Good afternoon, and welcome to the Occidental's Fourth Quarter 2023 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Jordan Tanner, Vice President of Investor Relations. Please go ahead.

Thank you, Gary. Good afternoon, everyone, and thank you for participating in Occidental's Fourth Quarter 2023 earnings conference call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Sunil Mathew, Senior Vice President and Chief Financial Officer; Richard Jackson, President, Operations, U.S. Onshore Resources and carbon management; and Ken Dillon, Senior Vice President and President, International Oil and Gas Operations. This afternoon, 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 afternoon. We'll also reference a few non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in the schedules for our earnings release and on our website. I'll now turn the call over to Vicki.

Thank you, Jordan, and good afternoon, everyone. 2023 was a great year for us, thanks to the performance of all of our teams in Oxy. I'm going to start by discussing our financial performance, operational excellence and our strategic advancements in 2023, then I'll review our capital plans for 2024. [indiscernible] continue to position us to deliver sustainable and growing returns for our shareholders through our premier asset portfolio, advanced technology and robust commercial runway. First, I'll begin by reviewing our financial performance in 2023. Last year, our talented and committed teams across the company applied advanced technical expertise, operating skills, leading-edge technologies and innovation to our exceptional portfolio, and they delivered results, $5.5 billion in free cash flow, which enabled us to pay $600 million of common dividend, repurchased $1.8 billion of common shares and redeemed $1.5 billion of preferred shares, while also investing $6.2 billion back into the business. Next, I'll comment on our operational excellence in 2023. Last year, our production in our global oil and gas business exceeded the midpoint of our original full year production guidance by 43,000 BOE per day. This was driven by record new well productivity rates across our domestic assets in the Delaware, Midland and DJ Basins, and internationally by record production from Block 9 in Oman, and in addition, we safely completed the expansion of the Al Hosn plant in the UAE, which also delivered record annual production. Despite negative price revisions, well performance across our portfolio enabled us to achieve an all-in reserves replacement ratio of 137% in 2023, and a 3-year average ratio of 183%. Our track record from prior years of consistently replacing produced barrels continues and added F&D cost that is below our current DD&A rate. At these year-end 2023 worldwide proved reserves increased to 4.0…

Thank you, Vicki. I will begin today by reviewing our fourth quarter results. We announced an adjusted profit of $0.74 per diluted share, and a reported profit of $1.08 per diluted share, with the difference between adjusted and reported profit primarily driven by the after-tax fair value gain related to the acquisition of Carbon Engineering. Our teams exceeded the midpoint of guidance across all 3 business segments during the fourth quarter, and we delivered outstanding operational performance. Higher-than-expected production in our domestic onshore and international assets enabled us to overcome production losses caused by an unplanned third-party outage in the Eastern Gulf of Mexico. This outage led to a lower-than-expected company-wide oil cut and a higher-than-anticipated domestic operating cost per BOE. It is also expected to impact production into early next month and is reflected in the guidance that I will soon cover. We had a positive working capital change, primarily due to receipt of the environmental remediation settlement, timing of semiannual interest payments on debt and decreases in commodity prices. We exited the quarter with over $1.4 billion of unrestricted cash. Turning now to guidance. Last month, Oxy and CrownRock each received a request from the FTC for additional information related to the acquisition. The FTC's request for additional information will impact the timing of closing, which we expect to occur in the second half of the year. Oxy will receive the benefit of CrownRock's activity between the January 1, 2024 transaction effective date and close, subject to customary purchase price adjustments. Additionally, the issuance of senior unsecured notes, funding of the fully committed 4.7 billion term loans and termination of the existing bridge loan facility are expected to be aligned with the transactions closing. In 2024, we expect full year production to average 1.25 million BOE per day,…

Thank you, Sunil. 2023 was a significant year for Oxy on both operational and commercial fronts. Our teams skillfully navigated through the dynamics, and I want to recognize our employee's ingenuity and hard work, their efforts generated the exciting achievements we covered today as well as the great progress that is underway to position us for a successful 2024. With that, we'd like to open the call for questions. Jordan mentioned earlier that Richard Jackson and Ken Dillon are also on the call, and they will participate in the Q&A session. We'll now take your calls.

[Operator Instructions] The first question is from Neil Mehta with Goldman Sachs.

My question is just really around deleveraging. And so you talked about this in the opening comments, but just talk about the path to getting the balance sheet to where you want to be post the CrownRock acquisition, and how are you seeing the asset sale market playing out here and enabling you to get that debt lower?

Well, as you noted, by virtue of all the M&A that's happening, there's a lot of appetite for companies to try to get into the Permian. And we do have properties in the Permian that are not core to us, but could be core to others, and some of it is where they're placed in the Permian geographically and how they're not as cored up as some of our key areas. So the divestitures, I believe, will go well. What we won't do though is we've decided not to make any divestitures until we close the CrownRock acquisition. And then we'll start a proactive process more aggressively at that point.

That's great, Vicki. And then on the Gulf of Mexico, the Q1 guide of $107 million to $115 million, but the balance of the year, $133 million to $141 million. I'm guessing a lot of that's around the pipeline outage. Can you just give us a sense of what are the gating factors to get that asset back online, and how we should be thinking about the cadence of production over the course of the year?

Yes. We're leaving the updates on that to the operator. And so we're not making any comments on that because we're giving them room to get their business done. With respect to the rest of the year, we expect the rest of the year to continue on as normal. And we expect that when we're back up and running, we may get a little bit of flush production from that. And we'll have, hopefully, our target date for getting back up online is pretty close to what we've said. Do you have anything to add?

It's Ken here. Maybe I can add a couple of things. So we feeling pretty good about the date. And for example, we're sending our specialist start-up crews offshore tomorrow to finish lining out the facilities for full operations. I think that gives you a feel for where we are in the process. The plants are in great shape. Our operations crews in parallel with the outage carried out our full 2024 turnarounds and also completed our enhancement projects for the year as well. So avoiding outages in 2024 gives us a really good shot. So we're looking forward to it.

Thank you. Appreciate it, Neil. That was timed very well spent. They made use of all the time that they had to do things that we needed to do.

The next question is from Doug Leggate with Bank of America.

I guess the number of Scotts are shrinking, Ken. It's great to hear you on the call after Conoco's latest retirement. So thanks, Vicki, for getting on as well. So I have a couple of questions, if I may. I guess the first one is, I hate to do it, but I want to come back on the disposal question. I realize you don't want to give a lot of detail, but I want to frame it like this. When you had bought Anadarko and you were trying to delever, I seem to recall you had about 25 different packages that were for sale. And of course, you ended up not having to do hardly any of those. I think it was about a dozen or something like that. So it seems to me that you've got a lot of things that you've already scrubbed. So my question is, can you give us some color as to whether there is significant cash flow that would come along with the range of $4.5 billion to $6 billion, without being specific on assets, what's the associated free cash flow number?

Well, depending on what actually is divested, we can't really give you an estimate of what that is today. Some things are changing in terms of what we're looking at. So I think that it would be very difficult to put the number out there at this point.

Is it significant? Would you consider it material, Vicki?

Anything that's material, we wouldn't likely do. We're trying to minimize the cash flow sold to ensure that we can maintain our cash flow. With that said, there will be some cash flow going because it's hard to sell any assets out here that we haven't already at least done appraisal work on to generate some cash flow.

Okay. My follow-up is on sustaining capital. You've stepped up a little bit to $3.9 billion. But the way we -- what we're trying to figure out is this year's growth is about 2%. You're spending $6.5 billion, of which $1 billion is Battleground and DAC, which gets you to about $5.5 billion. So what I'm trying to figure out is the growth rate of 2% seems to correlate with growth spending of about $1.5 billion. It seems -- the ratio just seems a bit off. Can you help me understand how I should think about that?

So if you look at our -- what we've said we'll spend in oil and gas is $4.8 billion to $5 billion in 2024. That -- part of that will be spent on, as we mentioned, some of the mid-cycle projects that generate oil production at a later date. That's for example, the Permian EOR, investing in that would generate the oil and gas production from that is about the third year after we started. So that will be a bit delayed. Gulf of Mexico, some of those are also preparing us for the future. So the mid-cycle investments will not impact this year's production. Potentially 2.2% increase will be based on the spending of the [ 4.9 ] if you use the mid-cycle price, less that [ 480 ]. And then when you look at what's being spent in our oil and gas operations minus that amount, you still have some of that going forward facilities. So I think it speaks well to what the teams have done with respect to productivity and getting more out of the wells that we can actually spend what's really less than half that $1 billion that you mentioned on oil and gas activities and then some of that will be for facilities. So we're actually getting a 2% growth rate from some of what we've developed in 2023 flowing over to 2024 and then the high productivity that we're getting out of our developments.

It's a great answer, Vicki, still the most capital efficient portfolio by miles.

I know it's really exciting what the teams have done, and thank you for the question.

Next question is from John Royall with JPMorgan.

So my first question is on midstream. I think one area that surprised us a bit was the full year midstream guide, you gave some good color on the slides kind of bridging from 4Q to 1Q. But just thinking about bridging the full year. How would you characterize the moving pieces from full year '23 to full year '24? And then maybe what do you think the midstream business can do structurally kind of under mid-cycle conditions, excess $300 million to $400 million savings you've spoken about?

Yes. So one of the main drivers for the relatively lower guidance for this year is an assumption on the spread for the gas transportation contracts. So last year, we captured several gas transportation capacity optimization opportunities. For example, when the cold weather event occurred in the West Coast in the first quarter. So obviously, we cannot predict this event. So our guidance assumes compressed gas transportation spreads. But when the market does present itself, we are well positioned to capture these opportunities. So that is one of the main factors. The other one is in Al Hosn. We have assumed a lower sulfur pricing for '24 compared to last year. Now sulfur prices are at a near-term low of around $70 per tonne, and that is primarily due to weak Asian fertilizer demand and also sale of built-up sulfur inventories by major regional producers. But based on the market trends, we think -- we see a potential improvement in prices during the second half from demand pickup and also unwinding of the sulfur inventory. And the last thing I would say is, we think this is sort of the low point in terms of the midstream income. We have assumed a narrow spread for the gas transportation for this year. And starting next year, we are also going to start getting the benefit of the 2 crude transportation contracts expiring, like I mentioned in my prepared remarks. So looking forward, the next 3 or 4 years, you should see a significant uplift in our midstream income.

Great. And then maybe just hoping for a little bit of detail on the 700 million BOE of additions to reserves. It's a pretty big number, especially when considering you're adding an acquisition this year. So maybe just some color on the sources of those additions and where they're coming from?

I think the bulk of the addition is from our Permian Resources business, I think the -- I think just essentially most of it was. We had some revisions from productivity improvements in other areas, but the bulk was from Permian EOR, where I think, Richard, if you look at your reserve replacement ratio, just for onshore, that was pretty significant.

Yes. I mean just to add to that. I mean, obviously, the focus, while near term, some of these highlights that we're putting in on the primary benches that we've been developing driving the outperformance on production. But some of the highlights we've been trying to put in the call or some of these secondary benches that are becoming more prevalent in our program. If you look at some of those highlights at a 2nd Bone Spring or the Bone Spring line, you look at that Delaware chart that we've got on [indiscernible] production, highlighting the year-on-year performance in the Delaware, those secondary benches are outperforming our 2023 average. And so those -- as we delineate and develop more of those, that's really driving that reserves in the unconventional. EOR continues to do well. Talk in more detail if there's interest, but some of the projects they have going on there to increase capacity in some of our gas processing facilities like in the Seminole, which I think we highlighted, these are also giving us near-term, we call it, operability or it's really the reliability of that production. So some of that incremental investment this year is driving, say, a couple of thousand barrels a day of improved base production, but that's also providing capacity to develop some of those low development cost barrels that Vicki noted as we're able to bring on the CO2 for the future. So that's sort of how we're thinking about the reserve story, and it plays out in near-term outperformance, but the long term is picking it up on reserves as well.

And I would add the other place where we did add significant reserves is Algeria as a result of the team's work to get all the 18 contracts merged into 1 and then extended. So that was great work done by the Algeria team to add reserves there. But the thing I'm most proud of is, while the bulk of the reserves came from those 2 sources of the Permian and Algeria, and a little bit from the DJ, every business unit we have increased reserves except for Al Hosn where we had already booked quite a bit of reserves because of the modeling [indiscernible] to get that estimate more refined.

The next question is from David Deckelbaum with TD Cowen.

I just wanted to follow up a little just on the prior conversation around EOR. I guess this is being built out in conjunction with some of the anticipated volumes coming from STRATOS. Can you give us a sense what sort of capacity in terms of production relative to where you're at today, you're intending to build out? Or I guess, thought another way, how large do you anticipate the growth rate to be out of the EOR production base over the next 5 to 10 years?

I would tell you that, over the next 5 to 10 years, it's going to be a significant part of our portfolio development. We have 2 billion barrels of resources remaining to be developed. And we believe that as a result of our direct air capture facilities that we ultimately will build to get CO2 out of the atmosphere, it's going to be the most sustainable barrels in the world. It's going to be a resource that the world needs to get -- to leave 30% or 40% of oil in conventional reservoirs and 90% of oil and shale reservoirs is just not acceptable. And for the United States, to continue our energy independence, EOR is going to have to be a part of the equation ultimately. We're getting way ahead of the game here to be sure that we're ready because we do believe that the climate transition would not be affordable for the world without EOR being able to produce net zero carbon barrels of oil. So this is a huge part of our strategy and important, not only to our shareholders. It will add value, but to the U.S. and ultimately to other parts of the world. And for the near term, a forecast on what we can do. Richard has some data on that.

Yes, perfect. I'll tie that. I mean one of the attributes we really like around the EOR production that we talk about a lot is the lower decline. And so as we came through the last several years with -- especially to the downturn with lower commodity prices, being able to have that flat, flatter decline, less than 5%, was able to help us maintain a lot of free cash flow. We really started restoration of some of that development last year. And this year, as we go forward, we'll have about 60 wells that we'll bring online, which will add about 4,000 barrels a day of new well production. But the benefit of this EOR and when we talk about mid-cycle, that double next year and triples in the third year. So you really hit your peak production of around 12,000 barrels a day based on that investment today 3 years from now. The other thing I mentioned shortly, but just provide a little more color, the Seminole gas plant expansion, that's about 85 million a day that will add in terms of capacity for about $40 million Again, this year, we'll expect a couple of thousand barrels a day that we'll add in our base production. So if you think about kind of a cash investment intensity, or capital intensity, that's a competitive business we've got in the portfolio. But what it does, to Vicki's point, is we're able to bring on our CO2, anthropogenic CO2 for the future, these are very good return projects. They'll be very competitive in our portfolio, especially given the lower decline. And so when we look at just that Seminole, as we look '24 to '28, that's, say, another 15,000 to 20,000 barrels a day type opportunity for minimal capital. And so within sort of the range of capital that we're spending this year in EOR, we're building those sort of wedges with great opportunity to do more as we bring on more CO2. So hopefully, that helps tie the short and long.

I appreciate the details, Richard. Maybe just sticking with the theme as a follow-up, just -- I think you talked a little bit about some spending is in the budget this year for the second DAC facility, I guess, in Kleberg. Is any part of that sort of progression still contingent on conversations with the DOE? And is -- are you expecting a resolution around finality of funding and grants this year?

The discussions with the DOE are continuing and going quite well that where we -- the timing of the start of the front-end engineering and design will be dependent on the completion of some of those discussions. And then the discussions will continue beyond that on getting prepared for the start of construction, but there is a time line there that we're working through.

Maybe just a couple of details I'll add since you asked the question on that. A lot of that spend is continuing to build out the subsurface capability for that CO2. Obviously, direct air capture is an anchor for the King Ranch area, but we continue to work on our other Gulf Coast hubs. We've submitted 8 Class 6 and are expected to submit another 10 this year. So just kind of giving you scale of what those -- that type of work has been going there. So going really well. I'm really pleased with the development work on that end and then obviously Carbon Engineering, we've been getting to work more and more with and really happy with the progress that is going through R&D to project work with Ken that will fulfill that development work.

The next question is from Roger Read with Wells Fargo Securities.

I'd like to come back 2 things, please, Vicki. First one on the CrownRock, if there's anything you can kind of offer us on what the FTC is asking you for a second request. And I'll just sort of preface with I understand were some of the more integrated companies, the concern of concentration. I'm a little more surprised in a more upstream-oriented company. So anything you can help us with there?

Well, some of our teams felt like they'd asked for everything. But I can tell you, our teams are working diligently to work with the team at the FTC to get them all the answers that they need. So it's -- we're progressing and hope to, as we said, be able to close in the second half of this year.

So they ask for the moon and everything else?

I did -- well, I didn't see the moon on there, but we're not done yet.

Fair enough. All right. The other question I had in terms of the capital efficiencies are obviously coming through in the Permian. The regular, let's call it, still modest growth there, but you're increasing the growth rate during 2024 for the Rockies and other part of it. When we had the follow-up calls yesterday, you said part of it was built in some mid-cycle businesses, maybe somewhat lower decline businesses. I was just wondering from a corporate structure, how you make the decision on where to allocate the growth capital here? Like why lean more into the Rockies and the EOR rather than the Permian when we're -- kind of all conditions to thinking of the Permian is among the best returns in the business and, obviously, the performance you've been delivering at the wellhead kind of says, well, why not more capital in the Permian rather than these other opportunities?

So when you look at it on a corporate level, what we're really trying to do is balance our investments over time so that we can have a sustainable growing dividend. And it -- and we've got this unique balance that I think makes it for us, different than many other companies, and we want to take full advantage of it. And I want to let Richard and Sunil chime in on their views on it because this is a critical part of what differentiates us.

Yes. No, Roger, I appreciate the opportunity. I mean, obviously, we're putting together short term with long term in mind, and the CrownRock acquisition provides a lot of growth, and we've talked about the positive attributes of that being a more mature unconventional development with high margin, 35% decline. It immediately adds, you can think about it from a growth standpoint, a really nice growth wedge this year, both from a free cash flow basis, but also a decline basis. The Rockies, I'll just pick on 1 point there. About 40% of that capital on the Rockies this year has to do with drilled uncompleted wells that carried in from last year. The sort of the cadence of that activity levels we had resumed activity last year, got ahead on the drilling. And then this year really beginning to complete a lot of those wells. So from a capital intensity standpoint, that's very, very low when you look at what we're spending for the amount of production that we're able to add there. Obviously, that's -- we have high margins in the Rockies. We have royalties. There's other things that drive very competitive returns there. And so that DAC count, just as a data point, we'll kind of go from say, mid-60s kind of the fourth quarter last year to more like mid-30s as we balance, and that's allowing us to then actually pull back about half of a net rig in the Rockies to more of a sustainable activity level. So just a little color on the Rockies, so we don't read too much into just 1 year. But maybe Sunil can then pick that up and talk kind of across the company.

Yes. So when we think about capital allocation in the oil and gas segment, what you're trying to do is we're trying to balance between margin, base decline and capital flexibility. So if you start with cash margin, we start with the U.S. unconventional with high margin, high returns. And based on everything you've heard so far, it's getting better each year. And then you have Gulf of Mexico, which has one of the highest cash margin in our portfolio. And if you look on an incremental basis, it's even higher because a large part of the operating cost is fixed. And then you have international assets, which are mostly production share [indiscernible] where we get a higher share of production at lower prices, and this helps mitigate some of the commodity price risk and protect the overall cash margin. So that is from a margin point of view. I mean when you think about base decline, so today, our production, approximately 60% of our production is unconventional. And with Crown Rock, it's going to get to around 65%. So what we are trying to do is balance between the short cycle, high-end decline unconventional, and then the mid-cycle shallower decline conventional investments. And Permian EOR, like Richard said, is one of the lowest base decline in our portfolio. So if you look at a typical Permian EOR project, we get to the peak production by the third year, and the peak production is almost 3x the first year of production. And then after that, it is a shallow decline. So what this does is it helps manage our overall corporate decline, which helps with the sustaining capital, and which ultimately helps with the breakeven. And the third part of it is capital flexibility. So if you look at our CapEx even for this year, around 75% of upstream CapEx is U.S. onshore, where we have flexibility to change activity depending on the macro conditions. So like if you look back in 2020, in U.S. onshore, we had around 30% of the rigs that we plan to operate this year. So we were able to ramp up quickly and efficiently, and we can do this if the macro demands that. So these are the 3 attributes that we look at when we look at oil and gas capital allocation. So to summarize what I would say is we have a diverse portfolio of both conventional and unconventional assets that helps manage our base decline, while also maximizing our returns and also providing the flexibility to respond to different macro conditions.

The next question is from Neal Dingmann with Truist Securities.

My first question, Vicki, is on the DJ. I'm just wondering, could you remind me where you all sit, I think, in good shape. I'm just wondering where you all sit on total permits pertaining to your DJ D&C plan? And then while early, are you all concerned about the -- I saw some latest potential proponents Colorado bills?

Yes. I'll pass that to Richard.

Yes. I think just from a permit standpoint, it's been very productive over the last couple of years. So we stand today about a little over a rig year -- or 1.5x kind of our current activity. But in the last 6 months, we've gotten [ 155 ] through. In the next 12 months, we expect another [ 169 ]. So there are some big ones that we've been working through kind of from a larger package standpoint that have gone really well. That team there -- and I hope this helps kind of the second part of your question. We continue to drop things that are important to the communities and the state around emissions. Our safety programs are very good. We've worked on consolidating facilities and doing things around transportation to make it easier. And so a lot of those things have been really the positive things we've been able to add into these permit or development plans around the permits that we've received very positive comments on. So we're continuing on. Again, we're sort of hitting more stable, sustainable activity up there, and we feel like we're in as good a position as we have been in a long time in terms of permit outlook.

Very helpful, Richard. And then just a follow-up on shareholder return on M&A. I'm just wondering, I assume [indiscernible] the preferred redemptions would now not incur until late '25. So is it fair to assume that when you were looking at the CrownRock acquisition that the fact you factored in that any -- the CrownRock incremental production or free cash flow would more than offset any mitigated payments now for another year or so?

Yes. That's what we [indiscernible] on that. But the CrownRock does -- that acquisition, once we get our debt back down to $15 billion, that's going to be a key part of helping us then to start the resumption of a more robust share repurchase program of both the common and ultimately, the preferred.

The next question is from Josh Silverstein with UBS.

I was going to ask on kind of similar topic there now that the asset sales are pushed out, and you don't have the term loan coming into just yet. Is the shareholder return profile, just the base dividend this year and that kind of supports you get into that $15 billion debt number a bit faster?

No, actually, we would -- we're going to accumulate cash flow as we continue to work toward closing the CrownRock deal because part of cash flow will be used to help pay down both the term loan and our debt maturities that are coming. So cash flow would not be used for share repurchases until we get to the point where we've achieved those goals.

Got it. And then I saw that the Battleground project was pushed out to 2026. If you could just go through any sort of the drivers of the extra time that was needed and what the status of the other plant enhancement projects look like? And maybe what the split of that $350 million EBITDA uplift was like kind of between Battleground and the other projects?

I think there's -- the projects there were pushed out a bit just like many other things because of supply chain issues and also dealing a little bit with inflation. But those projects, we started those and those are in progress and going well at this point. So I'd like to say that though the importance of when those cash flows come on from the plant enhancement projects, we're already starting to see cash flow from those projects. The actual cash flow that we'll see from the Battleground expansion won't be until the second half of 2026. But the exciting thing about all of this is that, when you add the OxyChem projects, which will deliver the $300 billion to $400 billion the full uplift by the second half of '26, that's both the plant enhancement projects and the expansion, so we've got that, and you combine that with what Sunil had talked about earlier, where we have a $400 million reduction in our mid-cycle contract prices in 2025, we'll see the full uplift of that in 2026 as well. And so when you combine those along with the $1 billion that we expect, assuming in a WTI price of $70, that puts us in 2026 with $1.7 billion incremental cash at least and potentially more than that. So to be able to get to a point where in just a little over 2 years, where we have -- through these projects and cost reduction, we are $1.7 billion better in terms of cash flow, that's pretty significant for us and something that we're really looking forward to and excited about.

The next question is from Michael Scialla with Stephens.

I appreciate all the detail you gave on the decision to direct more capital this year to mid-cycle investments. I wanted to ask specifically about the Gulf of Mexico, which is part of that. Back in December, you were planning on just the 2 drill ships. So wanted to see what changed your thinking there to add a third drillship, and especially given that services there seem to be tighter than they are onshore, was it just part of this whole mid-cycle investment thesis? Or is there something else? And can you talk about specifically what you're seeing there that third drillship will be targeting?

And in terms of drillships, we're only planning on 2 drillships this year. In terms of GoM overall, [indiscernible] plays into the portfolio, last time I mentioned our GoM 2.0 project. Based on that, we're counting out detailed [indiscernible] characterization work we can see significant upside potential in the GoM assets. I mentioned waterflood, stimulation, horizontals, artificial lift and subsea pumping, which is already operational for us. If I talk a little bit about water injection, when you already operate fields with original oil in place numbers of billions of barrels, adding water injection is a really economical way of increasing recovery factors on high-margin, low-development cost barrels. Typical improvements in recovery in appropriate reservoirs can be between 10% and 16%, while also significantly reducing decline. So it plays into the things that Richard was talking about in EOR. Scale of these developments and the very low development costs lead to good returns. Analogs have been highly successful in GoM. As you know, we're world leaders in these technologies. We do them in every country that we operate in, and domestic is the foundation of who we are. I'd also like to highlight the OBN seismic activity that we've done since 2020. That's really helped define these targets, scale up them and it's assisting in the well planning and well locations that we're working on at the moment. I think we see GoM as a portfolio with great optionality to grow using the existing infrastructure that we have in place, but also the technology skills that we have across the entire company. I hope that answers your question.

Yes, it does. Appreciate that, Ken. And on the -- on your CrownRock acquisition call. You mentioned -- I think Richard mentioned your pilot that you've been working on the Midland Basin for a couple of years. I just wonder if there's any plans to expand EOR in the Midland in the near term? And did that have any bearing on your decision with the CrownRock acquisition?

The Crown Rock acquisition stood on its own in terms of quality and how it fit within our portfolio in the Midland Basin and made that asset stronger. But the 4 pilots that we conducted in the Midland Basin were on the South Curtis Ranch, which is not too far from some of those asset. So we do believe that the Midland Basin is going to be one of the areas that we would target in a big way with an enhanced oil recovery development that's using anthropogenic or atmospheric. But we're also doing the same thing in the Delaware Basin now. We have a pilot going on there. That will help us to potentially look at that as another place to develop ultimately. So we have both options.

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.

Just like to say thank you all for participating in our call today. Have a good day.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.