Occidental Petroleum Corp (OXY) — Q2 2019 Earnings Call Transcript

Thank you, Alison. Good morning everyone, and thank you for participating in Occidental Petroleum’s second quarter 2019 conference call. On the call with us today are Vicki Hollub, President and Chief Executive Officer, Cedric Burgher, Senior Vice-President and Chief Financial Officer, Ken Dillon, President, International Oil and Gas Operations, B.J. Hebert President of OxyChem and Oscar Brown, Senior Vice-President, Strategy, Business Development and Integrated Supply. In just a moment, I will turn the call over to Vicki.

Thank you Jeff and good morning everyone. Before covering our second quarter highlights, I would like to mention an organizational update and congratulate Robert Palmer. Robert was recently appointed to the position of President, Domestic Oil and Gas Operations with operational responsibility for Oxy’s domestic onshore oil and gas assets. Robert was most recently Senior Vice-President of Technical Support. He's an engineer, and has operating experience in the U.S., Peru, Oman, and Russia. He'll play a key role in integrating Anadarko’s domestic operations and ensuring that our combined assets deliver the highest returns for our shareholders. As many of you know we expect to close on our acquisition of Anadarko one week from today. The combination of our two companies will strengthen our long-term strategy and position us to drive profitable growth and return excess cash to our shareholders. We're truly excited about the many benefits that the combination of Oxy and Anadarko will bring to our shareholders, and we're encouraged by the feedback we've received from shareholders regarding the transaction and our discussions over the last few months. We also look forward to providing quarterly updates on Synergy capture, deleveraging and the integration process. I'd like to start this morning with the excellent operational and financial results that our core businesses delivered in the second quarter of 2019, along with some other key accomplishments. The strength of our integrated business model, confidence in our future performance and commitment to returning cash to our shareholders enabled us to increase our dividend for the 17th consecutive year. And we're committed to continue to increase the dividend. We returned approximately $600 million to shareholders in the quarter representing 33% of cash flow from operations before working capital. We remain focused not only on returning capital to shareholders, but also on generating higher returns on capital. Our ability to achieve best-in-class returns through investing in our high-quality assets continues to be evident as we generated a top-tier annualized cash flow return on capital employed of 22%.

Thanks Vicki. For the second quarter, we reported core earnings of $0.97 per diluted share and earnings of $0.84 per diluted share as all of our business segments continue to perform well. The difference between reported and core income is due to one-time costs incurred with the Anadarko transaction. Also in the second quarter, we returned approximately $600 million of cash to shareholders through our dividend, and as Vicki mentioned, increased our dividend for the 17th consecutive year to an annual rate of $3.16 per share. Over the past 17 years, our track record clearly demonstrates our commitment and ability to consistently grow our dividend and to ensure that returning capital to our shareholders remains a top priority. Oil and gas core income increased in the second quarter, compared to the prior quarter reflecting higher crude oil prices and volumes partially offset by lower domestic natural gas prices and a negative non-cash mark-to-market adjustment on carbon dioxide purchase contracts. We are very pleased to have lowered our operating costs on a per barrel basis across the board, both year-over-year and compared to last quarter. These cost improvements reflect higher volumes, improved downhole maintenance costs, and lower energy and surface operations costs. So a big congrats to our field operations teams, who continue to excel and lead the industry with low-cost operations. Total second quarter reported production of 741,000 BOEs per day exceeded guidance due to continued best-in-class execution and well productivity and Permian Resources, which exceeded guidance at 289,000 BOEs per day and International production exceeded guidance at 295,000 BOEs per day, driven by increased production in Colombia due to new exploration wells coming online. OxyChem surpassed the guidance with income of $208 million for the second quarter. Income decreased from the prior quarter primarily due to lower realized caustic soda prices along with fees received under a pipeline easement agreement executed in the first quarter.

Thank you, Cedric. Now I'd like to share how Oxy is uniquely positioned to extract the most value from this acquisition by applying our core competencies across the combined portfolio to maximize shareholder value. We have proven ability and a decades-long track record of innovatively recovering more hydrocarbons from conventional reservoirs than others can. We are continually improving and maximizing efficiencies in recovering hydrocarbons through water flooding and enhanced oil recovery. Today, we routinely recover more than 60% of the oil from large Permian conventional reservoirs and sometimes reach almost 70% recovery. Doing this cost effectively has required the development of extensive automation, advanced methods of artificial lift, and materials expertise, as well as downhole subsurface expertise. These tools will serve us well to maximize recovery from other less mature assets. This is a competitive advantage for us in the future.

Thank you and good morning, everyone. Good morning, Vicki.

Good morning.

Vicki on page 23 of your slide deck, I don't know if you should take the $6.6 billion as a capital guide, but it looks like that at least gives us an idea of how to frame our thoughts going forward. So that, if the combined company is doing closer to $9 billion, even adjusting for the African assets, that still suggests that the combined capital is already falling on your plan by substantially more than the $1.5 billion suggested. So I just wondered if you could speak to that, and related maybe speak to how the capital allocation on what you're thinking about as a preliminary thought, particularly in the Permian Basin. I've got a follow-up.

Yes. The combined capital was $9 billion, and we had committed to reduce activity levels to what would be the equivalent of $1.5 billion. But when you consider the synergies that we will achieve, that gets that $7.5 down closer to $6.6, as we achieve our $900 million of capital synergies.

So in terms of how that gets allocated in the Permian. Well, let me explain what's behind my question. To drop activity, the working interest that Anadarko had was only 40% on the acreage. So clearly dropping a rig there has a much lower impact on capital than dropping a rig in Oxy but then Oxy has much better wells. So I'm trying to think about how do we think about relative activity within that capital budget in the Permian Basin.

Well, we view it from an investment level, not a rig count per se. So if you're developing wells that have a lower working interest for you, then that's just more wells you're going to drill, potentially more wells you'll run but you'll get the same synergies. So we look at it from an investment standpoint, not from a rig level standpoint.

I understand, but presumably you'll give us greater details on that as we go forward. My follow-up is obviously this deal with Ecopetrol looks extremely capital efficient. Line of sight on asset monetizations. I wonder if you could share any additional thoughts and specifically, obviously, everyone myself included, is still quite focused on how you deal with the midstream of WES not least because it's giving you a better than $600 million income right now from the unit distributions. So any updated thoughts on those and I’ll let someone else jump on…

Thanks, Doug. From an overall perspective, the positive aspect of this portfolio is that we have many options available with the combination of OXY and Anadarko in terms of monetization opportunities. For instance, the joint venture with Ecopetrol demonstrates how we can pursue creative solutions without harming our interests. We will explore similar opportunities, and regarding WES, we'll need to assess the situation in-depth after the close. This will allow us to perform a thorough analysis. However, the encouraging aspect is that we are receiving numerous inquiries about various options, which enables us to prioritize our decisions over time. The challenge we currently face is that we cannot clearly indicate our intentions, as that may hinder our negotiation capabilities.

Can you confirm the press speculation about whether or not you had hired an advisor on WES?

We always work with advisors, and we have some assisting us with various matters. As we consider different aspects of our business, we plan to involve advisors for their input. This shouldn’t indicate any particular direction we are contemplating right now, as no decisions have been made.

Understood. Thanks so much, Vicki.

Thank you.

Good morning and congrats on the solid results.

Good morning.

I wanted to start by actually following up on one of Doug's questions, just on synergies and also some of the activity in capital reductions. With the deal closing now potentially next week, it’s earlier than the initial target. So I was wondering if you could address how, if at all, that impacts the timing of synergy realization versus the initial plan, and also on the $1.5 billion reduction in growth spending, how quickly post-close can that occur? Is that something that happens fairly immediately or will it be staggered over time and where will those reductions occur? If you can provide some guidance on that.

So we're going to meet our capital plan for this year. So, we'll meet the $4.5 billion for ourselves this year, we'll have to after close look at what's happening with Anadarko to determine what we do with the rest of their spending for the year. But the full $1.5 billion capital reduction in activity level will come in 2020. And I would say that, getting that really depends on what we see after close and certainly the acceleration of the closing date is going to help us get a jump-start on our synergies. We had committed to $1 billion in synergies in 2020. So being able to get started here before the end of August, when initially we thought it could be much later than that is going to be very helpful for us.

Got it. Great. And then my second question's actually on the OpEx side, just for Oxy stand-alone. You had some nice reductions quarter-over-quarter there, and it looks like some of the drivers are a mix between lower downhole maintenance and lower energy costs. I just wonder if you could comment a bit, in a bit more detail on what's driving those cost reductions, opportunities for further cost reductions over time, and how initiatives like utilizing solar power in the EOR business might drive costs down going forward as well.

Our Resources business has been successfully reducing operational expenses as they improve their use of artificial lift in shale wells. Initially, the depth of these wells posed challenges for optimal pumping, and fluid production was also difficult for electric submersible pumps. Our team has put in significant effort to identify and optimize the appropriate artificial lift techniques. As they continue to refine their selection processes, they are achieving better outcomes and lowering costs, aided by favorable energy conditions. Regarding our Enhanced Oil Recovery (EOR) business in the U.S., one of our largest expenses is the purchase of CO2 and energy. Our Low Carbon business strategy will support this by enabling us to implement net power in the Permian Basin, which will lower our electrical costs and provide a pure stream of CO2 for our operations. Once we start this installation, it will be very beneficial. In the meantime, we have already installed some solar power and plan to add more over the next year. This solar energy significantly aids in reducing operational expenses in our EOR operations, particularly at the most costly phases. It will require a combination of strategies to achieve ongoing reductions, but we have a clear plan in place, which I believe will be vital for driving growth in our EOR business in about three to four years.

Alright Great, thanks so much.

Thank you.

Yes. Thank you. Good morning. Coming back to some of your comments Vicki, about the ability to evaluate the acreage, decide where you want to move forward, just curious how, how long it takes to do that? And as a second part, or the second question really, if we look at what's happening with some of the other players in the Permian today, if you could give us a little bit of an idea, tying that evaluation into the performance you've had and how you've been able to avoid some of these problems we're seeing: the too much well density, or the parent-child issues, just maybe one big wrapper there, around that whole package.

I appreciate the question and would like to address the operational expenses. First, I want to commend Anadarko for their effective management of operational expenses, which are low, indicating they are doing a great job. Their expertise will be beneficial for us in handling the types of wells they operate. However, it will take some time for us to implement this, as our business model relies on subsurface characterization through drilling appraisal wells. This process allows us to gather valuable petrophysical and geophysical data from the logs obtained during drilling. We then integrate this data with our 3D seismic information, enabling us to perform data analytics more effectively. Recently, we have made significant advancements in our approach to understanding the subsurface, especially regarding how fracking will perform in various zones. Our progress includes the incorporation of 4D frack designs that enhance our understanding of both fracking events and related drainage areas, which is crucial for well design and placement. Currently, our subsurface models have become much more sophisticated compared to three to five years ago, thanks to the efforts of our subsurface teams and business units who monitor well performance and collaborate closely. It's important to note that while some operators may rely on statistical methods, true optimization of well performance requires a deep scientific approach that goes beyond that used for conventional reservoirs. We've tackled the complexities inherent in our operations, but it has required extensive data, patience, and time to confirm that our methods are successful. Our predictive capabilities now allow us to analyze previously drilled wells, matching model predictions with actual production results. This gives us confidence that our models will not only apply successfully within the Delaware Basin but also in other basins like the D.J. and Powder, where we anticipate increased productivity. We believe achieving our synergies will necessitate time and careful execution, which is why we have indicated that some benefits will not materialize until 2021. We are committed to avoiding trial-and-error approaches, preferring to rely on well-established models that require further appraisal drilling, supporting 3D data, and appropriate data analytics. Thus, while we expect synergies to take time, we are very confident in their eventual realization. Jeff, do you have anything to add?

Hi, Roger. The only thing I'd add, Vicki did a great job covering that, but I think, and you know this that is our secret sauce. So I mean we've been like Vicki said, advancing that for years now and not only is it our secret sauce, it's a secret sauce worth having, and because of the value that it creates and I mean a couple of things that she hit on, I think are really important to stress, not just the integration of the work closely with geo-modeling, geo-mechanics, petro-physics, stimulation, reservoir simulation, but it's really the combination of the people, tools and data, because the thing we get asked all the time by other people is, how easy is it replicated. And I think the important thing is, if you remove one of those things, the people, the tools or the data, the other two don't work as optimal as they will if you have them altogether. So that's why we show on Slide 18, 19 and the performance results. It's not just one thing that goes there you need all of those ingredients to really extract the value, that's what makes us so excited when we look at other reservoirs and being able to apply it because we think it definitely works, not just in the Wolfcamp or the Bone Springs, but in all unconventional reservoirs.

Thanks, build a better mousetrap and you win. Congratulations.

Thank you.

Good afternoon. I was wondering if we could touch on the rationale for a joint venture, rather than a complete divestiture, especially given the depth of your inventory across the Delaware.

The reason for a joint venture is that we value the acreage in the Midland Basin; it consists of quality assets. Over time, we believe this decision will be beneficial. We haven't factored it into our near-term model or the analysis of the acquisition. However, our potential for long-term growth lies in utilizing enhanced oil recovery techniques to extract a greater portion of reserves and resources from the wells. By doing so, we are maintaining the opportunity for significant upside in the Midland Basin through CO2 enhanced oil recovery. We think that increasing our capabilities in this area will provide us with an advantage in the future, allowing us to maximize output from existing wells rather than resorting to drilling new ones.

Perfect. Thank you.

Thank you.

Yes, thanks for taking the question. As you think about deleveraging, obviously the Ecopetrol deal marks the first step. Are you seeing other instances of this kind of rather unusual model, where a player that may not be in a particular geography that you're operating in, is going to rely on you for skill set development and sort of that kind of active partnership beyond simply selling acreage?

You are giving me an exciting opportunity to discuss our low carbon business strategy. We are receiving inquiries from around the world from people seeking our help to capture CO2 from industrial sources and determine how to utilize it in oil reservoirs. We possess the processing capability and design expertise, and we are the largest handler of CO2 for enhanced oil recovery globally. The technical assistance calls we’re receiving often lead to offers for us to participate in projects. This presents us with opportunities to generate revenue for our low carbon ventures through technical services and valuations, while also exploring potential project participation worldwide. This is a unique development for our group, and it’s quite exciting. As we move forward, companies will face increased pressure to address climate change, which is driving heightened interest in our initiatives compared to just a few years ago. That’s one example of what we’re experiencing. We are continually looking for ways to monetize opportunities while preserving the potential for future upside, and we are getting creative with these approaches.

Since you mentioned ESG, I wanted to follow up on that. I noticed that your U.S. realized gas price for the quarter was $0.23, which seems to include some one-time shifts. Is there a point at which you might have to resort to flaring in the Permian due to the unfavorable economics of selling the gas?

We do not plan to make flaring a standard practice and do not agree with it. Instead, we will always seek ways to utilize the gas efficiently. Recently, our team invested in a new method for generating electricity called NET Power. This technology burns natural gas with oxygen to produce electricity at lower costs, particularly when gas prices are around $0.10 to $0.20. We are currently piloting this concept in a project just south of Houston, where we are a part-owner and have partnered with Eight Rivers, the developers of the project. This approach allows us to make better use of our lower-cost gas and also produces a pure stream of CO2, which can be used for enhanced oil recovery. This dual benefit will help us utilize our gas more effectively while also increasing our oil production. We anticipate having this system installed in the Permian over the next two to three years. In the short term, we do not expect to resort to flaring, as we have alternative ways to extract value from our gas beyond selling it for $0.23.

Hey, Pavel one other thing I'd add to Vicki's comment. EOR, so injecting we've been advancing EOR not just with CO2 but also hydrocarbon gas. And the cheaper the hydrocarbon gas, the better the economics get for EOR because you're basically replace and oil for gas. So that's another thing, we continue to advance, so that you don't flare. But you can extract value from.

Okay. Very useful. I appreciate it.

Yes. Thanks for taking my question. First, Vicki, you made a comment in your prepared remarks, you expect a combined Permian business to be free cash flow positive at $45 WTI in 2020. So I was just wondering, for a little more detail on that, first part would be is that including EOR or is it just more of the standalone Resources business? And then, what level of rig count and CapEx and just underlying details to help us think about that in the context of this overall CapEx reduction plan that you have, through 2021. Thanks.

In 2021, the Resources business will follow the capital level we projected for 2020, amounting to $6.6 billion. This figure represents the actual run rate for 2021.

Right. So you are going from $9 billion to $6.6 and I think you said in 2020 you expect Permian Resources to be free cash flow positive at $45. Correct?

That's correct.

Okay. And so I would be an equivalent level of CapEx baked into the $6.6 to get to that.

Right, let's say the $7.5; make sure you use the run rate of 7.5% before the synergies of $900 million, which will be fully achieved in 2021.

Okay. Okay, got it. Second question, I guess just on the balance sheet, Cedric any latest thoughts here. I think your target all along has been to get to sub 2 times. You've given numbers with and without WES obviously you announced the JV today but any new thoughts there about how quickly you can get to that leverage level and what other levers you might be wanting to pull to get there? Thank you.

Yes, thanks, Phil. The asset sales are clearly our main strategy. We estimate a timeline of 12 to 24 months, and we believe we will lean towards the earlier end of that range. Additionally, as Vicki mentioned earlier, we anticipate generating excess free cash flow, and if we encounter any challenges, we can allocate more funds towards reducing our debt, which is our top priority. However, we do not foresee the need to take that action, as we believe the asset sales will achieve our goals fairly quickly. While these processes do take time, we are confident we can meet our timeline. Our goal is to reach a debt-to-EBITDA ratio of 1.5 times with $60 oil WTI by the end of 2021, and we intend to continue beyond that. We recognize that we currently have too much debt for our size, and reducing it is our highest priority. We have the resources to accomplish this and various options at our disposal, so we will pursue this aggressively. We expect to attain even lower leverage levels after 2021, returning to or surpassing our previous credit metrics before the acquisition.

Okay, thank you.

Yes.

Thank you. Good morning. I had a follow-up actually, just a series of questions with regards to slide 18, given the strong productivity gain shown there in every year but particularly 2019. The first is, if we looked at this on an oil-only basis with the gap between 2018 and 2019 look the same, second, what do you see as the longevity to continue to drive productivity gains on Oxy's space assets and, third is, what is your base case I realize is an appraisal process to that you need to go through, but what is your base case for how Anadarko well performance and well costs will ultimately compare relative to Oxy's?

I'll take the second one. And I'm going to toss the first two to Jeff. We really haven't gotten into their specific data well enough to know, we see the results of the wells, but what we want to do is dive a little deeper, see what data they have, and do our full analysis on it before we can answer a question like that but, we'll be doing that as quickly as we can. And fortunately, getting them to start doing that on a deeper level here in about a week. So I'll pass it to Jeff.

Hey, Brian. I believe your first question was about how it would appear on an oil basis. It would look approximately the same. The reason I say that is, if you examine our oil cuts for Permian Resources over the last two and a half years, we've fluctuated between around 59 to 62. This year we've been close to 60, last year we ranged from 61 to 62, and the year before we were just under 60. That's the level of variability you can expect with total resources oil cut. Therefore, it wouldn't significantly alter that curve when you analyze it. This year has been about a percentage point lower, but that's simply due to the different reservoirs we are drilling, which have varying gas-oil ratios. It's not an issue or something unexpected; it's just part of our development strategy.

Great, thanks.

And then what was your other question, Brian. I'm sorry.

The second one was the longevity to continue to drive productivity gains. Just on the Oxy assets. In other words, how many more years in the tank do you think you have faced in the processes of that you've, the technologies that you've talked about.

Yes, again, I mean, this one is so hard. It is, it's always difficult to know, we can see what the teams are advancing. I mean, every time we talk to the teams working on advancing our performance, I just kept blown away at the things they're thinking about, and working on , like we talked about the 40 models that Vicki talked about, when you look at that our ability now to understand how frac geometry changes, not only in a single well over time, but how it changes in a multi-well section development over time. Two years ago I never thought we would be able to understand how frac geometry changes over time, or how wells would interrelate with each other given the time component. Now that we can understand that, we're able to figure out better landings, better placements, better frac designs, that continue to propel the advancements. So I would answer it is, I don't know how we will improve next year, but I guarantee you that the teams are going to figure out how they continue to make well performance better, and they've done it every year since 2015 when we really started aggressive development. So it's hard to believe that's going to stop any time soon. I think it will just come from different areas, different things will drive it, just like different things drove it from '15 to '16 and '17 to '18 and so on, but I do continue to think or we're going to get better and if you put this over and you focused on value instead of rate. I think that has even more running room than just rate and volume performance, but on the value side.

Great, thanks. And then lastly on outside of the Permian, can you talk about any key learnings in the Anadarko, Gulf of Mexico are DJ Basin assets and any impacts that those have on your commitment to maintaining and retaining those assets in the going forward combined company, and on the capital and growth outlook there?

Yes, we're looking forward to operating again in the Gulf of Mexico. I think one thing I have to say, we're operating as two separate companies at this time, but I think we're really pleased of our former asset Horn Mountain returning to Oxy again, we were involved with it since the Varstar days even before BP was involved in it. We always believed it had long-term potential. So I think we're looking forward to picking that up. I think our goal with Gulf of Mexico so far is to deliver long-term stable cash flow through step wells close to the existing facilities. So very similar to Anadarko's approach and with Horn Mountain back I think we can see that potential running in for some time.

Great, thank you.

Hey guys just wanted to follow up a little bit on the asset sale topic here, just wanted to get a sense, has kind of OXY at this point really identified what they want to sell. I know obviously, you'll be price dependent on ultimately what you sell, but you feel like you kind of have your punch list sort of down. And have you guys integrated the rating agencies as well in kind of some of these discussions, as you look to hit your leverage targets over time.

I would say that we certainly, we have a punch list of things that we'd like to do, and that's why we want to keep that quiet for our negotiating power, but we do have a punch list and every now and then something comes up that that's unexpected and out of the ordinary, and we look at those too. So that's why we're really encouraged that we'll be able to achieve our targets and Cedric will address the credit agencies.

Yes, we have had extensive ongoing discussions with our rating agencies, especially this year. We have a confidential arrangement with them, allowing us to share a bit more information. I would say that they are very well-informed about our plans, and you can see some of the actions we are taking today. In fact, some of that information or news gets released. However, I want to emphasize that we have a longer list of needs and believe we can easily meet our plans, and I think the agencies recognize that.

Okay. And I guess just a brief follow-up to that, is there any update at all on the timing of the Africa sale and then additionally, Cedric obviously you got off the significant hedge. Are you guys considering other hedges for 2020, given that was portion of your production? But you still have significant remaining oil production unhedged?

I'll take the Africa question, we really, until after close would really can't make any comments on timing or anything like that, we'd prefer to get a little bit further down the road and we'll update you when we can.

So on the hedging. We're very pleased with what we're able to pull off in actually a very short period of time I was skeptical, we'd be able to achieve what we've done. But as Vicki mentioned earlier in her prepared remarks, we've hedged just under 40% of our combined company oil volumes if you take Anadarko's second quarter and our second quarter for oil volumes just under 30%, 40% there. And then if you exclude PSC volumes for us, you get approaching almost 50% of our volumes hedged. If you look at not just in the second quarter basis, so very pleased with the position, not going to be speculative about future hedging doesn't help us to do that other than to say, we'll be opportunistic. I would expect this to be primarily focused on when we're in a more leveraged situation this is giving us a great deal of additional support in a low price environment, potentially in 2020. But beyond kind of the deleveraging that we've talked about, we're not I'd expect us to kind of go back to the way we've been, which is very little to no hedging but we'll be opportunistic and we could see ourselves putting on more hedges or possibly not doing that as well.

Okay, thank you.

Yes, I'd like to say thanks to the OXY employees for operating safely and delivering great results. And to say we're excited to bring on the Anadarko employees, looking forward to that and then it can't happen soon enough. Thank you all for your questions and for joining our call. Have a good day.