Occidental to play a leading role in limiting methane emissions and removing CO2 from the atmosphere while amplifying our existing businesses and benefiting our shareholders. We expect to improve the profitability of enhanced oil recovery in the Permian and in other regions as we reduce the carbon intensity of our own emissions and products.
As we implement our low-carbon strategy, we expect to continue working cohesively with regulators under the new administration while demonstrating our commitment to safety and the environment. We expect our operations on federal land to continue and have more than 350 approved permits in New Mexico and approximately 175 in the Powder River Basin with many more pending. In the Gulf of Mexico, we have not experienced any impact to our operations.
Following our last earnings call, we released our 2020 climate report detailing our target of reaching zero emissions from our own operations by 2040, with an ambition to accomplish this by 2035 and an ambition to be net zero, including the use of our products by 2050. As part of our low-carbon strategy, we can provide a solution for partners and other industries as well, which is airlines and utilities. Those industries may not have an alternative means to significantly lower their carbon footprint.
As I’ve said before, the opportunity before us is immense, and we are ready for the challenge. Thanks to our incredible employees, we can plan through the lens of being a best-in-class, low-cost operator with an exceptional portfolio of assets in tandem with a goal of reducing our greenhouse gas emissions and executing our strategy to lead in a low-carbon world.
We’ll now open the call for your questions.
[Operator Instructions] The first question comes from Doug Leggate of Bank of America. Please go ahead.
Thank you. Good afternoon, everybody. I appreciate you taking my questions. Maybe, Vicki, first one is for you. It’s actually on midstream. I think, over the last couple of months, you talked about the possibility of maybe not quite a blend and extend, but some kind of a potential renegotiation of your midstream tariff. I wonder if you can walk us through where that stands today. And I’ve got a follow-up for Rob.
Yes. I’m going to start this out, and then let Rob add some to this. But, we have looked at alternatives and options. We’ve had conversations with other companies and potential partners, and we have not come across a solution that was acceptable to us from a value standpoint. We’re still continuing to consider options that are being brought to us, but we’re not willing to sacrifice value to do a deal that’s going to negatively impact us in the future. So, we’re still working the option around that. We believe that over time, there could be ways that we could adjust what we have today, but the strategy is just not in place for us to be able to execute on it now.
Yes. I would second that, Vicki. Doug, those contracts roll off in 2025, as we’ve indicated before. And to Vicki’s point, simply finding a way to actually find a super economic value to [Technical Difficulty]
Your voice is drifting in from the echo somewhere. So, I don’t know if someone else is tapped in here. But anyway, thank you for that. My follow-up is on the balance sheet and the disposal, I guess, the disposal target, Vicki. I realized that, it looks to me anyway that you’ve pushed out the maturities even further and you continue to talk about lineup side on the disposals for this year. So, I just wonder if you can walk us through your level of confidence in achieving that target and what lies behind that confidence. And while I realize that gets you to the bottom end of your original target, I wonder in a higher oil price environment, if you would still look towards the upper end of that $10 billion to $15 billion range that you laid out a year or so ago? Thanks.
Well, as I stated in my script, the most important thing for us is the value proposition. And as we consider options, and I can tell you, we have incoming offers for various things. So, if we wanted to simply achieve the $2 billion to $3 billion divestiture target, we could achieve that. But what we’re weighing is the value proposition of the offers that are coming in. And so, we’re going to stay very committed to making sure that we get the best value for whatever we execute on. But, I will say that I have some confidence that we’ll get there because of the fact that we have multiple opportunities. We’re not depending on just one or two possible divestitures. We have in our portfolio, so large, so diverse. We have multiple options to choose from. So, I do believe that we could get to the upper end, but it’s more likely that we would target the lower end. And the timing of the lower end really depends on how quickly we can get the offers to where we need them to be. And again, we have a couple of processes in place right now, and then the -- some things on hold. So, it’s all about value for us and getting to that number. And regardless of oil price, if the value is there, we still want to make the execution to get the divestitures to our $2 billion target, and we believe we can do that.
The next question comes from Brian Singer of Goldman Sachs. Please go ahead.
My first question is with regards to the Low Carbon Ventures and the tie-in to enhance the oil recovery, and it might be a couple parter. First is with regards to enhanced oil recovery. Can you talk about your ability and need, and remind us of that your ability and need to expand investments and production of EOR to meet your net zero goals, and how that factors into your capital budget in 2021?
And then, the second part is, on slide 38, focuses very much I think largely from a low-carbon pathway on the upstream side, arguably maybe with a more U.S. onshore bench. And I wondered if you could talk about the opportunities you see in petrochemicals and international to aid your decarbonization goals.
Well, our enhanced oil recovery projects in the Permian are -- they’re one of the anchors that we have for our Low Carbon Ventures strategy. I would say, it’s not -- the way we’re doing our strategy is not a necessity that we do it in association with our CO2 enhanced oil recovery projects in the Permian, but we believe that’s the best way to do it and the best value proposition for our shareholders. So that’s what we focus on initially.
And if I could just point you to -- as I talk about the production cycle, point you to the time line where it shows how this idea was originally brought up, it was our CO2 enhanced oil recovery projects in the Permian. They were the reason that we started this vision. And we started the vision more than 10 years ago. We started the vision well before 2008, where you see on the timeline that the original 45Q tax credit was established. We were a part -- our government group was a part of helping to get 45Q tax credit approved and put in place.
And so, back then, what we started looking at was how to maximize the vast resources that we had already in conventional reservoirs that were conducive to CO2 enhanced oil recovery. So, that started the process back then. What we wanted to do is, we wanted to come up with a way to have a lower cost, long term, no decline supply of CO2, and that’s why we came up with the anthropogenic CO2 option. So, you see, in 2010, it’s when our Century -- CO2 Century plant came on, and it’s capturing CO2, delivering it to our Denver units in West Texas. And the Denver unit MRV plan, you can see we got approved in 2015. The Denver unit is one of our largest CO2 projects. We are continuing to add reserves to it even today. It’s massive. And so, that and in addition to the Hobbs MRV plan that we got in 2017, it’s important to note that we were the company that got the first two permits ever issued by the EPA for the sequestration and capture of CO2 in the reservoir.
And the MRV is, it means monitoring, reporting and verification. It’s just a plan that ensures that you put -- when you put the CO2 on the ground, you have properly sequestered it. So, we got the first two of those. And that whole process, as we started getting that done, was to try to take advantage of the more than 1 billion barrels of resources that we have left to develop in our current holdings and conventional reservoirs in the Permian. And as you know, the Permian is so vast, we have lots of ability to expand way beyond that.
And I know you didn’t ask the rest of this question, but I do want to talk about what started as a vision to improve our cost structure and extend our ability to develop even more resources in the EOR business. It’s now turned into more than that. It’s turned into an ability for us to create a new business, a new business that not only will add additional value for our shareholders over time, but reduces emissions in the world. And it helps -- we’ll be the leaders in helping to test technology, the direct air capture technology, put it in place, make it operational and commercial, and that will be -- will provide an opportunity for others to expand it in the world.
And so, moving to what that does beyond our enhanced oil recovery in the Permian, you have to look at some of the things that are a part of what we’re doing. In 2018, another thing that was critical for us was when 45Q was expanded. And when we -- when it was expanded and approved by Congress, it enabled us to make this commercial, the first direct air capture and carbon capture from industry commercial. So, that was an important step. Then we established our Low Carbon Ventures group. We joined the Oil and Gas Climate Initiative. We teamed up with White Energy to capture CO2 from their project. We did some other things around emissions, too. We announced our Goldsmith solar project.
And two other things that we did is we invested in NET Power in 2018. NET Power is a technology that will generate electricity at a lower cost in a typical power plant and with the opportunity to capture the CO2 as a part of the process so that we can -- sequester it in our oil reservoirs. And then, at the start of 2019, we invested in Carbon Engineering. The Carbon Engineering has the technology that we will use as a part of our direct air capture process to pull CO2 from the air and to then sequester it in our oil reservoirs. And you can see through there, there are other things that we continue to do over time that’s led us to where we are today. There is -- I won’t go through and read all of those, but there’s a lot that’s been done. And the foundation has been very meticulously planned and staged, and now the foundation is set for us to finish some of the processes that we have and discussions that we have in place today to get to a point where this really becomes a business that has three ways of benefiting us and benefits the world. And so, without going through and reading the rest of that, I’ll go ahead and stop here and let you answer or ask your follow-up.
Great. Thanks. My follow-up is actually a similar line as it relates to the two of the technologies that you talked about, the emission-free power and direct air capture. What milestones are you looking for in 2021? Do you have full confidence that these two technologies can get to scale? The FEED study is out for at least half of maybe or the first train or half of where you kind of want to get capacity to for direct air capture, and I wondered if you can just kind of talk about your confidence in the technology, what the milestones are that they’re going to meet whatever cost thresholds you are looking for to get scaled on.
Well, the first real milestone for us was announced yesterday, and that was the -- or maybe today, and that was the selection of our engineering and construction company, and that’s Worley. Worley is -- they’re an incredible company. They’re -- they have also a passion around carbon capture and around doing the things that they need to do to also become carbon neutral. And I want to point out, in all the partnerships that we’ve developed so far, all the partnerships have been with people who share our vision and our commitment that this is -- has to create value for our shareholders, but it’s also the right thing to do for our operations and for the world.
All of these guys share the same thing. United Airlines, who is partnering with us too to build this direct air capture, they share the same vision that we do. They’re committed to become carbon neutral. So, selecting Worley and having them on board with the commitment that they have and to get the FEED study done, that’s going to be a significant milestone for us. And we’re hoping to get that done by 2022. And then, the construction beyond that would take about 18 months to two years. But we’re very confident in the -- that the technology will work because every part of the direct air capture is being used in some way somewhere. And as I think I said on the last earnings call, one of the key things that’s needed in there as a part of it is that potassium hydroxide, which we use a lot of anyway. And so, we’re familiar with what we need to use. We’re familiar with the pieces and parts.
And I have confidence that our team in working with Worley to work out the details. We’ll do the same thing that we’ve been able to do in Al Hosn where that was a very complex facility that we built there. And I know I belabored this probably too much, but that was incredibly impressive to build a facility out the middle of the desk at that huge and the sulfur recovery units that are a part of Al Hosn were very, very unique and different. And I don’t think there are any that are that large and anywhere else in the world. But, we working with our partners, ADNOC, were able to make that work right off the bat without any kind of glitch. And not only made it work, but we were able to expand it by 30% with just an incremental $10 million off of the $10 billion that it took to build it.
So, our major projects team knows how to build things. Worley is very, very experienced and knowledgeable. I think between the two of us, our team and them, I think we have a great chance to build with this first one. And the first one is always more costly than the next ones to come because we -- you learn a lot from it. But, I believe we’ll learn a lot from building this first one and making it as efficient as we can be and then learning as we get it online, how to make it even more efficient.
Yes. And Brian, I would just add for order of magnitude, that first DAC train, I think you described would capture 1 million tons annually, which is about 5% of what we sequester annually in the EOR business today.
The next question comes from Paul Cheng of Scotiabank. Please go ahead.
Two questions. First I think is for Rob. Rob, when I’m looking at your presentation, in terms of the cash flow priority, I’m actually surprised that you put retiring the preferred equity at the bottom, given it’s actually pretty high 2.8%. So, just wondering that why that would not be a higher priority for you to retire such a high coupon debt to some degree, I mean, even though you start deferred equity from our standpoint, it’s no different than the debt. So, maybe that you can elaborate a little bit of the thinking.
Secondly, back on your page 15, I think, you gave some data about the Permian, 11 rigs that you’re going to run and the number of wells. And since that’s including the yield out now, so can you break it down, the number of rigs that is related to the unconventional and the number of wells that you’re going to come on stream? And in terms of the trajectory, is that a pretty steady program, variable throughout the year, or that is more heavy bottom, or that is early heavy or that is bottom heavy in terms of the program? Thank you.
Paul, this is Jeff. I’ll answer your second one first because I think that one is probably a little more straightforward. So, to answer your question, it does conceptually include Permian EOR, now that we’re guiding those two businesses together. But I can tell you, there aren’t any drilling rigs in Permian EOR plan for this year.
And as for trajectory, it’s -- I would say, it’s relatively flat except -- Q1’s got a few -- it’s not a huge difference, but a little bit, fewer wells coming on than you do in Q2, 3 and 4, and that’s just because of the ramp-up trajectory. So, if you look back, we averaged two rigs in the third quarter of ‘20, 5 rigs in the fourth quarter of ‘20, and then now we’re going to average about 12 rigs in Q1. So, when you just think about that trajectory and how the wells online lag that, it makes sense for Q1 to be a little bit lighter, but it’s -- there’s not a huge difference between those. And I’ll let Rob take your first one.
Hey Paul. So, yes, so looking at the slides, you do see that the preferred equity is at the bottom of the slide. Frankly, obviously, we’re focused on the top two pieces of the project list right now. As it relates to the Berkshire, so the way the agreement works is that in order to retire principal, we would have to have at least a $4 per share common distribution over a 12-month period to open up and on a one-for-one basis down on the Berkshire preferred principal. And so certainly, we don’t foresee that type of distribution on the common in the near-term future to open it up. To do anything outside of that would require an agreement with Berkshire in order to make a reduction in the actual principal in the near term. It’s not that we’re not aware of the fact that our ability to source capital is well below the coupon rate today, but we don’t have the ability to force that upon the situation as we sit today.
The next question comes from Dan Boyd of Mizuho Securities. Please go ahead.
So, I just want to follow up with a few questions on the mission targets and the carbon capture business. So, just first, can you maybe give us an update or a review of your existing pipeline infrastructure and your ability to capture revenue from just the 45Q tax credits and sequestering carbon? And sort of as we think about, I think you’ve made comments, Vicki, about revenue from your carbon business matching your oil business in a couple of decades from now. How big does -- how big of a role is directly our capture versus using your existing infrastructure?
Our plan is to use both. As you may know, we have the largest infrastructure of any CO2 enhanced oil recovery in the world in the Permian. We have the pipelines that we need to move the CO2 around to wherever we need it to go and for our own fields. We also have the gas processing plants and the supporting infrastructure for those plants and the pipelines. So, that’s why when we think about how to maximize and continue to develop the EOR reserves, that’s our preference.
And as I’ve mentioned in -- when I was going through the time line, the deal that we made with White Energy, they’re an ethanol company. So they have two plants in the Permian Basin, and they’re -- not in the Permian Basin, I’m sorry. They have two plants in Texas. And their plants are not too far from a pipeline that will get that CO2 to our infrastructure in the Permian. So, that’s why we did the deal with them.
We’ve also teamed up with a cement plant in Colorado to do the same thing, and that plant there will tie into a pipeline that we have coming from Southern Colorado all the way down to the Permian. So, we’ll be getting CO2 from that plant into the pipeline and to our EOR operations in the Permian. So, it’s that infrastructure that we’re trying to definitely take advantage of.
But, the really good thing about the direct air capture and the thing that some people have missed is you can put direct air capture anywhere because you don’t need to put it where the pollution is because the winds balance the concentration of CO2 around the world. So, what we can do with the direct air capture is put it right close to the facility or the reservoir that we want to put it into. That’s why it makes us possible to have direct air capture in the Permian and the DJ, the Powder River, Oman and ultimately, and hopefully in Algeria too. So, we can put it anywhere we want.
And this creates opportunities way beyond the Permian. We wanted to prove it up in the Permian because that is the best place for -- almost in the world for enhanced oil recovery. The utilization of the CO2 is best there. And so, we’ve got a good option, good opportunity to maximize our infrastructure. Nobody else has the scale that we do and the size that we do and the opportunity that we have. So, we’re very, very excited about it. And we do believe that over the next 5 to 10 years that the benefits of our low carbon business will equal our chemical business. And then, as you said, ultimately, it’s going to be as profitable and deliver as much as our oil and gas business does.
Okay. That’s very helpful. My follow-up would be, as we look at your goal of being carbon-neutral, can you talk about how much of that reduction comes from direct air capture? And how that ties in with getting companies like United to come in as a partner? And presumably, you’re talking to companies such as Amazon and the like of those that want to lower their carbon footprint. How do you share those carbon credits as you get others to come in and fund the facility cost?
Yes. I think it’s -- the direct air capture is going to be a huge part of our future to do this. We’re going to continue the other partnerships that we consider the services agreements with others to help them have a place to send their carbon from their facilities, from their plants or industry. But we’re -- I’m most excited about the direct air capture because of where we can put it, and the maritime industry, the airline industry, the tech industry. We’re having conversations with companies from all of those industries.
And the thing that we really need to have in place and what we’re working on too is to ensure that we have -- that there is a way and a certified process to track the CO2 molecule from the reservoir to its end use. And as that matures, then we’re going to be able to ensure that as we build these partnerships that the partners we have will be able to take full credit for what their investment should provide them while we do the same. But, it’s all going to be associated with either anthropogenic from industry or direct air capture. And I believe, over time, direct air capture will be a bigger percentage of what we do.
I hate to be greedy on my first conference call with you, but just my last one is just on the cost competitiveness and the cost curve of direct air capture, recognizing it’s still early days. But, I get a lot of pushback on just the cost of -- and the need for very high tax credits to make this economic. But, can you talk about where you think the cost curve can be three to five years from now as you start to build these facilities?
I think, it’s not going to take very long for us to get this to the point where the tax credits are going to be necessary. It’s just like solar and wind. I can tell you that I hear the most negative comments from those who have a reason to say that solar and wind are profitable today, a direct air capture never will be. Reality is, there’s never been a commercial plant built that -- where you can optimize the process like we’re going to do. We do expect -- as I said earlier, the first plant will be the most expensive, but I don’t believe it’s going to take very many plants for us to build to get it to the point where it is economical and does not need the credits. Initially, we do need the credit, but we’re very close to being in a position to -- for the credits to go away, we believe. Because of the fact that we’re -- if you couple direct air capture with an oil reservoir and you don’t have to build a pipeline to take it very far, you’ve already there optimized the cost of the initial bill and the ability to get it in place and make it operate. And every component in the direct air capture is working somewhere. So, it’s a matter of just putting the components together and getting them to be more efficient.
I believe, like any new technology, that the cost definitely will come down. How quickly it will come down I think is going to be driven by the expertise, experience, commitment and drive of those working on it. I can tell you our team in Worley, the reason we selected them is because they clearly have a vision on how to make this work, and they’re committed to it as our team. And so, I have high confidence that over time and not too long a time within the second or third unit, we’re going to have it down to the level where credits are not going to be needed. That’s why we’re very confident that we can expand this to other areas internationally.
The next question comes from Jeanine Wai of Barclays. Please go ahead.
Our first plan -- our first question is on the 2021 plan and kind of what that might mean for an early peak for ‘22. Leverage improvement is pretty significant this year and on the ‘21 completions trajectory in the amount that you have. Does it include a ramp into year-end to get ready for maybe modest corporate or corporate oil growth in 2022, if prices weren’t, or is the plan next year to instead get back to a more meaningful base event or is able just to do both? I think, in Paul’s question, you might have said the Permian TILs were maybe a little bit ratable 2Q. 4Q, but we’re just trying to figure out if there’s any kind of completion CapEx in there to get ready for ‘22.
Let me start, Jeanine, and then Rob and Vicki can jump in on the back end. So, obviously, Q1 production is lower than the average for the year. So, there is -- 2, 3, 4 is going to be higher than Q1, partly because of the storm and then partly just because of how we started up our development program late in the year and how that flows through. But, I wouldn’t think of it as some continually increasing trajectory heading into 2022. It doesn’t necessarily look like that. It’s -- every quarter, it will be a little different. But definitely, the back three quarters are higher than the first one.
I think, as Vicki said, we’re not driving towards growth for 2022. Our cash flow priorities remain intact. We’re very focused on deleveraging -- generating free cash flow from the business that we can use to continue that pace and move that forward as fast as we can.
Okay, great. That’s very helpful. For the Permian on sustaining CapEx, how do you anticipate that the area mix will change over the next few years? And can that $1.2 billion in CapEx, can that hold the Permian flat over, say, like a three to five-year time period as the Midland JV carry runs out? I know there’s some gross net issues with some of the TIL guidance this year, but how do you anticipate that $1.2 billion being sustainable?
Yes. I mean, you mentioned a couple of points there, and let me hit on them. So, like the Midland Basin JV, it’s very helpful from a capital intensity standpoint. If you look at that, where the 750 carry or through, we’ve still got a little more than 600 left on that. So that will get us through at least another couple of years from a capital efficiency standpoint.
If you asked us to guess where we’re going to be, it’s difficult to do that because I wouldn’t have expected would be as low as where we are today three years ago when we were doing this business as the teams continue to get better. And just as an example, our capital intensity in the resources business will be half this year of what it was two years ago. And that’s in a year where we’re ramping up capital, so usually that works the opposite way. So, our teams continue to get better and better. So, while I would hate to guess on what that’s going to be, it wouldn’t surprise me to see it be a little bit higher than a $1.2 billion three or four years from now, but I wouldn’t expect a meaningful change from that number to hold our Permian Basin flat.
I think, you’ll get puts and takes. Our decline continues to come down, as you saw the corporate decline going from 25% to 22%. That’s largely driven by our improvements in our unconventional businesses, both in Permian resources going from 37 to 33. Also in the Rockies, that’s coming down to about 33. So, I continue to expect that to improve a bit. And as the teams get better and better, that should also help with that capital intensity going forward. So, I guess, the short answer is, it could go up a little bit, but I wouldn’t expect a huge change over the next few years.
The next question comes from Raphaël DuBois of Societe Generale. Please go ahead with your question.
The first one is about your hedging for crude oil. I was a bit surprised not to see a new slide on this in your presentation package. Could you please remind us what is your position on hedging? And can you confirm that you didn’t take further position in Q4? Thank you.
Thanks, Raphaël. So, just historically, the Company is not one that’s regularly engaged in hedging, preferring to realize the prices over the cycle, that delivers the most to shareholders. But we did, to your point, with our increased leverage, take on an oil hedge in 2020 that had a collar in 2020, but then it also had a call provision in 2021. So, the only thing remaining from that oil hedge is the call provision in 2021. We have put in place, as the slide deck shows, slide 20, natural gas hedges for 530 million standard cubic per day as of 12/31 with a value between $2.50 and $3.64 on a costless basis, similar to a costless basis we had on the hedge on oil last year. There’s no extending call option though on the gas side.
We continue to evaluate additional hedges, particularly on the oil side on a regular basis. We evaluate the cost of doing so versus not doing so. As you can imagine, we do a pure put. It’s still fairly expensive, despite the improvement in price, and a costless type collar hedge is going to require both the cap in the current year in addition to the one we have hanging others today last year’s hedge, extending one into 2022. And so, when we look at the -- we moved the debt maturities down quite a bit in the near term, which is somewhat of a hedge against downturns in the business in the near term. We also know that shareholders appreciate our heavy exposure, leverage to oil price. And so, we have not put something in place as of now, but we’re going to kind of continue to evaluate them and see if they’re going to be constructive in the future.
That’s very helpful. Thank you. My second question is, have you quantified, if any, one-off cost for restarting your wells in Texas after the cold wave? And same question about your clinical division. Did you quantify any financial implications of the cold wave for this division?
We have not yet quantified the cost of either one, the oil and gas restart or the chemicals. We’re still in the -- as I think we put out. We’ve got 90% of our production back on, the chemicals in the oil and gas. The chemicals business is still starting up some of their facilities, but it’s going to take us a little while to get to the end of this to quantify the cost. But, the good thing is we see no permanent damage with anything. And the wells are starting back and looking very good.
And the last questioner today will be Phil Gresh with JP Morgan. Please go ahead.
First one here is just on the capital budget for this year. I think, in the past, Jeff, you’ve talked about for every $10 a barrel, there could be potentially 10% inflation risk. And I know that the CapEx guidance uses the $40 WTI price. So, I’m curious, what are you seeing on inflation? And if something were to pick up later in the year, is the priority to maintain the production if it requires raising the CapEx a bit for the inflation, or would you be more inclined to stick hard to the 2 times budget? Thank you.
Yes. I mean the point you raised, Phil, is true. I mean we’ve seen that both flexing up and down generally as a pretty good guide for us with that $10 change in commodity price. We see that type of inflation, deflation. What’s a little different this time, and you guys are looking at it really closely, most of the time in the past, changes in oil price correlated with changes in activity. And so, this time, as you know, we’ve seen a pretty strong run-up in commodity price lately. We haven’t seen the correlative activity change that we historically see with that. And so, really, when you kind of layer down where a lot of the inflationary pressures come from, it’s from changes in activity and the need for resources and so on.
So, this time, looks a little bit different. We’re not seeing huge inflationary pressures yet. Of course, there’s parts of the market that are driven by housing starts, more than they are, a number of frac crews running and things like that. And so, you get little puts and takes. And what we do know and what we see, we have built into the budget. So, it wasn’t absent of any of that, but it was largely poured on a lower price environment. But, we don’t expect with what we see at least right now, that number to have to change materially for inflationary reasons, a little early in the year. But at least with what we’ve seen right now, we don’t expect that to change.
Okay, got it. And my follow-up was just along the lines of Jeanine’s question. You touched upon the Permian. But, I was curious because some of the other areas, Gulf of Mexico, DJ also, the implication of what sustaining CapEx for those businesses are is quite low relative to history. So, I was just curious if you had any additional color on those other lines of business and what the implication would be for go forward sustaining capital beyond ‘21. I know on past calls, you haven’t really wanted to comment too much beyond 2021 yet, but just anything else you could share there would be interesting. Thank you.
Yes. I mean, I’d say the same thing. So, I mean, the GoM is interesting. And so, let me hit on that one first. I mean, you see what its capital is this year. I think it’s --if we looked at that over a long period of time, as you know, its capital tends to be a little more lumpy. It comes in bigger chunks than it does in the Permian or DJ because one well doesn’t just cost a few million dollars. There’s much more that goes with that, and there’s tieback costs and things like that.
So, if I was going to characterize the GoM, I mean as you know, our strategy is generally around high-return tiebacks. The teams have been super successful with what they’ve been doing. And I think Vicki hit on the first two wells that they drilled, the Oxy Drilling Dynamics are coming in at cost 35% less than where they were in 2019. So, that’s really going to help when you look at sustaining capital, and we’re having good success delineating new reservoirs around our platforms. So, a lot of good things happening there.
But to explicitly answer your question, if you looked over a five-year period, I would expect the sustaining capital to be higher than the number that we have this year. It may be a couple of hundred million in a given year higher than what we have this year. But it’s, again, not a huge difference from where we are this year, but probably a bit higher over a five-year period.
When you look at the DJ, it’s probably similar to what we said on the Permian. Again, the performance improvements are making -- I know we talk about this a lot, but I am astonished at all our businesses and what they’re doing. And let’s look at the Rockies. You look at their rig release to rig release time in the fourth quarter, for the two rigs they ran, it was 4.3 days. That was 27% better than what it was in 2019, and that’s in a restart period. So, again, they’re doing really, really well. Same thing on our EOR business, one we don’t talk a lot about, they pulled over $350 million out of their OpEx last year. And that largely is sustainable this year.
So, you look at those things and all of those kind of benefits are going to flow through to the sustaining capital as we look a few years out. So, for DJ, I’d give a very similar answer, and it could be a little bit higher than what we’re seeing this year just because of the number of DUCs we brought in this year, but it’s not going to be a huge material change. So, we feel pretty confident with our 2.9%, maybe a little bit higher, if you’re in a much higher commodity price world for a longer period of time, but we don’t see a change in 30%, 40%, that kind of thing. We feel pretty confident about that for the next few years.
In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.
I’d just like to say thank you all for your questions and for joining our call. Have a great day.
The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.