Occidental Petroleum Corporation (OXY) Q2 2019 Earnings Report, Transcript and Summary

Good morning and welcome to the Occidental. Second Quarter 2019 Earnings Conference Call. All participants will be in listen-only mode. 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, 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 Vicky.

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 onetime costs incurred with the Anadarko Trans acquisition. Also in the second quarter, we returned approximately $600 million of cash to shareholders through our dividend, and as Vickie 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 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 decade’s long track record of innovatively recovering more hydrocarbons from conventional reservoirs than others could. We are continually improving and maximizing efficiencies and 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 maximizing recovery from other less mature assets. This is a competitive advantage for us in the future.

Thank you. Our first question will come from Doug Leggate of Bank of America. Please go ahead.

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 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 on 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 monetization’s. 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. I'd say that from an overall perspective, the good, the other good, really good thing about this portfolio is that we do have a lot more levers to pull with the combination of OXY and Anadarko in terms of monetizations. So there are some things that we can do, the joint venture with Ecopetrol was one example of how we can do something creative without negatively impacting ourselves. So we will look at those kind of opportunities and with respect to WES, we'll have to after close, when we can take a deeper dive into what's happening there. We can make some analysis of that, but I'll say that the good thing about it and the reason we're so confident about our asset divestitures, is that we have a lot of incoming calls about various things. And so we're able to -- we'll be able to high grade what we want to do over time. The difficulty we have right now is that we can't signal really what we want to do, because that would, that would compromise our ability to negotiate.

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

We always use advisors and so we have some advisors that are helping us with various things. So I think it's -- I think that as we look at lots of aspects of our business we'll be bringing in advisors to get their feedback. That should not signal anything in particular that we're thinking right now because we have no decision made, on that.

Understood. Thanks so much, Vicki.

Thank you.

Our next question will come from Devin McDermott of Morgan Stanley. Please go ahead.

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 were 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 real-- the full $1.5 billion capital reduction in activity level will come in 2020. And I would say that, 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 do you get started here before the end of August, when initially we thought it could be a much later than that that's 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 cost down going forward as well.

Yes, so our Resources business has been continuing to drive down OpEx as they get better with the artificial lift, the artificial lift in these shale wells was really challenging early on because it's too deep to make being pumping optimized. So too deep for that, too shallow, and the fluid production, a little bit too challenging for ESPs. So our team has worked really, really hard to find the right kind of artificial lift to use, and how to optimize it. And as they do that they are beginning to get much better at selecting the right kind of lift, and lowering the cost on that and of course, energy helps. And with respect to the EOR business in the US, it's our biggest cost one of our two biggest cost in the EOR business is the purchase of CO2 and energy in general. So, with respect to CO2 our Low Carbon business strategy is certainly going to help there because we're going to be able to ultimately install net power in the Permian Basin, which will further reduce our electrical cost, while also supplying a pure stream of CO2 for use in our operations. So once we get that -- start installing that in the Permian that will help a lot, but in the interim, we put in some solar already and plan to install a little bit more over the next year or so, and the solar is really good to reduce OpEx in our EOR operations and it reduces it at the most expensive part of the cycle. So that's very helpful. So it's going to take a combination of things over time to continue to reduce it, but we do have a strategy to do it, and I believe that that's going to be one of the key drivers to helping us start to take off for the growth in the EOR business in about 3 or 4 years.

Alright Great, thanks so much.

Thank you.

The next question will come from Roger Read of Wells Fargo. Please go ahead.

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 all that just maybe one big wrapper there, around that whole package.

Okay. Certainly, I appreciate the question. But let me -- let me address the OpEx one more point on that. I forgot to give kudos to Anadarko because there, they've really manage their OpEx well, they have a low OpEx and they are apparently doing a really good job to manage that. So the combination bringing that expertise in to us, for the types of wells that they're operating will be helpful too. But to your question, it's going to take us a little bit of time, because what we have to do, the way we do our business to our subsurface characterization is, we drill appraisal wells and that helps get us some data, so we get some petro-physical and geophysical data from the logs that we run when we drill the well. We take that data and we combine it with our 3D data -- 3D seismic data, combining those two, then we can perform data analytics on it, and with the data analytics now, we can take that even a step further with a paradigm shift, we had a couple of years ago, on how to look at the subsurface differently, with respect to how the frac is going to be perform in the zone as you're trying to pump it. So not to say too much about that, but that's, but we went through that process to get us to where our productivity was a couple of years ago or about a year and a half ago. Now what we've done is, we've been able to incorporate 4D frac designs, which is helping us to more accurately understand what's happening with the frac and then not only what's happening with the frac, but what's happening with the drainage area. And that's all really key to spacing and how you design your wells, where you land your wells and all of that. So our subsurface models are much more sophisticated today than they were about three or four, five years ago, and the kudos on that go to our subsurface teams that have worked it really hard, but also our business unit who watch these wells every day, figure out what's happening with them and collaborate with our subsurface team to really get down to trying to figure out what's happening in the subsurface. We've seen some operators that just do this on a statistical basis deal, but you really can't do that and optimize what you get from these wells and the value of these wells. This -- this takes a lot of science and it takes science that -- it goes beyond what we've ever had to do with conventional reservoirs. So the companies that that only drill conventional reservoirs around the world-they haven't dealt with what we are having to deal with here, from a complexity standpoint. We've conquered that, but it's taken a lot of data to do it. It's taken some patience and time, and it's taken getting it to the point where you know it's working, because now we can, and we're predictive with that we can blind wells that we've drilled in the past and run the model and the model will tell us --will match what we're seeing from the wells that we're producing. That's why we're very confident that this model, what we're using now will not only work in other areas outside the Delaware Basin, but in other basins. That's why we're very comfortable that in the D.J. and in the Powder we're going to see increased productivity there, based on the model that we're using. And we think it takes a lot of science and it takes patience so that's why we've said that some of our synergies we can't get in 2020, some of our synergies are going to come in 2021, because we're not going to spend dollars to do trial and error. We're really going to need to have our model and then that's going to take drilling some appraisal wells, and making sure that we have the 3D to match it, and the data analytics around it, but that's why it's going to take a little time to get all the synergies. But we're very confident that we'll get the synergies. Jeff, do you have anything to add to that?

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 close 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 is 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.

Our next question will come from Will Atkinson of UBS. Please go ahead.

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.

Yes. The reason for a joint venture, is we like the acreage in the Midland Basin, it's quality acreage, quality assets, and we think over time. Again, we haven't built us into our near-term model and we didn't include it in the --in how we evaluated this acquisition. But the upside over time is to use our enhanced oil recovery to get more of the reserves and resources out of the wells. So we are preserving our opportunity to get significant upside in the Midland Basin, through the application of CO2 enhanced oil recovery ultimately, and we think the more that we have of this, the more upside that we have over time and that we believe will give us an edge into the future on being able to get more out of existing wells rather than having to go drill new wells.

Perfect. Thank you.

Thank you.

Our next question will come from Pavel Molchanov of Raymond James. Please go ahead.

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.

Well you are giving me an exciting opportunity to talk about our low carbon business strategy and that, we are getting calls from all over the world, with people wanting our help to -- to help them also figure out how to capture CO2 from industrial sources, and then what to do with it and oil reservoirs. We have the processing capability, we have the ability to design it and we're the largest handler of CO2 for enhanced oil recovery in the world. So what's happening with these calls that we're getting for technical assistance is that, in some cases, there has been offers, allowing us to come in as a participant in the project, so these are not only opportunities to earn some revenue for our low carbon ventures business through technical providing -- technical services and valuations, but also to, to look at projects around the world for possible participation. So that's one way. That's one unique and different thing that that we're seeing happening to our group now, and that's really exciting, because as we go forward, there's going to be more pressure on companies to do something about their climate change story, and so that's making a lot of people get much more interested in what we're doing than just a few years ago. So that's one example. There -- we are always trying to look for ways to monetize things but without losing the potential eventual upside. So, we are getting creative and continuing to look at ways to do that.

Okay. Well since you mentioned ESG, let me follow up on that. I could not help noticing that your U.S. realized gas price in the quarter was $0.23 obviously some kind of one time shifts in there, but the -- is there a point where you would, have to resort to flaring in the Permian, because the economics of selling the gas are just lopsided.

We would not do flaring as a normal routine practice, we don't agree with that, and we wouldn't do it, so we will always try to find a way to utilize the gas and the net power concept that I just mentioned earlier, I should probably explain that a little bit better. Our team, last year or maybe it was the end of the year before, invested in a new way to generate electricity and it's called NET Power. What it does is, it takes natural gas combines that with oxygen and burns it together, and that's what creates electricity and it creates that electricity at lower costs, especially if you are using gas that cost like $0.10 or $0.15 or $0.20, which gives us this great opportunity because we're piloting that now, we have a pilot project where part-owner. We've invested in it and we are strategic partner to eight rivers, the group that developed the concept and put the pilot in place to start it. It's, it's in -- the pilot is just South of Houston here. So that's one of our solutions, is to put that in the Permian. It will utilize our gas that that if we sold it would make nearly as much. So it will, not only will it give us a way to utilize that lower-cost gas. It also, as I said earlier, provides that pure stream CO2 off of it, for use in our enhanced oil recovery. So it's a dual benefit of having a way to better utilize our lower priced gas, and also create the opportunity to you CO2 to increase our oil production. It's a really unique way of dealing with the scenario that we have in the Permian that we expect to be able to have that installed over the next two, three years. It's a little bit out, but in the near term, we don't see that we're going to have to flare. We have the capability to get it out it's just that it's certainly there. There are other ways to better utilize our gas and to get more value for it then 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.

Our next question will come from Phil Gresh of JPMorgan. Please go ahead.

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.

So in 2021, it would be the Resources business and it's at the capital level that we projected for 2020. So that would be capital for us and 2020 would be at the $6.6 billion -- have we given -- any additional. Okay. So the run rate of the 6.6, the actual 6.6 is in 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 cap, Resources' 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 obviously are the primary lever there. We've given you kind of a timeline of 12 to 24 months, we think will be on the early side of that. So, and then also as Vicki mentioned earlier, we have expect to have excess free cash flow and if need be, if we for whatever reason hit a snag we direct more of that than planned to delever, is at the very top of our list of priorities. We don't expect to need to do that. We think that that they asset sales will get us there and get us there fairly quickly. These things don't happen overnight, but. But we think we can easily get there in the timeline, we've allotted. The second thing I would say is that our target, we've said that 1.5 times debt-to-EBITDA that $60 oil WTI by the end of 2021 is kind of our target and base plan, and we're not going -- we're not going to stop there, that is we know for our weight class, we have too much debt, it's our highest priority to knock it down. We have the means to do it. We have a lot of levers, we can pull and so we're going to aggressively do that and we're not stopping at the end of 2021, but we expect to go through that, and get down too much even lower level -- leverage levels beyond that time. So we expect to basically be back to where we are, or better from a credit metric standpoint prior to the acquisition.

Okay, thank you.

Yes.

The next question will come from Brian Singer of Goldman Sachs. Please go ahead.

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 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 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, on a deeper level here in about a week. So I'll pass it to Jeff.

Hey, Brian. I think I got your first question was, what would it look like on a oil basis? It would look roughly the same. And the reason I would say that is, if you look at our, our oil cuts for Permian Resources over the last 2.5 years -- we've range from about 59 to 62. This year we've been right around 60, last year, we were 61 to 62, the year before we are just a hair below 60, so that's the kind of variability you get on total resources oil cut. So it wouldn't materially impact that curve when you look at it. Now obviously this year has been a percentage point or so less and that's just a function of where we're drilling different reservoirs that have different gas oil ratios with them, it's not anything that's problematic or something we didn't expect. It's just where we're developing.

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 learning’s 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?

Well, Ken's been very involved in that. We'll let Ken answer that one.

Yes, thanks. 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 were involved in it. We always believed it had long-term potential. So I think we're looking forward to the picking that up. I think our goal with Gulf of Mexico so far is to the 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.

Our next question will come from Leo Mariani of KeyBanc. Please go ahead.

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've had, we've for years, but even especially this year had extensive ongoing dialog with our rating agencies. We have a confidential arrangement with them, so we're able to share a little more information. All I would really say though is that you --so they are very well-informed on our plans and you can see some of the actions we're taking to today. In fact, some of that information or news comes out, but what I would say is that we've got a longer list and we have needs and so we think we can easily achieve our plans and I think the agencies understand 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 we 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 a Anadarko's second quarter in 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 a 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.

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.

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.

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