Occidental Petroleum Corporation

Good morning and welcome to the Occidental Petroleum Corporation fourth quarter 2018 earnings conference call. Our participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touchtone phone. To withdraw your question, please press star then two. 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 Oxnell Petroleum's fourth quarter 2018 conference call. On the call with us today are Vicki Holub, President and Chief Executive Officer, Cedric Berger, 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 two. Our earnings press release, the investor relations supplemental schedules and our non-gap-to-gap reconciliations, and the conference call presentation slides can be downloaded off 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 the 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 costs 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 takeaway position. In 2018, we grew cash flow to a level that exceeded both capital expenditures and our dividend, a key achievement we had been working towards 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 return on capital and second to return an increasing level of excess cash to shareholders. In 2018, we returned more than $3.6 billion to shareholders through our sector-leading dividend and $1.3 billion of share repurchases under our $2 billion plus share repurchase program. We intend to complete the remainder of the share repurchase program in 2019. We remain committed to returning capital to shareholders through a balanced combination of dividends and share repurchases, as we've done for a long time. Since 2002, we've increased our dividend each consecutive year, and we've returned $33 billion to our shareholders through our dividend and share repurchases. That's about 70% of our current market capitalization. Almost 50% of this was returned in the last five years, a time period which included one of the worst downturns our industry has ever experienced. Through this downturn, we also maintained our strong balance sheet and A-level credit ratings. Our focus on investing in our high-quality assets delivered a 2018 return on capital employed of 14% and cash return on capital employed of 27%, both significantly higher than 2017 and upper quartile performance versus our performance peer group. These achievements reflect our commitment to our value proposition, the strength of our integrated business model, and the high quality of our assets. We made notable productivity and efficiency gains across all three business segments in 2018. The investments that OxyChem and our midstream business completed in recent years paid off in 2018 as both segments optimized cash flow and delivered record earnings. Our Permian business continued to outperform with Permian Resources delivering an impressive 52% production growth and Permian EOR exceeding cost reduction targets for the acquired Seminole CO2 field. Our international business generated $1.4 billion in free cash flow in 2018 and has enormous potential to grow cash flow going forward. On our last call, Kim provided details of our new international opportunities. Now we're pleased to have been awarded a new block in Abu Dhabi that Ken will describe in a few minutes. This new Abu Dhabi block along with six in Columbia and three in Oman make 10 new blocks added in the last year. These new international opportunities will add significant high return, low decline development inventory to our portfolio. At the same time, it's worth highlighting that these will require only a modest investment in the short term. One of our key competitive advantages is our ability to develop assets in a way that efficiently maximizes oil production and recovery and generates significant cash flow growth over the next decades. For the last three years, we've achieved all-in reserve replacement ratios exceeding 160% company-wide. The 2018 reserve replacement ratio of 164% is due to the excellent technical work our teams have completed in enhancing subsurface characterization across our portfolio and building customized development plans. Our momentum has continued into 2019 as our business segments continue to invest in high return opportunities. Last month, we discussed various capital budgets for three different pricing scenarios, but we've decided to limit our full capital spend in 2019 to $4.5 million. This represents a $500 million or full 10% reduction from 2018. By maximizing efficiencies, we are reducing spending to adjust to a lower oil price environment. As activity is adjusted to meet full-year capital spending of $4.5 billion, we expect spending to be higher in the first half of the year. In creating our capital budget to realize the highest returns, Permian Resources shale production will become a larger portion of our total oil and gas production. We expect this will increase our oil and gas base decline to 20% in 2019. As we continue to invest in the Permian, we will advance our appraisal in the short cycle low decline development opportunities in our new international blocks to prepare them for growth. Our 2019 capital program is dominated by short cycle investments, the majority of which will pay back within two years at $50 WTI. We will continue to be conservative, and if necessary, within six months, we can reduce capital spending to sustainable levels. meaning that Oxy remains flexible throughout the commodity cycle. We will grow oil and gas production by 9 to 11% in 2019 to replace the cash flow from Qatar in 2020, but our long-term annual growth rate forecast remains at 5 to 8 plus percent. Cash flow growth is an inherent driver in generating a higher return of capital and a higher return on capital. Our 2022 roadmap details the projects we will prioritize and execute over the next few years in order to grow cash flow from operations to $9 billion in 2022. While Permian Resources will continue to be the main driver of growth through 2022, our international business will also grow in terms of both cash flow and production. In addition to having many high return short cycle opportunities, We also continue to benefit from the stable, sustainable cash flow generated by OxyChem, Midstream, and Dolphin. Even with a lower activity level and a significantly reduced capital budget for 2019, we still remain on track to achieve the low end of the 2022 cash flow range of $9 to $9.5 billion that we communicated in our third quarter call. As you will have noticed, based on our expectations for the WTI spread, we updated our rent price assumption for 2020 onwards. And this will have minimal impact based on our production sharing contracts. To be conservative, we modeled OxyChem and Midstream cash flow at the low end of the previous range. And our projection of $9 billion in cash flow by 2022 does not include significant upside from several additional projects that we're currently evaluating. We'll provide updates on these projects as we advance. This morning, Cedric will take you through our financial results and updated guidance, and Jeff will detail the continuous improvements we are creating in the Permian. Ken will then provide an update on our new opportunities in our international business. I'll now hand the call over to Cedric.

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 in 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 DDNA 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 slightly lower than guidance, primarily due to the oil price adjustment in our production sharing contracts in Oman. The contracts utilize a pricing mechanism with a two-month delay, which resulted in a higher realized price and lower production for Oman in the fourth quarter. Fourth quarter international production was also impacted by weather and accelerated maintenance. OxyChem continues to perform strongly. reporting its highest fourth quarter pre-tax income ever of $223 million, above guidance of $220 million. Earnings decreased from the third quarter, primarily due to expected seasonality and in-market demand for chlorovinyl products, as well as lower realized caustic soda pricing and higher natural gas and ethylene costs. Our midstream business reported record core fourth quarter earnings of $670 million, which exceeded the high end of our guidance due to positive mark-to-market movements and a higher than expected Midland to MEH differential. Compared to the prior quarter, fourth quarter earnings reflected lower marketing margins due to a decrease in the Midland to MEH differential from $16.67 to $15.31 and lower pipeline income from the sale of a Centurion pipeline in the prior quarter. Fourth quarter revenue and cost of sales were both grossed up by $340 million due to the accounting treatment of certain midstream contracts where we've used our excess takeaway capacity from the Permian to purchase and resale third-party barrels. The third quarter gross up amount was $327 million. Operating cash flow before working capital for the fourth quarter was $1.9 billion which covered our capital expenditures of $1.3 billion and dividends of $594 million. Our total year capital spend came in just under our planned spend amount of $5 billion. Slide 11 details our guidance for the first quarter and full year 2019. As Vicki mentioned, we will pursue high return reinvestment opportunities in 2019 that will be funded by a total capital budget of $4.5 billion. which will result in annual production growth of 9% to 11%. We are reducing capital spending year over year, and due to technical and operational advances, we are still able to deliver significant cash flow growth. As we advance into 2019, our balance sheet remains strong, and we have ample liquidity available to complete our share repurchase program. We ended 2018 with over $3 billion in cash and still hold PAGP units with a market value of approximately $700 million. I'll now turn the call over to Jeff.

Thank you, Cedric. 2018 was an outstanding year for combined Permian business as we improved the value of our conventional and unconventional assets through our value-based development approach. We were 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 for 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 costs 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, compress time to market, and lower full cycle costs. In 2018, We increased our feet drilled per day by 19%, and we drilled record 15-day, 10,000-foot wells measured rig release to rig release in both our New Mexico and Texas Delaware areas. On the base management front, our investments in operability and surveillance are transforming how we optimize our base, as demonstrated by our 10% reduction in operating costs per barrel in 2018. In addition to efficiency improvements, we're also achieving major advancements in artificial lift optimization and well enhancements to lower the base decline rate. The rate of progress in Permian resources is extraordinary and will lead us to exceed 600,000 BOEs per day for this business alone within the next five years. Our Permian EOR business also had a great year. We continued the integration of the Seminole San Andreas unit and have now lowered OPEX by $8 per BOE, since we took over operations in September of 2017. We started injection on a new grassroots CO2 flood at the West Sundown Unit, which started injection four months earlier than planned and will achieve a development cost of under $6 per BOE. Permian EOR continues to provide low decline cash flow and high returns for our shareholders. We are excited about the critical role it will play in our long-term business sustainability strategy, especially as we leverage our position and expertise to reduce our carbon footprint. Slide 14 provides more detail on the 2019 capital program. Permian Resources will comprise $2.6 billion of our $4.5 billion total capital budget in 2019. We will utilize approximately 12 operated rigs and one to two net non-operated rigs with development focus in our core areas. We plan to operate six to seven rigs and New Mexico, which will primarily develop the high-return bone springs and wolf camp formations. We will continue development in the areas proved to be highly prolific in 2018 and plan to allocate activity to the Tanks area of greater sand dunes in the second half of the year. The appraisal results from Tanks area have been outstanding, with three wells online in 2018 averaging over 3,000 BOEs per day per well for 30 days. In Texas, Delaware, we will operate five to six rigs, primarily developing the Wolf Camp A and Hoban formations. The tapered well design we implement in the second half of 2018 has significantly improved the returns of our new wells, and we expect to see continued improvement through 2019. Overall, our capital program for 2019 will generate significant value for our shareholders and result in 30 to 35% annual production growth. We will also be advancing the commercialization of unconventional EOR development and expect to share more information on results later in the year. As you can see, 2018 was an exceptional year for our Permian businesses. We set well productivity records, significantly lowered operating costs, and realized breakthroughs with data analytics and subservice characterization that improved the returns from our assets. 2018 may seem like a hard year to beat, but the organization is more energized and capable than ever and I'm sure we will leave no doubt in 2019. I'll now turn the call over to Ken to discuss international.

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 a 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 in 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 oil fields of Abu Dhabi and Oman. It's also adjacent to our Al-Hosn gas project. As I mentioned on the last call, our regional geological knowledge is best in class and continues to develop We utilized that experience in preparing our initial stacked pay prospect inventory for Block 3. In 2019, our capital spend in Block 3 will be modest. The initial scope of work involves participating in a state of the art 3D seismic acquisition interpretation. Our plan is to initiate drilling in 2019. Expanding our footprint in the UAE in such a meaningful way, especially through a 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 de-bottleneck the Al-Hosn gas facilities. In Colombia, in partnership with Ecopetrol, we have signed an agreement to develop Blocks 39 and 52. These blocks are adjacent to our giant cannula moon field and near where we had successful discoveries this year. In addition, we farmed into four blocks in the highly prospective Putumayo Basin, where we have regional knowledge of the reservoirs. With these blocks, our net acreage in Colombia has risen to approximately 1 million acres at a low cost of entry. Like our other recent awards, capital will be small in 2019. In terms of performance, our Oxy International drilling teams continue to improve performance. and since 2014 have saved approximately $650 million for Oxy and our partners. As well as improving efficiency, cost, and time to market, the international safety performance was again world-class. Our international exploration programs in 2017 added 47 million BOE of resources and bettered that in 2018 by adding 94 million BOE of resources, while at the same time opening up new plays. Finding costs were around 76 cents per BOE. In closing, we expect 2019 to be an exciting year for Oxy internationally. As the exploration programs in our new blocks progress, we will continue to provide updates on significant developments. As you can see, the work we're executing closely aligns with Oxy's key technical competencies and returns focus and our true partnerships. I'll now turn the call back to Vicky. Thank you.

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 the structure and the sustainability to withstand the oil price cycles while also maintaining a social license to operate in the world in general and to operate in a low-carbon world. Our value proposition will continue to deliver a growing dividend and upper quartile or maybe best-in-class returns to our shareholders, while also growing oil and gas production 5% to 8% plus 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 that add significant value and provide important support during low oil price cycles. The diversification of our upstream oil and gas business also provides strength in periods of low oil prices, 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 the new conventional opportunities that we just picked up in Oman, Colombia, and Abu Dhabi. Our strength in a low price environment is 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 floods in the Permian, our water floods in Northern Oman, our steam flood in Mocasina, which happens to be one of the largest steam floods in the world, and our new Teca steam flood in Colombia. Our production sharing contracts and our low-to-decline gas projects in Dauphin and Alhosen also provide significant support in low oil price cycles. I believe there is no other oil company in the oil and gas industry that has this blend of high-quality, focused oil and gas projects that provide this diversity. This is why we can continue to deliver our value proposition. Not only do we have a great blend of assets with the addition of our new blocks, we have an incredible inventory of development opportunities. Over the past few years, we've replaced our production with new reserves at a ratio of greater than 160%. With the inventory we now have, we expect to achieve that replacement ratio for the foreseeable future. This ensures the sustainability of our value proposition. With respect to our social license to operate, our commitment is to manage our business in a way that improves the quality of life for our employees, contractors, and the communities where we operate, while also minimizing the potential impacts of our operations. Our employees are the lifeblood of our company. They are the drivers of our success, and as such, we are committed to their continued development and to helping them address the challenges of work-life balance. Many people refer to this as human capital management, but I don't. These are our people, the Oxy family, not just capital. It's personal to us. We want their lives to be the best that they can be at home and at work. This will enable them to be engaged and ready to deliver the best possible value to our shareholders as they have done in a significant way during this downturn. And in the areas where we operate, we want to ensure that we have a positive impact and can find ways that improve the quality of life in the community. Lastly, but equally as important is our commitment to use our unique skills and assets to lead carbon capture use and sequestration, or CCUS, starting in the United States and ultimately in other parts of the world. Along with many other initiatives, CCUS is necessary to limit the impact of climate change. With our CO2 enhanced oil recovery expertise and projects in the Permian, we believe we can lead the effort to capture current CO2 emissions from industrial sources to use and sequester in our Permian reservoirs. This will benefit the climate and our shareholders. As we have previously mentioned, we now have a low carbon team whose mission is to seek opportunities to innovatively reduce our carbon footprint in ways that also improve our operations and thus are expandable and sustainable. Our comprehensive strategy addresses all the factors that make a company great and sustainable. I believe this has built us into a next generation company that is uniquely positioned to excel in our changing world. We'll now open it up to your questions.

We will now begin the question and answer session. To ask a question, you may press star, then 1 on your touchtone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then 2. And our first question will come from Roger Reed of Wells Fargo.

Yeah, good morning. How are you? Hopefully everybody can hear me.

Yeah. Hey, Sam.

Yeah, I just wanted to, you know, kind of come at it from the capital discipline side. Obviously, the presentation you put out in January highlighted, you know, that you would live within cash flow at a given oil price. Good to see the higher growth rate, you know, 9 to 11 versus the 10 to 8. But I guess 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 have 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 of 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 net present value. I can tell you we're not trying to outpace the majors. We're trying to outperform the majors. 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 employ today than many other companies are with almost double the rigs that we have. Our focus is more on making sure that every dollar we invest creates more value. And so we're trying to really work this side of maximizing recovery from the reservoir and minimizing our costs. 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 that we're 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, I think, in a catch-up mode at this point.

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

Yeah, I think the real quantification is when you look at, you know, 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, you know, as you can see, you know, 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, you know, from the subsurface standpoint, utilize the huge amounts of data that we have in an effective way, and come up with an optimal development that delivers, you know, very good results from the beginning, not in a trial and error mode where you have to deploy a lot of capital that gets underutilized. And so, you know, it's almost unfair to point out, you know, we use 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. The subservice characterization is one we talk about the most because it's so impactful, but it's being used universally across the business, and there's 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, on 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'll 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 like you're doing this year to sort of cap any spend to return cash above $50 per barrel to shareholders? I know that would put your growth at the lower end of your range, and you could still attain double-digit growth out of Permian Resources. So is there a scenario where you may continue like you're doing 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 at $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 bit later. But our 5 to 5.3 – capital budget would allow for us above a $60 environment to return cash. That's something that we've always done, as I mentioned in my script, and something that we'll continue to do. We think a balanced return of cash to shareholders through repurchases and a strong dividend with the right balance between those is important to continue.

Sure. I appreciate that. My second question is, 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, we've certainly seen 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 when there's something coming to market. If you look at our organic growth opportunities as we've described, they're robust across the globe and across each business sector. 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 value. 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 of, 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've 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 event or a catalyst that sparks an increase in consolidation, not necessarily for Oxy, but across the Permian at some point?

That's hard for me to predict. 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. 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'll just be something that will be to be determined. It's hard to predict.

Yeah, no, I agree with you there. Thank you. Yes.

Hey, Bob, this is Jeff. I mean, the only thing I'd add to what Cedric said to me, if you look at the Permian's history, it's consolidated when the business got really hard. Prices dropped, margins got squeezed, and then consolidation generally happened. I think when you look across the unconventional space, you all know better than anyone, you know, the business continues to get harder, not easier as people move to full section development, having to operate with low operating costs, you know, manage infrastructure, large-scale wells, you know, 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, you know, maybe aren't as good.

Yeah, 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 four, you state 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 there? Thank you.

Sure, Paul. I'll take that. Basically, if you go to anyone that has a deck open, slide 31 shows that. So, you know, there's lots of ways to measure performance. The specific measure that we use as the cleanest is to where we look at over the last year the top 50 wells from an IP standpoint. Where are they? Who has them? And then you can see on the left, you know, we've got 20 of the top 50 over the last year. We've showed this for several quarters so you can see how it moves around and how it progresses. And that, you know, 40% of those, you know, we're the top operator when you look at the data. Another thing we add to it on the right, which is something we often talk about is, you know, we're able to do it with less propping. And the reason we highlight that is twofold. One, it's a big cost driver. Obviously, you all know, you know, the more propping you pump, the more cost. But two, It really indicates how we customize our developments. 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 of 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 you show a comparison of results, they're normalized by something. Or, you know, you cherry-pick which wells you use. You exclude this. You include this. So we included 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 15, 16, 17, and 18 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 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 into the details and you look at 2018, you know, that's with 90-plus percent of wells that have an offset, so characterized as children wells. So the big debate on are children wells worse than parent wells, You know, we can have that discussion, but fundamentally you can look at, you know, for many different reasons, we continue to get better well performance every year.

Thanks, Jeff. And a follow-up along the lines of clarification. On slide seven, 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 done four CO2 injection pilots in the Midland Basin to test the efficiency and the commerciality of CO2 flooding the shell, 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 injection. which would do two things for us. First, it would help us to maintain pressure. Secondly, it would become also somewhat miscible in the oil and would make it the same as CO2 does, make it more, you know, less reluctance to flow, lower the friction, improve the ability to flow the oil from where it is to the producer, whether it's a huff and puff or a full stream. What we intend to do in southeastern Mexico would be a continuous injection that would be full stream. We're going to test that. We believe, based on our models, that it will work. 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.

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

Oh, sorry. Looking forward, as we think about the normalization of CapEx, you highlight back towards kind of a $5 to $5.3 billion level beyond 2019. Is 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'll be both. The incremental capital in 2020 will be spread between 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 the new areas.

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

It'll 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 environment with what we're seeing from efficiency improvements in our increase in production and I wouldn't say that we would be at the four or five. It would depend on how our costs are looking then and everything else, but we would stay within cash flow.

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

So one thing, this is Jeff. So one thing, you know, given our, you know, full cycle value focus, water infrastructure is really, really important in all of our development areas from the very beginning. So, you know, if you go look at, you know, New Mexico and how much we're recycling up there, the size of our water infrastructure in Texas Delaware, I mean, we see a not only as a risk to the business if you don't manage it properly, but it's 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 into 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 with 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 have different risks than others. Some may be cost and just availability. Some may be permitting related to seismicity or whatever it is. We've identified and mitigated those risks in all of our development areas.

Great. Thanks, Jeff.

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

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

First, with respect to the GNA, the GNA on a per BOE basis will be coming down over time. That should be the case. 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 seven. And what we tried to give you there is more of a roadmap of how we're going to get there in the international blocks, particularly with some information about the unconventional EOR and when that might happen. But this is essentially the roadmap we wanted you 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 the performance will be, it's sort of 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, they're contiguous there. 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 that 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 want to let Ken tell you a little bit more about that.

Thanks, Vicki. If we start with 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 our existing Block 62 as a hub for facilities. On a previous call, I was asked would we spot a 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 drill ready by Q3 this year, which lets us 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 usable 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 three. 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. If we're successful, we can hook up to flow lines very quickly and get our oil to export very quickly. I mentioned earlier we'll spud a well this year. We've already mapped 162 prospects and 11 stacked reservoirs as targets. And we'll tune 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've tried to detail the milestones for Oman and Abu Dhabi and Colombia. We're ramping up TEKA. We'll drill 30 wells this year in TEKA, and we'll have steam online to them this year. We're placing all our long-lead items in for TEKA. which will enable the ramp-up to continue through 2020, 2021. And as Vicky said, we're continuing to explore in our core existing assets also. So we 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. Yes. And my follow-up goes back to 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 we look at across the landscape, even among larger, more scale-oriented Permian companies, for a company of your Permian resources production base, you're planning to grow production at a rate that other EMPs tend to 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.

Yeah, Brian, this is Jeff. That's a good question. So, I mean, the risk, we feel really good about the areas we're developing in because they are, you know, one, they're core development areas. We know them really well. You know, there's not a huge appraisal component to it. There is a little bit. Again, like last year, you know, we drilled a lot of development wells, so we weren't just out drilling single wells. It fits that same mold, 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. You know, the biggest risk I see is actually, you know, from a performance standpoint, we're starting to see high productivity gains and lower, you know, time to market, drilling faster and things like that. So the biggest challenge I see with us is as that continues, what do we do, you know, when that pace keeps picking up? You know, but from a cost standpoint, having teams up and running, you know, 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, you know, 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 an execution standpoint, cost, and performance standpoint for this year, especially at the pace we're going. Because like Vicki said, you know, running 12 rigs for us is a very moderate pace, especially compared to many others, and especially compared, you know, if you go back a few years ago, you know, we were 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 Leggett 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 in, I think it There's a conference at the beginning of the year. So what I'm really trying to understand here is, so $50 TI post-19, you're capping your spending? Is that the way to think about this? And above that is going back to shareholders?

Hi, Doug. Yeah, good question. I appreciate the clarification. We weren't intending to have it be precise where you move from you know, one penny to the next and it shifts gears, but it's indicative of the way we think about it. You know, it was been, I guess, two years ago when we came out with our breakeven plan, which allows us to sustain 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 costs. As Jeff outlined, we're beating it on productivity of our wells. As we continue to lower our break-evens, just by the way, that is one of the keys to us raising our dividend at a more meaningful rate. 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 break-evens. delivering more cash flow from that. But above $40, we are looking to reinvest first and kind of 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, you know, something we certainly demonstrated last year. So I wouldn't give you a precise at $50 and one penny. We're going to, you know, share buyback that number or dividend increase, but it is how we're thinking about it. As you get into a, certainly in a $60 environment, which is what we're forecasting through the 2020, we think that is a logical price for the industry to balance supply and demand. That is something we would look to do is 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, you know, I think there was an earlier question that sounded like it was different, but that's very clear. Just to tag on to 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 and I have talked about this many times in the past, but if you're at $9 billion, let's assume, in a couple years' time, or let's assume oil maybe is a little 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 if you buy back 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 proved 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 will continue to grow it. That's our intent. And we certainly want to grow it at even more meaningful rates as we were able to. Can't forecast when that will be. But as we think about higher prices, that certainly, like I said earlier, when we start to think about buybacks. And it's complimentary, as you stated, because it does reduce the share count, which enables us to afford dividend growth more easily. 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 a 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 at even a modest improvement in oil prices over that time to be in a really good position to deliver the 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 answer. Thanks, Cedric.

Yep.

And the next question comes from Phil Gresh of J.P. Morgan.

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 were some items on both sides here, but it just seemed a little bit bigger than the normal sensitivity I would suggest in the differentials. And then if you have an outlook on the full year for the midstream business, whether it's on differentials or the pre-tax income, you know, if you could share that.

Yeah, part of what's happening in Q1 is the dolphin turnaround, so that's part of the the difference between Q4 and the midstream and the differential impact and dolphin. And 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 may be. 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, you know, when the differential collapses, you see that in midstream from a negative standpoint. But the upstream now, given our oil production in the Permian, you know, we'll realize more than 50% of what you lose on the midstream side. So... You know, a good way to think about that, you know, we gave that sensitivity. So, you know, as that differential collapses, just for everyone to remember that, you know, more than half of the benefit will be recognized in oil and gas.

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

Yeah, Phil, this is BJ. For caustic, I mean, 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, you know, 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, you know, supply and demand fundamentals long term in the caustic market. So I think it's conservative, but we still feel really good about the forward years.

Just to add one thing, we 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 the 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 laid it out. But just to clarify, so that's $400 million combined, which more than offset the $150 million pickup you 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 $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 a 20% base decline rate and that it was higher than in the past. So I just want 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 a third of the production at this point, so it just sounded a little bit high to me, but just any additional detail behind that would be helpful. Thank you.

Yeah, 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 Jungworth of BMO Capital Markets.

Thanks. Good morning.

Good morning.

Just hoping you could 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 does really either capital efficiency improve, or is it more about increasing the level of investment?

It's Ken here. As I mentioned earlier, in terms of capital efficiency, our drilling performance has improved beyond measure over the last few years. We're able to drill many more wells now than we could say just three or four years ago. In terms of the roadmap on slide seven, we basically have a large portfolio now of opportunities going forward. We have your milestones associated with Columbia, the tech development and new blocks. If you look at it stage 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 our awesome deep bottlenecking. We see opportunities there. And we see great well performance and also a new geological and petrophysical model show that we have additional gas there to enable that to be further debottlenecked.

Great. And then on Flight 6 where you lay out the facilities investment at 24% of the 2019 program, I was wondering if you could just isolate that to Permian Resources 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 of that facilities investment.

Sure, Phil. This is Jeff. So for 2019, it's around 21% facilities. And I'll caveat that. When we do our OBO, we exclude that, but they also have a facilities component to it. If you were to look at it from a peer standpoint, you'd probably lump that in. But of the 2.6, it's about 21% as facilities. And you brought up one of the most important things, not just from a productivity standpoint, but that really helps drive full cycle costs, which shows up in operating costs. So when you look at our operating costs, you know, us able to get it down into the, you know, the mid to low sixes is really where you see the benefits of that. You also see it from a productivity standpoint. It's harder to measure. but just from an uptime standpoint and the ability to handle the production reliability, it shows up there as well. So from a long-term standpoint, you know, when 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.

The next question comes from Paul Chang of Barclays.

Hey, guys. A couple of quick questions. On the WIC event, you're talking about the 24% on average per year growth in the permanent resource. Can you give us a number that for 2020 to 2022, what is your WIC count per well productivity improvement that you assume compared to 2018 or 2019? And also, what is the capping assumption as well as the base decline curve?

Sure. So, Paul, what we said last year, so 24% CAGR, four-year CAGR, you know, this year will be 30% to 35%. So, obviously, you know, that number is coming down as the base grows. And so, the way I think about it, you know, when we originally rolled that out, we said capital would be, you know, roughly flat with where we were last year, which was around $2.8 billion. And so, you know, what's going on when you do that, it goes back to the question Phil asked, is, You know, you actually, you know, 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 into drilling wells. So, you know, just easy math. These aren't exact numbers because they'll factor in with working interests and other things. But, you know, facilities goes from 20 to less than 10. That could add a couple operated rigs to that are generating production growth. instead of being spent on facilities.

So you're basically looking at about 14, 15 rigs. And in the base assumption, do you work out productivity improvement on the well production?

Yeah, 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, you know, almost zero. I think we had like 1%. and some areas for productivity improvements. When I just referenced the slide that shows 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 then mentioned in your PPL remark saying that in five years' time, the business will be over 600,000 bills per day. Are you talking about just the Permian resource or Permian resource plus EOR? Yes, that's just Permian resources. Just Permian resources? Okay.

Correct.

So that excludes EOR, obviously. Final question. I think Ricky 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 patterns, certain type of characteristic of the reservoir will be better respond to certain CO2 flooding and the other one? Is there anything that you can share? And how widespread is that application could be

Nothing meaningfully that we can share, but you're right. Different reservoir characteristics will be more conducive to hydrocarbon gas versus CO2. I'd say you can look at, in the conventional world, many of the same principles will apply with miscibility, depth, pressures, temperature, all of those things. You know, 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 it 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? 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 the 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 Herland of Societe Generale.

Yeah. Hi. Thank you. With respect to your CapEx budget, what kind of labor or oilfield services inflation costs are you baking in for this year?

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

Yeah. Internationally, we're seeing the last 16 contracts we've bid, we've seen a 4.1% deflation, and if we focus only on the major suppliers, what we're seeing is a 16% reduction internationally.

Good. Then my next question is regarding international PUDs. You had some good growth in Colombia and also MENA. Was that all just drilling program related?

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

Okay. And the last one for me is on Permian Resources. Earlier it was mentioned that you haven't had, you know, some of the parent-child relationships that some of your peers have. Have you changed your spacing design plans in your core areas, or is it very petrophysically specific?

Yeah, I think it's very petrophysically specific. So if you look at, you know, our core areas, they may vary from three-well spacing to six or seven is where they are. And one of the numbers we give in our less than 50 inventory is 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 you know, more of a Chevron design and 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, you know, when you mentioned the parent-child, we, you know, 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 KeyBank.

Hey, guys. Just wanted to touch quickly on the EOR business. Obviously, you guys have put some, you know, longer-term growth rates between 2018 to 2022 for Permian Resources and international funds. I just want to get a sense of how does that EOR business play out in that outlook? Is it more flattish with sort of cost reductions, or how do we 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, you know, as we show, you know, we have tons of inventory for further EOR projects, so we continue to prosecute that. We need more injectant and other things. So CAGR is around 1%.

One thing I'd add to that is if you had noticed, we 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'd like to make great progress and develop. And as Jeff mentioned, we have a lot of running room to go in terms of EOR projects we could take if we 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's another potential upside for our 2022 plan.

Okay. Maybe just shifting gears over to the new block that you guys picked up on 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, your neighboring Al-Hosn 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 supergiant 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 over to Vicki Holub for any closing remarks.

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

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