Good morning, and welcome to Occidental’s Fourth Quarter 2020 Earnings Conference Call. All participants will be in listen-only mode. After today’s presentation, there will be an opportunity to ask questions. 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.

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 de-risk 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.

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 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. By reducing our debt by $2.4 billion and refinancing $7 billion of near-term maturities in 2020, we have significantly de-risked 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 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, lowering 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 strengthening the balance sheet to provide stability throughout the cycle.

To the recent regulatory actions, it’s clear 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 a goal 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.

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, the 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.

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.

Well, as I stated in my script, the most important thing for us is the value proposition. And as we consider options, 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 a large and diverse portfolio with 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. The timing of the lower end really depends on how quickly we can get the offers to where we need them to be. We have a couple of processes in place right now, and then there are 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 execute to reach 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 regarding the Low Carbon Ventures and the tie-in to enhance the oil recovery, and it might be a couple parter. First is regarding enhanced oil recovery. Can you talk about your ability and need, and remind us of 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 mainly from a low-carbon pathway on the upstream side, arguably maybe with a more U.S. onshore bench. I wondered if you could talk about the opportunities you see in petrochemicals and internationally to aid your decarbonization goals.

Our enhanced oil recovery projects in the Permian are one of the anchors for our Low Carbon Ventures strategy. I would say, it’s 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. As I talk about the production cycle, I want to point you to the timeline where it shows how this idea was originally brought up. It was our CO2 enhanced oil recovery projects in the Permian that laid the groundwork for this vision. We started looking at how to maximize the vast resources already in conventional reservoirs conducive to CO2 enhanced oil recovery. What we wanted to do is to have a lower cost, long-term, no decline supply of CO2, and that’s why we came up with the anthropogenic CO2 option. Our Century CO2 plant came online in 2010, capturing CO2 and delivering it to our Denver units in West Texas. In 2015, we got approval for the MRV plan for Denver unit, which is one of our largest CO2 projects. We continue adding reserves to it even today. It’s significant. We also received the first two permits ever issued by the EPA for the sequestration and capture of CO2 in the reservoir. This whole process was 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 I know you didn’t ask about the rest of this, but I want to highlight what started as a vision to improve our cost structure and extend our oil development has now turned into a new business that creates value for our shareholders while reducing emissions globally. We’ll test technology, particularly direct air capture technology, and help provide opportunities for others to expand as well.

Great. Thanks. My follow-up is actually along the same line regarding the two technologies that you talked about, 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 for direct air capture, and I wondered if you could talk about your confidence in the technology, what milestones are they going to meet whatever cost thresholds you are looking for to get scaled.

The first real milestone for us was announced yesterday, and that was the selection of our engineering and construction company, Worley. They have also a passion around carbon capture and around doing what they need to do to also become carbon neutral. I want to emphasize that in all the partnerships we’ve developed so far, all share the vision and commitment that this has to create value for our shareholders while being the right thing for operations and the environment. Selecting Worley and having them on board is a significant milestone for us. We’re hoping to complete the FEED study by 2022, and construction beyond that would take about 18 months to two years. We’re very confident in the technology because every part of direct air capture is in use somewhere. As I mentioned before, potassium hydroxide, which we use significantly, is a key component. Our team, working with Worley, will apply our learnings from previous complex projects like Al Hosn. I believe we have a great chance to build this effectively. The first plant is always more costly than the next ones due to learning curves. We’ll learn a lot from this first one and develop ways to enhance efficiency.

And Brian, I would add that the first DAC train, which 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 at 2.8%. So, just wondering why that would not be a higher priority for you to retire such a high coupon debt. Maybe you can elaborate a little bit on 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. Since that includes the yield out now, could you break down the number of rigs related to the unconventional and the number of wells that you’re going to come on stream? In terms of the trajectory, is that a pretty steady program, variable throughout the year, or is it more weighted towards early or late in the year 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. To answer your question, it does include Permian EOR conceptually, now that we’re guiding those two businesses together. I can tell you, there aren’t any drilling rigs in the Permian EOR plan for this year. For trajectory, it’s relatively flat except Q1 has a few fewer wells coming on than you do in Q2, 3, and 4 due to ramp-up. If you look back, we averaged two rigs in the third quarter of ‘20, five rigs in the fourth quarter of ‘20, and now we’re set to average about 12 rigs in Q1. So, there’s a minor difference with fewer wells being online in Q1, but it’s not significant. I’ll let Rob address your first question.

So, yes, looking at the slides, you see that preferred equity at the bottom of the slide. Our focus has been on the top two pieces of the project list right now. As it relates to Berkshire, the way the agreement works is that in order to retire principal, we’d need at least a $4 per share common distribution over a 12-month period to open it up for a one-for-one basis with Berkshire preferred principal. We don’t foresee that type of distribution on the common in the near-term future to open it up. Anything outside that would require an agreement with Berkshire to make a reduction in actual principal in the near term. We’re aware of our ability to source capital being well below the coupon rate today, but we don’t have the ability to force that upon the situation as it stands today.

The next question comes from Dan Boyd of Mizuho Securities. Please go ahead.

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? 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 of a role does direct air capture have versus using your existing infrastructure?

Our plan is to use both. We have the largest infrastructure for CO2 enhanced oil recovery in the world in the Permian. We possess the necessary pipelines to move CO2 around to our fields. We also have the gas processing plants and supporting infrastructure for those plants. We aim to maximize the development of our EOR reserves, following our agreements with various partners. For direct air capture, you can place it anywhere since it doesn’t need to be near pollution sources. This flexibility allows us to utilize direct air capture in the Permian, the DJ, the Powder River, Oman, and hopefully Algeria too. We wanted to prove the concept in the Permian due to its suitability for enhanced oil recovery. We believe that over the next 5 to 10 years, the benefits of our low-carbon business will equal our chemical business, and ultimately will be as profitable as our oil and gas business.

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? Presumably, you’re talking to companies such as Amazon and others 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. Direct air capture will play a significant role in our future. We’ll continue our other partnerships that provide services agreements with others to help them have a place to send their carbon from their facilities. I’m particularly excited about direct air capture due to its flexibility in placement. We’re engaging with industries including maritime, airline, and tech sectors, and they share our vision to become carbon neutral. What’s essential for us is creating a certified process to track the CO2 molecule from the reservoir to its end use. Once that’s in place, we can ensure partners get credit for their investment while we also benefit. The aim will be to incorporate anthropogenic from industry and direct air capture in our overall plan, and I foresee direct air capture becoming a larger portion of our operations over time.

I hate to be greedy on my first conference call with you, but just my last question is on the cost competitiveness and the cost curve of direct air capture. Recognizing it’s still early days, I get a lot of pushback on the cost of and the need for very high tax credits to make this economic. 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 believe it won’t take long for us to reach a point where tax credits are less essential. It’s similar to the journey of solar and wind. Realistically, criticism often comes from those vested in the current energy landscape. There hasn’t been a commercial plant created where you can optimize the process as we aim to. Initially, we will need tax credits, but we feel confident that with subsequent plants, we can achieve economic viability without them. Direct air capture paired with an oil reservoir reduces the overall costs due to minimized transportation distances. Each component in the direct air capture is proven, so it’s just about optimizing and making them more efficient. I believe that as we continue to trial and deploy this technology, the costs will decrease. While I can’t forecast exact timelines, I’m confident that with our team and Worley’s experience, we will bring these projects to fruition and further reduce costs.

The next question comes from Jeanine Wai of Barclays. Please go ahead.

Our first question is on the 2021 plan and what that might mean for an early peak for ‘22. Leverage improvement is pretty significant this year, along with the 2021 completions trajectory. Does it include a ramp into year-end to get ready for modest oil growth in 2022 if prices weren’t? Or is the plan next year to get back to a more meaningful base event or capable of doing both? I think, in Paul’s question, you might have said the Permian TILs were maybe a little bit ratable in 2Q. 4Q, but we’re just trying to understand if there’s any completion CapEx in there to prepare for ‘22.

Let me start, Jeanine, and then Rob and Vicki can jump in. Obviously, Q1 production is lower than the average for the year. So, there will be higher production in Q2, 3, and 4 compared to Q1 partly due to the storm and how that flows through since we started up our development late last year. But I wouldn’t see it as a continually increasing trajectory heading into 2022. Each quarter will differ slightly. However, the latter three quarters will see substantial increases over Q1. As Vicki stated, we aren’t driving towards growth for 2022. Our cash flow priorities remain intact, and we focus on deleveraging and generating free cash flow to move forward as fast as possible.

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? Can the $1.2 billion in CapEx hold the Permian flat over a three to five-year period as the Midland JV carry runs out? I know there are some gross-net issues with some of the TIL guidance this year, but how do you expect that $1.2 billion to be sustainable?

You mentioned several points there, and let me address them. The Midland Basin JV is beneficial for capital efficiency, with over 600 remaining. For the future, it’s difficult to predict as we didn’t expect to be as low as today three years ago. Our capital intensity in the resources business will be half this year of what it was two years ago, despite ramping up capital. I hate to guess on the long-term outlook, but it wouldn’t surprise me if it were a bit above $1.2 billion in a few years. Our decline continues to decrease, assisting with capital efficiency improvements. So, it could increase slightly, but I wouldn’t expect significant changes in the coming 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. Historically, the company has not regularly engaged in hedging, preferring to realize prices over the cycle that deliver the most to shareholders. However, we did take on an oil hedge in 2020 that had a collar in 2020, which carries a call provision into 2021. The only remaining from that oil hedge is the call provision in 2021. We have 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. There’s no extending call option on the gas side. We evaluate additional hedges regularly, looking at the costs versus not hedging. A costless put is still relatively expensive, and a costless collar requires both the cap in the current year and one from last year extending into 2022. As you can see, we significantly moved the debt maturities down in the near term, which offers a hedge against downturns. Our shareholders appreciate our heavy exposure and leverage to oil prices. Thus, we have not implemented anything new yet.

That’s very helpful. Thank you. My second question is, have you quantified any one-off costs for restarting your wells in Texas after the cold wave? And the same question about your chemicals division. Did you quantify any financial implications of the cold wave for this division?

We have not quantified the cost of either, the oil and gas restart or the chemicals yet. We’re still in the process. We’ve got 90% of our production back online now, with chemicals starting up some of their facilities. It’ll take a while to determine the costs, but we see no permanent damage. The wells are restarting and performing well.

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. The CapEx guidance uses the $40 WTI price. So, I’m curious, what are you seeing on inflation? If something were to pick up later in the year, is the priority to maintain production if it requires raising the CapEx a bit for inflation, or would you be more inclined to stick hard to the 2 times budget? Thank you.

Yes. The point you raised is true; we’ve seen inflation as a good indicator with that $10 change in commodity price. Although this time is different, historically changes in oil price correlated with changes in activity, but we’ve seen strong commodity price increases without the same activity increase recently. The inflationary pressures arise from activity changes and the need for resources. So, this time looks different. We haven’t seen significant inflationary pressures yet. Some market parts are driven by housing starts more than by the number of frac crews running. Nevertheless, we’ve built the budget based on those pressures without being absent any forecasting. We don’t expect any material change in the numbers for inflationary reasons; it’s a little early in the year.

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 in some of the other areas, Gulf of Mexico, DJ also, the implications of what sustaining CapEx for those businesses are is quite low relative to history. Could you share any additional color on those other lines of business and what the implication might be for future sustaining capital beyond ‘21? I know on past calls, you haven’t really wanted to comment too much beyond 2021 yet, but anything else you could share there would be interesting. Thank you.

For GoM, while its capital tends to be lumping, it comes in larger chunks than the Permian or DJ. Our strategy mainly revolves around high-return tiebacks, which have seen significant success. The additional two wells we drilled in Oxy Drilling Dynamics came in at 35% lower costs compared to 2019. If considering sustaining capital over a longer span, I would expect it to be higher than this year. We do expect some increases over the years, but not drastically. Similarly, for DJ, I’d provide a comparable response; performance improvements continue to drive better results, contributing to sustaining capital as we look a few years out.

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.