Occidental Petroleum Corporation (NYSE:OXY) Q2 2023 Earnings Call Transcript

Occidental Petroleum Corporation (NYSE:OXY) Q2 2023 Earnings Call Transcript August 3, 2023

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

Neil Backhouse: Thank you, Drew. Good afternoon, everyone, and thank you for participating in Occidental’s second quarter 2023 conference call. On the call with us today are Vicki Hollub, President and Chief Executive Officer; Rob Peterson, Senior Vice President and Chief Financial Officer; and Richard Jackson, President, Operations, U.S. Onshore Resources and Carbon Management. 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 to our earnings release and on our website. I’ll now turn the call over to Vicki. Vicki, please go ahead.

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Vicki Hollub: Thank you, Neil, and good afternoon, everyone. There are three things I’d like to drive home today. First, our portfolio of assets continue to set the table for record results. Second, our teams outperformed last quarter’s and last year’s excellent operational metrics. And I want to make sure our investors see how that flows to the bottom line. Third, our strategic and operational improvements continue to support our ability to take actions to drive even better shareholder returns. I’ll begin with the portfolio. We had the highest quality and most complementary assets that OXY has ever had. They are a unique blend of short-cycle, high-return shale assets in the Permian and the Rockies along with lower decline, solid return conventional reservoirs in the Permian, GoM and our international assets.

60% of our oil and gas production is from shale reservoirs and 40% from conventional. More than 80% of our production is in the United States. The international oil and gas assets that we operate are in only three countries, Oman, Abu Dhabi and Algeria. Our worldwide full year 2023 production mix is expected to be approximately 53% oil, 22% NGLs and 25% gas and 70% of the gas is in the United States. Our conventional oil and gas sets, along with OxyChem provides support during low price cycles while the shale assets provide the opportunity for growth during moderate and high price cycles, and the flexibility to adjust activity levels quickly if needed. This combination of assets has generated record cash flows for Oxy over the last couple of years versus the cash flow generated by the portfolio that we previously had in a similar price environment from 2011 to 2014.

The midstream business provides flow assurance and has done so with exceptional performance during catastrophes and emergencies. The low carbon ventures business will help Oxy and others decarbonized at scale in a way that provides incremental value to our shareholders. To summarize, we have a deep and diverse portfolio, providing the cash flow resilience and sustainability necessary to support our shareholder return framework throughout the commodity cycles. Let’s shift now to operational excellence. Strong second quarter operational performance exceeded the midpoint of our production guidance by 42,000 BOE per day, enabling us to again raise full year production guidance. In the Rockies, outperformance was driven by improved base production and new well performance, along with higher-than-expected non-operated volumes and the receipt of accumulated royalties.

Our Rockies teams drilled 32% faster on a foot per day basis than they did in the first quarter. The team’s diligent work set several new Oxy records, including company-wide record of drilling over 10,400 feet of lateral in only 24 hours. Just 10 years ago, it took the industry an average of 15 days to drill 10,400 feet. Our Permian production delivered higher operability and better-than-expected new well performance, particularly in our two new drilling space units in New Mexico, top spot in precious. Our Delaware completions team shattered OXY’s previous record for continuous frac pumping time by nearly 12 hours for a total of 40 hours and 49 minutes. Four years ago, the same job would have taken about 84 hours. 40 hours back then was unthinkable, but our teams have made this a reality.

We expect that the efficiencies generated by advancements in drilling and completions pumping will result in lower cost and reduce time to market. Offshore in the Gulf of Mexico, we safely completed seasonal maintenance activities focused on asset integrity and longevity. Excluding the impact of this planned maintenance, we delivered higher base production and benefited from improved uptime performance across multiple platforms. Internationally, our teams continued to deliver strong results. The Al Hosn expansion came online two months earlier than planned. as a result of great teamwork with our partner, ADNOC. This means that together, we have now successfully expanded the plan in stages from 1 Bcf a day to 1.45 Bcf a day or a very small incremental capital investment.

In Oman Block 65, we drilled a near-field exploration well, which delivered 6,000 BOE per day and a 24-hour initial production test, and it is now on production to sales in less than a month from completion. This was our highest Oman initial production test in the decade, and we continue to show the benefits of our subsurface characterization techniques worldwide. We were awarded the block in 2019 and in collaboration with the Ministry of Energy, we are positive about opportunities in the country where we are the largest independent producer. OxyChem also outperformed during the second quarter due to greater-than-expected resilience in the price of caustic soda and reductions in feedstock prices. OxyChem is one of our valuable differentiators.

It provides rich diversification to our high-quality asset portfolio by consistently generating quarterly free cash flow which provides a balance of our oil and gas business throughout the commodity cycle. Now I’d like to talk about how our focus on operational excellence is enhancing our portfolio and extending our sustainability to maximize near- and long-term shareholder returns. OXY’s wells are getting stronger and are supported by our deep inventory, which continues to get better. In the Permian, we have improved well productivity in 7 of the last 8 years. And with the application of our proprietary subsurface modeling, we’re starting to see the same results in the DJ Basin, where improved well designs have delivered reserves at roughly 20% less cost.

The improved well design has resulted in about 25% improvement in single well 12-month cumulative volumes over the last five years. And we are on pace to significantly exceed that rate in 2023. In addition, our teams are continuing to advance our modeling expertise, which has led to upgrades of secondary benches to top-tier performers. This was the key for our 2,000 — sorry, 212% U.S. organic reserves replacement ratio last year. Let me try to make that point again. Last year, because of these upgrades to our secondary benches to our top-tier benches, we were actually able to replace our production by 212% with reserve adds. Secondary bench upgrades are progressing in 2023. Overall, in 10 of the last 12 years, we have replaced 150 to 230% of our annual production.

The only exceptions being in 2015 with a price downturn in 2020 with a pandemic. Converting lower-tier benches to top tier will further extend our ability to achieve high production replacement ratios. Not only are we adding more reserves than we are producing each year, we’re adding the reserves at a finding and development cost that is lower than our current DD&A rate, which will drive DD&A down and earnings up. Our differentiated portfolio and the strong results delivered by our teams provided support for execution of our 2023 shareholder return framework. During the second quarter, we generated significant free cash flow, repurchased $425 million of common shares and have now completed approximately 40% of our $3 billion share repurchase program.

Common share repurchases, along with our dividend enabled additional redemptions of the preferred equity. To date, we’ve redeemed approximately $1.2 billion of preferred equity. I’ll now turn the call over to Rob.

Rob Peterson: Thank you, Vicky, and good afternoon, everyone. During the second quarter, we posted an adjusted profit of $0.68 per diluted share on a reported profit of $0.63 per diluted share. Difference between our adjusted reported profit was primarily driven by impairments for undeveloped noncore acreage and deferred tax impacts from the Algeria production sharing contract or PSC renewal, partially offset by an environmental remediation settlement. In the second quarter, strong operational execution enables to are over $1 billion of free cash flow for working capital despite planned maintenance activities across several of our oil and gas businesses. Following nearly $1 billion of preferred equity redemptions and premiums, $445 million of settled common share repurchases and approximately $350 million relate to LCVs investment net power, we concluded the second quarter of approximately $500 million of unrestricted cash.

We experienced a positive working capital change during the second quarter primarily driven by reductions in commodity prices and fewer barrels in shipment over quarter-end. Interest payments on debt are generally paid semiannually in the first and third quarters, which also contributes to a positive second quarter working capital change. During the second quarter, we made our first U.S. federal cash tax payment this year of $210 million and state taxes of $64 million, which were netted out of working capital. We anticipate a similar federal cash taxes will be made in subsequent quarters this year, those state taxes are paid annually. Our second quarter effective tax rate increased from the prior quarter due to a modest change in our income jurisdictional mix.

The proportion of international income, which is subject to a higher statutory tax rate grew during the second quarter. We are therefore guiding to a minimum adjusted effective tax rate of 31% for the third quarter as we expect our effective tax rate going forward will be more closely aligned with the second quarter rate. I will now turn to our third quarter and full year guidance. As Vicki just discussed, our technical and operational excellence continues to drive outperformance across our oil and gas businesses. This enables us to raise our full year production guidance midpoint to just over 1.2 million BOE per day in anticipation of a strong exit to the year. Rockies outperformance serves the largest catalyst to our full year production guidance raised and is also a primary driver of the slight change to our full year oil mix guidance.

Reported production in Rockies is expected to reduce to its lowest point this year in the third quarter before beginning to grow in the fourth quarter. In the Gulf of Mexico, we were guiding slightly lower production in the third quarter compared to the second quarter due to a contingency for seasonal weather. The third quarter weather contingency as well as planned maintenance opportunities brought forward to reduce oral downtime are expected to result in our highest domestic operating costs on a BOE basis this year when normalizing to less than $9.50 per BOE in the fourth quarter. Internationally, we expect higher production compared to the first half of 2023 due to planned turnaround and expansion project timing at Al Hosn as well as impacts from various international production sharing contracts.

As we have previously mentioned, the increased international production will be slightly offset by the new Algeria PSC, which decreased reported production, but the reduction in imported barrels is not expected to have a material impact on operating cash flow. Overall, the first half of 2023 was characterized strong production in Gulf of Mexico, Permian and Rockies, with latter two businesses also benefiting from nonrecurring production events. We have better anticipated wells and time-to-market momentum year-to-date, which we expect it to be benefiting from in the second half of the year, the third quarter will be the only quarter in the year where we production average is below 1.2 million BOE per day. Reduced production is mainly driven by the previously mentioned weather contingency implies to the Gulf of Mexico.

The decrease in third quarter production will likely result in total company production is lower in the second half of the year when compared to the first. However, the change in expected production does not represent a shift in our volume trajectory. We anticipate fourth quarter production will be similar to the first two quarters of 2023, and we expect to enter 2024 with a strong production cadence. Furthermore, our full year guidance implies our fourth quarter output of approximately 53%, largely due to improved GoM production absence of third quarter weather contingency. Shifting now to OxyChem. As anticipated in original guidance, we continued to see weakening in the PVC and caustic soda pricing during the second quarter. However, our full year guidance remains unchanged at a pretax income midpoint of $1.5 billion, which will represent our third highest pretax income ever in another strong year for OxyChem.

We also expect our chemicals business to return to a more normalized seasonality compared to recent years, meaning that the fourth quarter will represent the lowest earnings for the year. As we have mentioned on previous calls, the fourth quarter is typically not a reliable roll forward for the year ahead through the inherent seasonality of the business. We revised our full year guidance from Midstream and Marketing due to expected market changes over the second half of this year. The margins generated by shipping crude from Midland to the U.S. Gulf Coast are expected to compress further following the annual FERC tariff revision, which has increased our pipe cost approximately $2.55 a barrel. Over the same period, the price we market long-haul capacity is expected to decrease.

Additionally, we anticipate fewer gas market opportunities as spreads across multiple basins have continued to narrow and find opportunities generated in the first quarter. Also, pricing for sulfur produced a holding is expected to soften in the second half of the year. Capital spending during the quarter was approximately $1.6 billion. We expect capital to decrease slightly in the third quarter with a more pronounced reduction in the fourth quarter. The expected decrease was primarily driven by reduced working interest and growth activity in the Permian, which is in alignment with our original business plan. We anticipate receiving $350 million during the fourth quarter associated with the second quarter environment remediation settlement.

While this settlement will drive our reported overhead down, our full year guidance to overhead expense on an adjusted basis remains unchanged. Turning now to shareholder returns. As Vicki mentioned, we further advanced our shareholder return framework during the second quarter through the repurchase of $425 million of common shares, which enabled additional preferred equity redemptions. After a strong start in the first quarter, we triggered the redemption of over $520 million of preferred equity in the second quarter. Year-to-date, we’ve been approximately $1.2 billion or 12% of preferred equity that was outstanding at the beginning of the year with 10% premium payments to the preferred equity holder of approximately $117 million. Preferred equity redemptions to date have resulted in elimination of over $93 million of annual preferred dividends.

As of August 2, rolling 12-month common shareholder distributions totaled $4.08 per share. Due primarily to the concentration of share repurchase in the third quarter of 2022, coupled with the current commodity price curve, it is likely that the cumulative distributions will fall below the $4 per common share during the third quarter. If we drop below the $4 redemption trigger, our ability to begin redeeming the preferred equity, again, will heavily be influenced by commodity prices. WTI prices would likely need to be higher than what the forward curve presently indicates for us to remain above the trigger for the remainder of 2023. Even if we aren’t able to continue redeeming the preferred equity for a period of time, we remain committed to our shareholder term program, including our $3 billion share repurchase program.

Our basic common share count is at the lowest since the third quarter of 2019, resulting in per share earnings and cash flow accretion to our common shareholders. Sustained efforts to significantly deleverage over the past several years have improved our credit profile, culminating a return to investment-grade status when the Fitch ratings upgraded OXY in May. We believe that our investment grade credit ratings reflect our exceptional operations, diversify the high-quality asset portfolio and our commitment to pay down debt as it matures. Our second quarter results and our full year guidance demonstrate solid progression towards another strong year for OXY. We look forward to reporting on additional progress in the year again. I will now turn the call back over to Vicki.

Vicki Hollub: Thank you, Rob. Before closing today, we’d like to briefly mention two low carbon ventures announcements that we made this week. We were glad to announce that Japan’s ANA Airlines became the first airline in the world to sign a carbon dioxide removal credit purchase agreement from our subsidiary, 1.5. We’re excited about that and happy to work with them. We’re also pleased to announce a first-of-its-kind agreement with our long-standing partners, ADNOC, to evaluate investment opportunities in director capture and carbon dioxide sequestration hubs in the U.S. and the UAE. With this agreement, we intend to develop a carbon management platform that will accelerate our shared net zero goals. We have many exciting developments taking place in LCV, and we look forward to providing you a more comprehensive update towards the end of this year. With that, we will now open the call for questions.

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Q&A Session

Operator: [Operator Instructions] The first question comes from Doug Leggate with Bank of America.

Douglas Leggate : Vicki, I wonder if I could focus on productivity which your latest slide deck is showing — you refer to it as the wedge wells with a quite frankly, stunning step-up in performance relative to prior years. My question, I guess, is the repeatability of that and the impact on how you think about your strategy? Because to summarize, you’ve suggested you would not seek to grow production meaningfully, if I’m interpreting that correctly. But this productivity would suggest that either you’re going to grow production as you did with your step-up in guidance or you’re going to cut your capital budget to hold the production at a flatter level. So I’m curious, are you prepared to take the production? Or is it going to get more capital efficient with lower CapEx?

Vicki Hollub : Well, we intend to keep our capital plan as we had it or at least the activity plan as we had it. I can tell you, Doug, I’m incredibly impressed with what our teams have done I’ve been in this industry for a very long time, and I’ve seen a lot of extensive work done to model conventional reservoirs over the years. And when we started our shale development, some thought it was more of a statistical play where you just go drill wells and maybe 25% of them would be really good and 75% would be okay. But we took the time in 2014 to step back and say that we were going to put together a team that could do the kind of work that needs to be done in shale. It’s much more complex than conventional. So we really focused on trying to make sure that we put together a team that could do the most sophisticated work on the subsurface possible, and they’ve done incredibly well.

And I would say, in the past two to three years, I was thinking that we were getting close to plateauing on our learnings and what we can do. But the teams continue to surprise me, continue to go beyond what I thought we would ever be able to do in this industry with respect to not only understanding the subsurface as well as we do, but also being able to understand how to get the most oil out of it. And — so where we are today is, I’ve now asked the teams to stop talking about it. We — for years, we’re sharing things that we were doing, and we’ve shared some things on the slides in the slide deck, but they had prepared a lot more to share with you today to highlight and map out the pathway that we’re using to get to where we are. But it’s just too important to our company, it’s — and to our shareholders to keep that proprietary because this is something that’s pretty phenomenal, I think.

And now we’re taking this, and we’re going to apply it to the Permian — I mean to the Powder River Basin. We’re using it. They’ve done incredibly well in the Permian. We’ve also taken learnings from the team in the DJ and moved those through the Permian. So we’re sharing ideas across business units. The next one will be the Powder River Basin, where while we did take an impairment on some noncore areas, they — we are excited about the Powder River. And I think Richard will say a little bit more about that later. But the Southern Powder River is, we’re seeing good results there. And our appraisal team is beginning to work in the northern part of the Powder River. And we’re going to take it also the same sort of concept about how to do it, we want to take to other areas within OXY.

And we think that by using a similar methodology with what our phenomenal team in the Gulf of Mexico has been able to do. They’ve done amazing things in terms of being able to see below-the-salt and to improve our success rate there. But I think you put this subsurface team for our shale development, but the approach they take, the methodology that they use with the ideas that our GoM team has generated and start really exploiting the various strengths. I think we take this and apply it to conventional reservoirs and applying this to conventional with the expertise that we have working those conventional reservoirs today, I think that there would be even more cross flow of learnings from conventional to shale and shale and conventional I think it’s beyond what anybody in the industry that I’ve seen or heard about it is doing today.

So with that said, to get back to your question on capital and production, we’re going to execute our program looks like it is going to result in a production increase, and we’re happy with that. We never said that we didn’t want to grow. We just don’t want growth to be the target. But the target is value creation. And that value creation comes from doing the developments when we’re ready to do them at the pace that generates the most net present value. And our teams are doing that, and they’re doing it incredibly well. So we’ll take what we’re getting here.

Douglas Leggate : I’ve got a very quick follow-up, and it’s kind of hard back to something we’ve talked about before, which is the legacy Anadarko portfolio. We know it dips in the second and perhaps the third quarter. My question is, when you rebound out of the fourth quarter as is ordinarily the case in that profile, have you lost any production capacity? Do you — what do you think the production capacity is today? And presumably, those are the highest margin assets in your portfolio. I just wonder if you could confirm that so we can anticipate what happens to earnings and cash flow in Q4?