Good morning and welcome to of the Occidental Petroleum Corporation Fourth Quarter 2018 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] 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, Laura. Good morning, everyone, and thank you for participating in Occidental Petroleum's fourth quarter 2018 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; and BJ Hebert, President of OxyChem. In just a moment, I will turn the call over to Vicki. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements, as more fully described in our cautionary statement, regarding forward-looking statements on slide 2. Our earnings press release, the investor relations supplemental schedules, and our non-GAAP to GAAP reconciliations and the conference call presentation slides, can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Vicki. Vicki, please go ahead.

Thank you, Jeff, and good morning, everyone. Today I'll begin our fourth quarter results followed by our 2018 achievements, a plan for the year ahead and an overview of the benefits of our integrated business model. The fourth quarter of 2018 wrapped up a successful year for Oxy both financially and operationally. We returned $900 million to shareholders in the quarter through a combination of dividend and share repurchases. Our continued focus on increasing returns for our shareholders was achieved due to outstanding performance from all three of our businesses in a changing market condition. Despite WTI falling below $43 a barrel in the quarter, we posted core earnings per share of $1.22 and generated the highest semiannual level of operating cash flow since 2014, making the second half of 2018 our strongest six-month period since our portfolio optimization. Permian cash operating cost were the lowest this decade, driven by the long-term high-return investments that we're making such as in facilities and infrastructure. We operate our assets with a full lifecycle view. Our investments will continue to provide payback in the form of lower cost as our production base expands. OxyChem and our Midstream business both achieved record fourth quarter earnings as a result of our integrated business model, which enables us to take full advantage of market conditions such as delivering higher realizations from our Permian take away position. In 2018, we grew cash flow to a level that exceeded both capital expenditures and our dividend, a key achievement we have been working toward since completing our portfolio optimization. Organic cash flow growth was driven by prioritizing the allocation of capital to opportunities that generate the highest full cycle returns. We are pursuing cash flow growth with two key objectives in mind, first and foremost to generate a higher…

Thanks Vicki. As Vicki highlighted, we are pleased to have continued repurchasing shares, allowing us to return $900 million of cash to shareholders during the fourth quarter and over $3.6 billion in 2018 including our dividend. On slide 10, I'd like to start with our earnings which improved across all segments year-over-year. For the fourth quarter we had core earnings of $1.22 per diluted share and reported earnings of $0.93 per diluted share. The difference between reported and core income is attributable to an impairment charge of $220 million which was driven by lower oil prices. Earnings also included a net tax benefit of $224 million, which significantly decreased our fourth quarter effective tax rate and it consisted of $100 million for additional EOR tax credits and tax credits related to U.S. export sales; $99 million for releasing a foreign withholding tax accrual; and $25 million for changes related to the 2017 Tax Reform Act. Oil and gas core income decreased in the fourth quarter compared to the prior quarter, reflecting lower oil and NGL prices as realized prices declined by 10% and 23% respectively from the third quarter. Fourth quarter oil and gas results included a non-cash mark-to-market change related to our CO2 purchase contracts, as well as higher operating and DD&A expenses in Qatar as a result of the ISND contract expiration later this year. Total fourth quarter reported production of 700,000 BOEs per day was above the midpoint of our guidance, due to the continued best-in-class execution and well productivity in the Permian Resources, which resulted in 250,000 BOEs per day during the quarter at the top end of the guidance range and represents an exit to exit increase of over 57%. Total international production of 290,000 BOEs per day was up slightly lower than guidance primarily…

Thank you, Cedric. 2018 was an outstanding year for our combined Permian business as we improved the value of our conventional and unconventional assets through our value-based development approach. We're able to add high margin barrels and generate great returns on our investments. We replaced 216% of our production with new reserves through industry-leading performance and successful appraisal. Combined total year production per Permian Resources and Permian EOR grew 77,000 BOEs per day compared to 2017, and exceeded 400,000 BOEs per day in the fourth quarter. We lowered Permian operating cost 9% by utilizing advanced data analytics on our artificial lift, implementing new water recycling technology, and improving maintenance efficiency across the Permian. Permian Resources has a simple model that I love called 'leave no doubt' which refers to our relentless pursuit of generating the best returns in the industry. In 2018, we made tremendous progress toward achieving this principle as we increased our total production 52% and exceeded our initial 2018 guidance by 12,000 BOEs per day. Our subsurface characterization improvements have driven breakthroughs at an accelerated pace. By integrating advancements in geoscience with our 12,000 square miles of 3D seismic and subsurface characterization models, we are rapidly achieving step change improvements in well design and placement. In 2018, we improved our average six-month cumulative production by 25% compared to 2017. Over the last 12 months OXY has delivered 40% of the top 50 horizontal wells in the basin which is the most for any operator while only drilling 5% of the total wells over the same time period. On the capital efficiency front our operational improvement initiatives continue to drive efficiency, compressed time-to-market, and lower full cycle cost. In 2018, we increased our fee drilled per day by 19% and we drilled record 15-day 10,000-foot wells measured rig…

Thank you, Jeff, and good morning, everyone. As Vicki and Cedric mentioned our 2019 capital plan focuses on investing in projects that grow cash flow and generate the highest returns. Today we're pleased to share the details of onshore Block 3, which is a new 35-year concession in Abu Dhabi. We feel honored to expand our relationship with ADNOC and the first award of its kind onshore. With Block 3 as well as the new onshore blocks landed in Oman and Colombia, we feel we have established the clear pathway for OXY to grow sustainable cash flow from our low-decline long-life international assets. We certainly appreciate the recognition as a partner of choice. As shown on slide 16 Block 3 covers an area of approximately 1.5 million acres, which is slightly greater than the total of our net unconventional acreage in the Permian. We have high expectations for this block given its location between the prolific oilfields of Abu Dhabi and Oman. It's also adjacent to our outhouse gas project. As I mentioned in the last call, our regional geological knowledge is best-in-class and it continues to develop. We utilize that experience in preparing our initial stacked pay prospect infantry for Block 3. In 2019, our capital spend in Block 3 will be modest. The initial scope of work involves participating in the state-of-the-art 3D seismic acquisition and degradation. Our plan is to initiate drilling in 2019. Expanding our footprint in UAE in such a meaningful way, especially through the 35-year concession has allowed us to enhance our long-term international portfolio at an attractive price of entry. Additionally in Abu Dhabi, we continue to look at cost effective ways to debottleneck the Al Hosn Gas facilities. In Colombia, in partnership with EcoPetrol, we have signed an agreement to develop Blocks…

Thank you, Ken. Before we go to Q&A, I'd like to emphasize that we believe the strongest oil and gas companies of the future will be those that have a shareholder-focused value proposition and our structure and sustainability to withstand the oil price cycles, while also maintaining a social license to operate in the world in general and operate in a low carbon world. Our value proposition will continue to deliver a growing dividend in the upper quartile or maybe best-in-class returns to our shareholders, while also growing oil and gas production 5% to 8-plus-percent annually. Unlike many companies in our sector, we delivered this through one of the longest downturns our industry has faced. Our company is primarily an upstream oil and gas company with integrated midstream and chemicals business, so that adds significant value and provides important support during low oil price cycles. The diversification of our upstream oil and gas business also provides strength in periods of low oil price along with substantial upside in higher oil price cycles. This upside is made possible by our short-cycle, high-return, unconventional assets in the Permian, along with a new conventional opportunities that we just picked up in Oman, Colombia and Abu Dhabi. Our strength in the low price environment bolstered by our very low decline enhanced oil recovery projects in the Permian, Oman and Colombia. I'm specifically referring to our CO2 and water plugs in the Permian, our water plugs in northern Oman, our steamflood in Mukhaizna which happens to be one of the largest steamfloods in the world and our new TECA steamflood in Colombia. Our production sharing contracts and our road to decline gas projects in offer and Al Hosn also provides significant support in low oil price cycles. I believe there is no other oil company’s…

We will now begin the question-and-answer session. [Operator Instructions] And our first question will come from Roger Read of Wells Fargo.

Yeah. Good morning. How are you? Hopefully, everybody can hear me? Yeah. I just wanted to kind of come at it from the capital discipline side. Obviously, the presentation you put out in January highlighted that you would live within cash flow given the oil price. Good to see the higher growth rate now 9 to 11 versus the 10 to 8. But just really my question is along the lines of trying to think about how Oxy and maybe the broader E&P space fits here, with what you're trying to do versus maybe what we’re seeing out of the super majors in terms of increasing activity in the Permian, and then we haven't seen the magnitude of drop-off, I think we would've expected out of some of the private companies. So as you think about capital returns, capital discipline, but then maybe a little bit of the risk being squeezed between these other two components, how do you kind of square that circle up? And what do you see as the driver for how you want to run the company?

The driver for us is to maximize returns. And so the way, we put together our development programs is, we don't try to design for peak rate production. We really try to design all of our development programs and our comprehensive development of the Permian with the synergies between EOR and resources. We try to design that in a way that creates the highest difference in value. And I can tell you, we're not trying to outpace the majors. We're trying to outperform the majors. And I think that, we're clearly doing that in the Permian at this time. I think it's – from the standpoint of our programs versus theirs. We're doing a lot more with the rigs that we employed today than many other companies are with almost double the rigs that we have. And our focus is more on making sure that every dollar we invest creates more value. And so we're trying to really work the side of maximizing recovery from the reservoir and minimizing our cost. So it's not a race for us to outpace them. And we have teams that have built our infrastructure and our position and our relationship in a way that grow as they will they will not impact our operations. We believe we are perfectly positioned to be able to do the things we need to do. We have the takeaway capacity. We have the export capacity. We have the infrastructure within the Permian. So we're positioned there, and I think in a catch-up mode at this point.

Okay. Thanks. And then Jeff just the part you mentioned about data analytics, I understand it's helping. Is there any quantification that you can offer on that front? Or either what's been captured to-date or what you would expect going forward?

Yes, I think the real quantification is when you look at performance improvements and ultimately what's going to play out from a capital efficiency standpoint. So, I think when we point to our well performance and our development performance, all of that -- or a good portion of that is being driven with how we utilize data analytics. And the thing I'd point to the most is as you can see our development; our performance isn't based on a lot of trial and error. It's largely based on our ability to go in, understand the reservoir from a subsurface standpoint, utilize the huge amounts of data that we have in an effective way, and come up with an optimal development that delivers very good results from the beginning, not in a trial and error mode, where we have to deploy a lot of capital that gets underutilized. And so it's almost unfair to point out we used artificial lift because that's where we've made some huge breakthroughs, but we are applying data analytics in almost every aspect of the business with sub-surface characterization is the one we talked about the most because it's so impactful. But it's being used universally across the business and there is example after example on how that's creating value.

Great. Thanks. And it's okay from our perspective if you want to be unfair when we're thinking about other stocks.

Thanks Roger.

And our next question will come from Bob Morris of Citi.

Thank you. Good afternoon everyone. My first question, Vicki, is with regard to again the capital discipline side, you've capped the budget this year at $4.5 billion so you can return any cash generated above $50 a barrel to shareholders. But then beyond this year, you're stepping back up the CapEx and to do that you're spending -- you end up spending cash above $50 a barrel and I know you have to do that to still hit your 5% to 8% production growth target. But to what extent would you consider continuing what you are doing this year just sort of cap any spin to return cash above $50 per barrel to shareholders? I know that would put your growth at the lower end of the range and you can still obtain double-digit growth out of Permian Resources. So, is there a scenario where you may continue, like you do in this year, beyond this year to then return any excess cash above $50 a barrel to shareholders?

Our assumption for 2020 was based on our belief that oil prices will be $60 in 2020. And if that's the case, with a budget of 5 to 5.3, we would still be able to return cash to shareholders. And we want to continue to, at some point, grow our dividend more meaningfully and Cedric will talk about that a little later but our 5 to 5.3 capital budget would allow for us above a $60 environment to return cash and that's something that we've always done as I mentioned in my script and something that we'll continue to do. We think of balance to return of cash to shareholders through repurchases and strong dividend with a right balance between those is important to continue.

Sure, I appreciate that. So, my second question is for Cedric. Cedric last quarter you mentioned that M&A was part of OXY's DNA and so at this stage, do you see the A&D environment more conducive to opportunities for OXY out there or have you grown more optimistic with regard to potential acquisitions or adding to your portfolio in the Permian?

Well, it's -- we've certainly seen a few -- some activity picking up in M&A. I would say from OXY's perspective, we're always aware and we keep ourselves very informed. We look at a lot of opportunities, it’s rare when we don't get a call and when there's something coming to market. But if you look at our organic growth opportunities as we've described, they're robust across the globe and across each business sectors. So we don't have to do a deal and we only want to do a deal, if it's going to be very accretive to our shareholders and for values. So we do see ourselves over the long run being a consolidator. That's one of the things that goes with -- or opportunities that goes with being a low cost producer. We consider ourselves one-off, if not the lowest cost producer in the basins and places we choose to operate. So I think, there will be consolidation opportunities over time as I said before, however it needs to be a compelling deal for us and for our shareholders and that's how we look at it.

Is there an advanced catalyst that sort of sparks an increase in consolidation not necessarily for OXY, but across the Permian at some point?

That's hard for me to predict. You know there's certainly a lot of assets and small private companies that don't seem to have the scale or the technology to put themselves in a low-cost producer status. So at some point perhaps those come to market at more reasonable prices. There have been a few, but it's hard to predict those things. We're certainly ready when that happens. And then otherwise there are other operators that are trying to figure out, if they can make the breakthroughs that we have and so on and it will just be something that will be -- to be determined. It's hard to predict.

Hey Bob, this is Jeff. I mean, the only thing I'd add to what Cedric said, if you look at the Permian history it's consolidated when the business got really hard, prices drop, margins get squeezed and then consolidation generally happen. I think when you look across though in conventional space, you all know better than anyone, the business continues to get harder not easier as people move to full section development, having to operate with lower operating cost, manage infrastructure, large KOLs all those things. So we're definitely progressing to where you're starting to see differentiation between those that are good operators and those that are maybe aren't as good.

No, I agree. OXY is positioned very well in that type of environment. So, I appreciate your comments. Thank you very much.

The next question comes from Paul Sankey of Mizuho.

Good afternoon. Just a couple of points of clarification on your presentation, if I could, on slide 4 you stated that you drilled less than 5% of the horizontal wells in the Permian, but have 40% of the top 50 well results. Could you expand on that a little bit in terms of what you're comparing and how you're comparing that? Thank you.

Sure Paul. I'll take that. Basically if you go to anyone who has the deck opened slide 31 shows that. So there's lots of ways to measure performance. Specific measure that we use is the cleanest as to where we look at over the last year top 50 wells from an IP standpoint, where are they? Who has them? And then you can see on the left, we've got 20 of the top 50 over the last year. We've showed this for several quarters, so you can see moves around and how it progress. And 40% of those were the top operators when you look at the data. Another thing we add to it, on the right, which is something we often talk about is, we are able to do it with less proppant. And the reason we highlight that is twofold; one, it’s a big cost driver. Obviously you all know, the more profiting in pump, the more cost. But two, its really indicates how we customize our development. You can see we don’t have a universal number where we use 2,000 pounds per foot on every well, we vary it. And that’s a function of our development strategy and our understanding on the subsurface to get really, really good wells in a customizable way. The other thing I'd point you to, Paul, one thing we put in there, because the question we keep getting asked all the time is, are results continuing to improve? And it seems like every time we show a comparison of results, they are normalized by something, or you cherry pick which wells you use, you exclude this, you include this. So we include a slide in this deck that I'll point out slide 28. So what this slide is, it shows our six-month performance for every horizontal well. We didn't cherry pick which wells that go in there, all appraisal wells, all development wells, all of our wells are in every year that you can see for 2015, 2016, 2017 and 2018, across Midland Basin, New Mexico, Texas, Delaware and it answers the fundamental question of are we able to continue to improve? And you can look at each year and there's reasons that vary on why we're improving. Some years, it may be more of the lateral length, some years it may be better completions. Every year is being driven by a better understanding of the subsurface. And so, there's lots of things driving it. But the fundamental question of are we continuing to improve, I think, is answered with this slide. And what makes it even more impressive is, when you dig in to the details and you look at 2018, that's with 90-plus-percent of wells that have an offset, so characterized as children wells. So the big debate on our children wells, versus some parent wells, we can have that discussion. But fundamental, you can look at for many different reasons; we continue to get better well performance every year.

Thanks, Jeff. And follow-up along the lines of clarification on slide 7. You talk about unconventional EOR commercial success in 2019. Could you talk more about that? I'm not sure what you mean there? Thank you.

We have in the past, on done 4 CO2 injection pilots in the Midland Basin to test the efficiency and the commerciality of CO2 flooding the shale. And that's in the Midland. And what we're looking at in the Southeast New Mexico area is more of an enhanced oil recovery with using hydrocarbon gas injections, which would do two things for us. First, it would help us to maintain pressure. Secondly, it would become also somewhat miscible than the oil and would make it the same as CO2 does, make it less reluctance to flow, lower the friction and improve the ability to flow the oil from where it is to be freezed, to help in performing a full string. What we intend to do in Southeast New Mexico would be a continuous injection that would be full stream. So we're going to test that. We believe based on our models that it'll work and part of the objective there is to try to lower the decline of the Resources business and we believe that we'll successfully do that over time.

Understood Vicki. Thank you.

Thank you.

And next we have a question from Ryan Todd of Simmons Energy. Mr. Todd, your line is open.

Sorry. Looking forward, as we think about the normalization of CapEx, you have a back door, it's kind of a $5 billion to $5.3 billion level beyond 2019. The incremental capital driven -- in that case, driven more by an acceleration of activity in the Permian Basin? Or by a resumption of activity in international regions?

It will be both. The incremental capital in 2020 will be spread between our resources and the international areas, part of which will go to the growth areas. We do expect to start seeing -- we're going to continue growth from our base areas internationally through exploration and some of the other things that we're doing. But we'll pick that up in the new areas as we complete our appraisal programs. Now, the bulk of the growth capital is still going to go to resources in 2020, but we will send more to these – to the new areas.

And maybe on that as well, I mean, you referenced some of the base case kind of assumes $60 crude in 2020. If you were to be at $50 again in 2020, would you see a similar type of program that we see here in 2019, where you continue to kind of smear out the international investment and run a moderated program in onshore?

It will be dependent really on where we are with respect to our cash flow. Our commitment is to stay, keep our capital programs within cash flow going forward. So if we're in a $50 of environment with what we're seeing from efficiency improvements and are increasing production in 2020. I wouldn't say that, we would be at the 4.5, it would depend on how our costs are looking now and everything else, but we would stay within cash flow.

Maybe an unrelated question, I appreciate some of the details you provided on water sourcing. Can you talk through how you see potential risk of increasing cost from water disposal going forward particularly in the Delaware Basin? And how you set up the handle water disposal over the long term?

So one thing – this is Jeff. So, one thing given our full cycle value focus, water infrastructure is really, really important in all of our development areas from the very beginning. So if you go look at New Mexico and how much we're recycling up there, the size of our water infrastructure in Texas, Delaware. I mean, we see – not only a risk to the business, if you don't manage it properly, but definitely a significant economic risk if you can't do it well. So one of the things we do from the very beginning of when we go to a development area is ensure we have water infrastructure in place to collect the water, recycle it where we can as much as we can, and then have numerous disposal outlets for when we're done for whatever water is left over. And so I'd say, in all of our development areas, we're very well-positioned and where there are some areas that have different have risks than others, some may be cost and just availability, some maybe permitting related to seismicity or whatever it is, we've identified and mitigated those risk in all of our development areas.

Great. And thanks, Jeff.

And the next question comes from Brian Singer of Goldman Sachs.

Thank you. Good morning. A couple questions with regards to the longer-term outlook here. In the years to come, how do you see your skill in the Permian impacting global unit operating in G&A cost? Do you see these costs falling flat or rising on a per BOE basis? And then what base case into that 2022 to cash flow plan? And then if I might add to that separately and you talked a little bit about this earlier what gives you confidence to base case production in Oman in the UAE even if it's three to four years out at the key milestones that we should be focused on between now and then?

Firstly with respect to the G&A, the G&A on a per BOE basis will be coming down over time. So that should be the case. And that's what we've assumed in our 2022 plan. The other thing that with respect to the milestones, the milestones are listed on slide 7 and what we try to give you there is more of a roadmap of how we're going to get there and the international blocks, particularly for some information about the non-conventional EOR and when that might happen. But this is essentially of the roadmap you wanted to be able to see, so you can check what's happening as we go. With respect to what -- yeah, with respect to what the performance will be, it's going to be based on analogs. Ken pointed out something to me just recently, and that is that if you look at the four countries that are contiguous there, you look at -- we're probably the only company that has operated in all four of those countries that have this similar trend. So we have a lot of experience in this trend and we can do analogs and help us understand how to forecast what to expect. So we have a lot of good information around that. But with respect to the roadmap, I’ll let Ken tell you a little bit more about that.

Thanks Vicki. If we start with the Oman in the north, the game plan is to further define the hydrocarbons in Block 30 and 51 in order that we can optimize the regional development by potentially using their existing Block 62 as a hub for facilities. On a previous call, I was asked would we spread the well in Block 30 before the end of last year. We did. It's an on trend discovery and in fact, we found a new zone that we were not expecting. We plan to drill a follow-on well this quarter on Block 51 we’re reprocessing the existing seismic lines and plan to be drill ready by Q3 this year, which led to look at the hub concept for Block 62. We think hub and spoke is the best and most efficient way to develop this area. In Block 72 we started shooting seismic and we hope to have useable data by Q2 2020, but we may use some fast-track data for early drilling. Again our oil targets there are similar to those we've seen in our existing Block 53 hub, again hub and spoke concept to maximize efficiencies. In Abu Dhabi we were delighted to land Block 3. The block is 90 miles long, 30 miles wide and very few wells have been drilled there since the 1970s. It's in a great location not only because of proximity of super giant fields, but also because of infrastructure for success where we can hook up the flow lines very quickly and get that oil to export very quickly. I mentioned earlier we’ll spud a well this year. We've already mapped 162 prospects into 11 stacked reservoirs as targets and within these based on the new 3D seismic, which we think is some of the most cost efficient seismic ever obtained by anyone in the industry. So overall we try to detailed the milestones for a mine in Abu Dhabi and Colombia we're ramping up TECA, we'll drill 30 wells this year in TECA and will stream online to them this year, replacing all of long lead items for TECA, which will enable the ramp up that continue through 2020 and 2021. And as Vicki said, we're continuing to explore in our core existing assets also. So we've tried to make the roadmap something that we can update you on periodically as we get good results and I hope that answers your question.

Great. Thank you, yeah. So my follow-up goes back to the Permian. And you highlighted some of the areas of efficiency and productivity gains in your comments and so far in the Q&A. I think if you look at across the landscape even among larger and more scaled Permian companies for a company of your Permian Resources production base, you're planning to grow production at a rate that other E&Ps kind of spend more in capital to achieve than what you're projecting. Can you just talk to what you see as the risk around the Permian capital and production plan this year? And to what degree Aventine hub is going to be a driver of further capital efficiency or whether that's already essentially been reflected in recent CapEx results?

Yes, Brian, this is Jeff. I will take your question. So, I mean the rest -- we feel really good about the areas we're developing in because they are -- one, they're core development areas, we know them really well. There's not a huge appraisal component to it. There is a little bit. Again like last year when we drilled a lot of development wells, so we weren't just out drilling single wells. It fits that same old, so it's a progression of areas we feel very comfortable with technically. So, from a well performance risk, I think it's very, very low. The biggest risk I see is actually -- from a performance standpoint, we're starting to see high productivity gains and lower time-to-market, drilling faster, and things like that. So, the biggest challenge is with us is as that continues, what do we do when that pace keeps picking up. But from a cost standpoint, Aventine is up and running. So, we've realized two-thirds of the benefits from that. We feel very comfortable with that. We have our people in place. I mean one of the things we did very early on is not just wait until we have the activity to start getting all the right resources in place. So, I really feel like our program is de-risked from execution standpoint cost and performance standpoint for this year, especially at the pace we're going. Because like Vicki said running 12 rigs for us is a very moderate pace, especially compared to many others and especially compared if you go back a few years ago we are at 40. So, it's well within our bandwidth to handle this not just execution but technically.

Great. Thank you.

And the next question comes from Doug Leggate of Bank of America Merrill Lynch.

Thank you, good morning everyone. Cedric I wonder if I could just get some clarification from you on slide 21. And I guess I'm also comparing it to the slide you put up specific to 2019 capital back and I think there's a confidence at the beginning of the year. So, what I'm really trying to understand here is $50 TI post-2019, you're capping your spending is that the way to think about this and above that is going back to shareholders?

Hi Doug, good question, I appreciate the clarification. We're weren't intending to have it be precise where you move to one penny to the next and that shift gears but it’s indicative of our -- the way we think about it we would spend I guess two years ago when we came out with our breakeven plan which allows us to sustaining a world-class dividend and keep our production base flat at $40 oil. And what we're doing today two years later is nothing short of amazing in terms of beating those assumptions -- beating that plan we're beating it on cost. As Jeff outlined, we're beating it on productivity of our wells and so as we continue to lower our breakevens just by the way that is one of the keys to us raising our dividend at a more meaningful rates. We've continued to raise our dividend 16 consecutive years but it's been more modest since the downturn more modest rates. We'd like to go back to more aggressive rates but the key to that is lowering our breakevens and delivering more cash flow from that. So – but above $40, we are looking at reinvest first and would get to that 5% to 8% target long-term growth rate, continue modest dividend growth and then above the $50, we are looking at both balance sheet improvement as well as share repurchases and that's something we certainly demonstrated last first. So I wouldn't give you a precise $50.01. We're going to share buyback that number or dividend increase, but it is how we're thinking about it, as you get into a certainly a $60 environment which is what we're forecasting to the 2020 we think that as a logical price for the industry to balance supply and demand. That is something we would look to do as we return more capital at that point. We don't need to grow any more than that 5% to 8% long-term target.

I understand. I appreciate the clarification, because I just wasn't – I think there was an earlier question it sounded like it was different but that's very clear. Just to talk on that very quickly the $50 TI I assume you're still using a $10 differential for Brent?

Yes.

Okay. My follow-up then is also related to the dividend. So I know you guys talked to this many times in the past, but if you're at $9 billion let's assume in a couple of year's times or let's assume oil maybe is a little bit more generous in between times. Is your first priority to reduce the dividend burden by buying back stock because on a per share basis you still get the growth of your buyback the stock? So how should we think about absolute dividend growth versus per share growth through share buybacks? I'll leave it there. Thanks.

Great – great question. I mean, we see dividends and share buybacks as complementary. I will say our first priority is always the dividend. We prove that in the downturn. We're one of the few high-dividend paying companies that didn't cut the dividend. There's a long trail of bodies of companies that did. We're very proud of our track record in a very tough time. So our priority is and always will be the dividend. We want to – we will continue to grow it. That's our intent and we certainly want to grow it even more meaningful rates as we're able to. Can't forecast when that will be, but as we think about higher prices that's certainly like I said earlier, when we start to think about buybacks and it's complementary as you stated, because it does reduce the share count that which enables us to afford dividend growth more easily. So but certainly that $9 billion that we're forecasting in 2020 should we have a $60 environment? If you back out the midpoint of the CapEx range at that time of $5.1 billion that leaves you $3.9 billion of free cash flow. That compares to our current dividend of about $2.4 billion. So that's more than a 50% cushion on that dividend, if you will that would allow you in a $60 environment to both grow the dividend and do buyback. So I think we would be in a very good position that even a modest improvement in oil prices over that time to be in a really good position to deliver a return a lot more capital and we would do it in both dividends and buybacks, which again I think – we think of as complementary.

I appreciate the full answers. Thanks Cedric.

Yep.

And the next question comes from Phil Gresh of JPMorgan.

Yes. Hi. Good afternoon. Thanks for squeezing me in here, just starting I guess with Midstream. Could you help maybe bridge the 4Q actual results to the 1Q guidance? I know, maybe there was some items on both sides here but it just seems a little bit bigger than the normal sensitivity, I would suggesting the differentials. And then if you have an outlook on the full year for the midstream business whether it's on differentials or the pretax income, if you could share that?

Yeah. Part of what's happening in Q1 is a Dolphin turnaround. So that's part of the difference between Q4 and the Midstream and the differential impact and Dolphin. We have some other just general marketing things that will have an impact in Q1 that we can detail out after Q1.

Okay.

With respect to the full year, it's kind of hard to forecast the full year at this point because of the differentials and what the volatility there might be. So we’ll see how things go over the next few months or so.

Hey, Phil this is Jeff and just to add to what Vicki said. I mean one thing that we wanted to update people on is to remember when the differential collapses, you see that in midstream from a negative standpoint. But the upstream now, given our oil production in the Permian, we’ll realize more than 50% of what you lose on the midstream side. So good way to think about that. We gave that sensitivity so, as that differential collapses just for everyone to remember that more than half of the benefit will be recognized in oil and gas.

Sure. And is there a caustic price assumption that will be behind that chemicals guidance? I know that maybe early part of the year seems to be a little tougher than the back half, I'm just trying to calibrate that?

Yes Phil, this is BJ. For caustic, and obviously, we saw price erosion towards the end of 2018. Our assumption in 2019 is we're going to see some price pick up but not to the level of the erosion that we saw towards the end of the year. So we're taking a conservative approach looking forward. But we feel really good about supply and demand fundamentals long term in the caustic market. So I think it's conservative but we still felt really good about the forward years.

Just to add one thing on. As we've certainly made a few adjustments to the 2022 cash flow outlook because we wanted to keep it current and that was one of the items that we were more conservative on caustic prices as well as sulfur which affects the midstream business. The combined effect of that is a deduct of about $150 million versus what we showed in 2022 versus what we showed you in the third quarter. We also had a deduct of a $250 million related to the lower production associated with a lower capital spend in 2019 and the less of a ramp in 2020. So that caused some confusion also last night, we didn't intend for that. We thought we’ve laid it out, but just to clarify. So that's $400 million combined which more than offset the $150 million pick up we have from the $5 increase in the Brent price differential versus last quarter. So just trying to bring it kind of current with current thinking, so it's not stale, but that's where we kind of move from the midpoint of the $9.25 billion last quarter to the $9.0 billion this quarter.

That's really helpful. Thanks Cedric. Last question for Vicki, you just made a comment in your prepared remarks about 20% base decline rate and that it was higher than in the past. So I just wanted to understand that comment a little bit more, what would you have said it was in the past? And I guess just because Permian's only one-third of the production at this point, so it's a little bit high to me, but just any additional detail behind that would be helpful? Thank you.

In the past we were traditionally running at a little bit less than 10%. And so the increase in the Permian has gotten us to -- will have us by the end of this year to around 20%. But it's important to think about the strength of our chemicals business in this sort of environment is that, when you think about our overall cash flow decline that's really only about 15%. So the 20% decline in the oil and gas business is not alarming, although the international assets as we develop those that will somewhat mitigate that decline.

Okay. Thank you.

And the next question comes from Philip Jungwirth of BMO Capital Market.

Thanks good morning. I was just hoping you can give a little more color around the 6% international production CAGR key drivers and then really just the progression of that growth over the next couple years because when we look at the 2019 guidance it looks like you're budgeting around $800 million of CapEx flat year-on-year production. So, how is that -- really either capital efficiency improved? Or is it more value increasing than the level of investment?

It's Ken here. As I mentioned earlier in terms of capital efficiency, our drilling performances improved beyond measure over the last few years. So we're able to drill many more wells now than we could say three or four years ago. In terms of the roadmap on slide seven, we basically have a large portfolio in our opportunities going forward. We have milestones associated with Colombia, the TECA development and new blocks. If you look at it, it spades through year by year, each of these plans will be optimized over time, so that we can maximize the returns of every one of these streams. So we feel comfortable in reaching the 6% with the portfolio that we show here. We haven't talked about Al Hosn debottlenecking, we see opportunities there and we see great well performance and also a new geological and petrophysical model, so that we have additional gas there to enable that to be -- probably be debottlenecked.

Okay. And then on slide 6, where you lay out the facility investment at 24% of the 2019 program, I was wondering if you could just isolate that to the Permian Resources as a percent of the $2.6 billion capital budget, and then also how that would trend over time? And maybe provide some color around just operating cost benefits around that facilities investment?

Sure, Phil, this is Jeff. So for 2019 it's around 21% facilities and I’ll carry that when we do our OBO, we exclude that but they also have a facilities component to it. So if you're looking at it from a peer standpoint you’d probably want that in. But of the $2.6 billion, it's about 21% as facilities and you brought up one of the most important thing, not just from a productivity standpoint, but that really helps drive full cycle cost, which shows up in operating cost. So when you look at our operating cost, us able to get down into the mid to low-sixes is really where you see the benefits of that. He also see it from a productivity standpoint it's harder to measure just from an uptime standpoint and ability to handle the production reliability it shows up there as well. So from a long-term standpoint, we look at most of our field development plans, we expect to get on average below 10%. So if you go and look at our more mature areas like in the Midland Basin where we have infrastructure developed and you look at the new developments there we're below 10%. So we expect to get there in the not too distant future from a total facility spend.

Great. Thanks a lot.

The next question comes from Paul Cheng of Barclays.

Hi, guys. Just couple quick question. On the breakeven you're talking about the 24% on average per year growth in the Permian Resource. But can you give the number for 2020 to 2022 what is your rig count per well, productivity improvement that you assume comparing to 2018 or 2019? And also what is it the CapEx assumption as well as the base decline curve?

Sure. So, Paul, what we said last year, so 24% CAGR, four-year CAGR. This year it will be 30% to 35%. So obviously, that number is coming down as the base grows. And so the way I think about it, when we originally rolled that out, we said capital would be roughly flat with where we were last year, which was around $2.8 billion. And so, what's going on when you do that it goes back to question Phil asked is, you actually -- we're running say 12 or 13 rigs at that pace. But as you spend less on facilities, you're able to dedicate more of that capital and to drilling wells. So just easy math, these aren't exact numbers because we'll factor in with working interest and other things, but facilities goes from 20% to less than 10%, that could add a couple operated rigs to better generating production growth, instead of being spent on facilities.

So you're basically looking about 14, 15 rigs. And in the base assumption what kind of productivity improvement on the well production?

Yes. That's a great question. So, hopefully, you've heard, with our long-term forecast, we always want to make sure we can deliver our long-term forecast. So when it comes to productivity improvements, we've assumed almost zero. I think we've had like 1% in some areas for productivity improvements. When I just reference the slide that shows is 25% improvements in the last year, 20% improvement in the year before that and so on. So we've been really conservative with productivity improvements and how we've built that into the plan. So it's almost zero. But we had some areas that were new from an appraisal standpoint, so they have some uptick in them. But it's small on a global scale.

And just a clarification, Jeff, you earlier had mentioned in your prepared remarks saying that in five years time that this will be over 600,000 barrel per day. Are you talking just the Permian Resource or Permian Resources plus EOR?

Yes. That's just Permian Resources.

Just Permian Resources. Okay.

Correct. So that excludes EOR, obviously.

A final question that, I think, Vicki was talking about, you guys have done a number of pilot on the CO2 as well as using the other hydrocarbon. Have you so far seen any distinct pattern, certain type of activities like of the reservoir will be better respond to a certain -- to CO2 flooding and the other one? And is there anything that you can share? And how wide spread is that application could be?

Yes. I mean, nothing meaningfully that we can share, but you're right. I mean, different reservoir characteristics will be more conducive to hydrocarbon gas versus CO2. And I'd say, you can look at, in a conventional world, many of the same principles will apply with miscibility, depth, pressures, temperature, all of those things. And so, as Vicki said, we're really comfortable now from a technical standpoint that we know with the EOR, hydrocarbon gas and CO2 through the different reservoirs, we can get more oil. And actually is better technically than what we thought. The real challenge is, from a commerciality standpoint what do patterns look like, how do you design them and how do you handle the gas processing, all of those things, that's where the real challenge lies and that's why we're focused on proving up that commerciality. But you will see differentiation based on reservoir characteristics, not that different than what you see in the conventional reservoirs.

And when you guys will be in a position that you maybe share more of the data?

I would expect late this year, we'll share more of that.

Thank you.

Thanks, Paul.

And the next question comes from John Herrlin with John Herrlin with Societe Generale.

Yes, hi thank you. With respect to your CapEx budget, what kind of labor or oilfield services inflection cost are you baking in for this year?

We're baking at about 4%. 4% is domestically but internationally, we're not seeing the kind of inflation that we're seeing domestically.

Internationally we're seeing the last 16 contracts we've bid; we've seen 4.1% deflation. And if we focus only on the sort of major suppliers what we're seeing is a 16% reduction internationally.

Good. My next question is regarding international policy, you had some good growth in Colombia and also me in it, was that all drilling-program elevated?

I think a combination of drilling also some of the reservoir characterization work we're seeing and overall, it's just a really good performance. I don't see anything one individual thing it's just a collective individual activities across the whole international.

Okay and the last one for me is on the Permian Resources. Earlier it was mentioned that you haven't had sort of the parent-child relationship that some of your peers have. Have you changed your spacing design balance in your core areas? Or is it very petrophysically specific.

Yes. I think it's very petro-physically specific. So, if you look at our core areas, they may vary from three well spacing to six or seven as where they are. And the numbers that we give in or less than 50 inventory we average about 4.7. So, I'd say significantly lower than many others. But again we're getting really, really good performance. So, that comes out there. But that's one of the variables that we continually update and modify and I think we mentioned an example in Texas Delaware where now we're doing more of a Chevron design in developing kind of two benches almost together and the implications of that are really good well performance and you are able to remove a well and get better performance when you combine those two together. So, it's one of the variables we turn all the time, but I would say when you mentioned the parent-child, we're not unique. That relationship exists. I would say we've just figured out how to manage it optimally from a net present value standpoint and not just try to drive up inventory.

Great. Thank you.

Thank you.

And next we have a question from Leo Mariani of KeyBanc.

Hey, guys. I just wanted to touch quickly on the EOR business. Obviously, you guys have put some longer term growth rates between 2018 to 2022 for Permian Resources and international. Just want to get a sense of how is that EOR business play out that outlook? Is it more flattish with cost reductions? Or how do you think about that production stream?

It has very minimal growth. It's on the order of 1% CAGR over that time period. So we continue -- as we show we have tons of inventory for further EOR projects, so we continue to prosecute that. But we need more inject and other things. So it’s CAGR is around 1%.

The one thing I'd add to that is if you had noticed when created the Low Carbon Ventures group last year, we've got some milestones listed in that area too. It's not reflected in the 2022 outlook but it is certainly an area that we like to make great progress and develop. And as Jeff mentioned we have a lot of running room to grow in terms of EOR projects if you could just get more CO2. It's kind of the irony in today's world where most people want to eliminate CO2 emissions and we just can't get enough CO2 commercially to our locations. And it's an area we're focused on.

Yeah, the bottom line is that that's another potential upside for our 2022 plan.

Okay. And just shifting gears over the new block you guys picked up in UAE there. You certainly talked about a plethora of prospects over there. Presumably is most of the activity going to be focused on oil over the next couple of years, obviously, you're neighboring out holes and block there is more gassy, can you just give us any color on what you're targeting?

Yeah, it's mainly oil we’re targeting as I mentioned earlier between the super giant fields in Abu Dhabi and the prolific fields in Oman, we’re focused mainly on oil.

All right. Thanks, guys.

In the interest of time, this concludes our question-and-answer session. I would like to turn the conference back to Vicki Hollub for any closing remarks.

I want to thank you all for your questions and have a good day. Thanks. Bye.

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