Occidental Petroleum Corporation
Q4 2015 Earnings Call Transcript

Published: 4 Feb 2016

[Operator:]

Good morning and welcome to the Occidental Petroleum Corporation Fourth Quarter 2015 Earnings Conference Call. Please note this event is being recorded. I would now like to turn the conference over to Chris Degner, Senior Director of Investor Relations. Please go ahead, sir.

[Christopher M. Degner:]

Thank you, Carrie. Good morning everyone and thank you for participating in Occidental Petroleum's fourth quarter 2015 conference call. On the call with us today are Steve Chazen, Oxy's President and CEO; Vicki Hollub, President and Chief Operating Officer; Jody Elliott, President of Oxy Domestic Oil & Gas; Sandy Lowe, President of Oxy Oil & Gas International; and Chris Stavros, Chief Financial Officer. In just a moment I will turn the call over to Vicki Hollub. 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. Additional information on factors that could cause results to differ is available on the company's most recent Form 10-K. Our fourth quarter 2015 earnings press release, the Investor Relations supplemental schedules, 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 Hollub. Vicki, please go ahead.

[Vicki A. Hollub:]

Thank you, Chris, and good afternoon everyone. Despite sharp declines in product prices, we had a strong year of production growth, particularly in Permian Resources. And we made big strides in lowering our cost structure as well as executing our strategic review. I'd like to share highlights of our 2015 achievements. First, Permian Resources growth exceeded our expectations as we reached our 2016 growth target of 120,000 BOE per day. This was a year ahead of our original plan. We increased production by 35,000 BOE per day for a year-over-year growth rate of 47%. Al Hosn reached full production capacity and delivered an average of 35,000 BOE per day of production last year. In total we grew our production by 81,000 BOE per day, which was approximately 14% higher than 2014. We reduced our cash operating cost by 14%, achieved SG&A sayings of 16% and cut our average drilling and completion costs in Permian Resources by 33%. As a part of our strategic review that we launched at the end of 2013, we sold our Williston Basin properties and made significant progress in our effort to exit non-core areas in the Middle East including Iraq and Yemen, while also reducing our exposure in Bahrain. This will lead to lower capital spending in the region. Construction of the OxyChem ethylene cracker joint venture is on schedule and on budget for start up in early 2017. We reached a settlement with the Republic of Ecuador for approximately $1 billion of which we've collected $300 million and expect to receive the remaining proceeds in the coming months. And we exited 2015 with $4.4 billion of cash on our balance sheet. Now I'd like to reiterate our strategy and cash flow priorities. I want to emphasize these have not changed. Our overall strategy is to invest in projects that generate long-term value, achieving returns well above our cost of capital while maintaining a conservative balance sheet. Our assets in Colombia, ISND in Qatar, Block 9 in Oman, Permian EOR, Dolphin and OxyChem provide significant earnings, require relatively low maintenance capital and provide free cash flow in this low price environment. Our most recent addition to this list is our Al Hosn gas project which is a 30 year joint venture with ADNOC in Abu Dhabi. And the role of our Permian Resources business, the role it will play in our strategy is to provide quick production growth as needed to support our cash flow. Our top priority for use of cash flow is and always will be the safety and maintenance of our operations. Our second priority will continue to be funding the dividend. Third is allocating capital to our growth projects. The next priority for any remaining cash would be for potential asset acquisitions and/or share repurchases as opportunities arise. Commodity businesses are inherently volatile. We maintain a strong balance sheet to not only survive but to take advantage of potential opportunities. We'll invest our capital prudently and maintain a flexible program as we maneuver through this low price cycle. As I mentioned earlier, we made great progress last year on lowering our operating and SG&A costs. We plan to further reduce these costs during 2016 and expect that the financial impact of executing on initiatives from our strategic review will be evident through lower costs in capital in the coming months. In terms of our capital program for this year, our plan is to carefully reduce our activity levels without harming the strong progress we've made with our growth prospects. We'll fund only those opportunities that exceed our rate of return hurdles. Our 2016 capital program is expected to range from $2.8 billion to $3 billion. This represents a nearly 50% reduction compared to the $5.6 billion spent during 2015. This capital plan should approximate our expected cash from operations at current commodity prices. The majority of this year's spending program will be allocated to the Permian Basin and to completing long-term projects in our chemicals and midstream businesses. Our capital run rate is expected to be higher during the first quarter and falling in subsequent quarters as committed project capital winds down. In Permian Resources, our drilling activity will be highly focused on areas in both the Midland and Delaware basins where we have existing infrastructure, allowing us to achieve higher returns. Our level of activity will help preserve efficiency gains achieved over the past year. In Permian EOR, we'll take advantage of reduced cost for labor and materials to modify and expand existing facilities to increase our capacity to handle and inject greater quantities of CO2. This will enable us to implement additional CO2 projects. These projects will have longer duration and a typical production response time of one to two years. This will result in a modest increase in capital for our EOR business versus last year. Chris will provide greater detail on this year's capital program in a few moments. Despite the reduction in capital spending, we expect overall company production from our core assets to grow 2% to 4% on average compared to 2015. Our core assets are pro forma for the expected divestments in areas we plan to exit, including the Piceance Basin, Iraq, Yemen and Libya along with lower exposure in Bahrain. The full year contribution of production from Al Hosn and the startup of Block 62 in Oman should add approximately 35,000 BOE per day of production this year. Overall, domestic production is anticipated to decline slightly through the year, primarily due to the declining natural gas and NGL volumes caused by the curtailment of drilling activity in our gas assets in late 2014. We expect a modest increase in production from Permian Resources versus last year and will hold our Permian EOR production flat. Turning to our oil and gas reserves, the good news is that we managed to keep our proved producing reserves essentially flat in 2015 due to our development programs and improved recovery from some of our Permian Resources wells. We continued to see strong performance from our Permian Resources drilling program, which enabled us to replace 214% of our Resources production, excluding net sales and revisions. Our development programs added 149 million BOE of proved reserves. Our year-end 2015 proved reserves totaled 2.2 billion BOE consisting of 79% proved developed reserves, up from 71% proved development reserves at the end of 2014. Our liquids reserves comprise 74% of our total proved reserve base. In summary, while the macro environment remains challenging for the industry, we delivered strong production growth during 2015. We lowered our cost structure and continued to execute on our strategic review. Although we expect commodity prices to gradually recover, we've set our plan to be more aligned with a lower price environment. We're fortunate to have a great set of assets with the relatively low base decline rates that provide us with enormous flexibility for our capital. We believe our continued focus on returns, improved cost structure and strong balance sheet provide us with the opportunity to emerge from the current cycle as a stronger company relative to our peers. I'll now turn the call to Chris Stavros for a review of our financial results and further details on this year's capital program.

[Christopher G. Stavros:]

Thanks, Vicki, and good morning everyone. As Vicki indicated, we continue to have three main objectives over the long term

[Jody Elliott:]

Thank you, Chris. Today I'll review 2015 highlights from Permian Resources and Permian EOR and provide guidance on our program for 2016. 2015 was a very successful year. Permian Resources achieved our 2016 growth target ahead of schedule by reaching 120,000 BOE per day in November. We achieved this milestone by leveraging our advancements in geoscience, reservoir characterization and integrated planning to deliver better wells in less than half the time and at two thirds of the costs versus 2014. Throughout 2015, we reduced our OpEx costs by over 20% by improving field reliability, productivity and optimizing our surface and subsurface engineering. Our Permian EOR segment generated free cash flow in a low price environment and had its best safety metrics of all time. Turning to Permian Resources, in the fourth quarter we achieved record production of 118,000 BOE per day, a 40% increase versus the prior year. Oil production increased to 76,000 barrels per day, a 2% increase from the previous quarter and a 49% increase from a year ago. Winter storms at the end of December impacted total quarter production by approximately 1,300 BOE per day. For the full year, the business achieved production of 110,000 BOE per day, a 47% increase versus the prior year. Permian Resources continues to drive down capital cost through improved execution and drilling and well completions and reduced time to market. For each of our core development areas, we continue to monitor both our early time well performance and cumulative production to ensure our development approach is providing maximum value. In addition to improving individual well performance, we optimized field development value through pace, well sequencing, flowback designs to reduce cleanouts and fluid handling costs, artificial lift designs to maximize long-term production, and facility plans to ensure maximum utilization over time. Our Delaware Basin well performance continues to be strong. We placed 19 horizontal wells on production in the Wolfcamp A benches in the fourth quarter. We continue to increase well performance by optimizing the density of our completions and proppant loads and drilling longer laterals. For example, the Priest E 1H well achieved a peak rate of 1,659 BOE per day and a 30-day rate of 1,247 BOE per day. The HB Morrison B 12H achieved a peak rate of 1,487 BOE per day and a 30-day rate of 1,176 BOE per day. In New Mexico, we're delivering more productive wells by increasing our proppant concentration and reducing cluster spacing. For example, the second Bone Spring Cedar Canyon 27 #6 produced at a peak rate of 2,498 BOE per day and a 30-day rate of 1,750 BOE per day at an 82% oil cut. In the Delaware Basin, our Wolfcamp A 4,500-foot well cost decreased by about 45% from the 2014 cost of $10.9 million to a current cost of $6.2 million. We reduced our drilling time by 26 days from the 2014 average of 43 days to 17 days. In our new area of the Midland Basin, we brought the Adams 4231 Wolfcamp A online in the fourth quarter at a peak rate of 2,167 BOE per day and a 30-day rate of 1,841 BOE per day. We also brought online the Merchant 1409A well at a peak rate of 1,345 BOE per day and a 30-day rate of 1,132 BOE per day. Both wells are producing at over 80% oil cut. In the Midland Basin, we made similar improvements in well costs and drilling days in the Wolfcamp A formation. We reduced these costs of the 7,500-foot horizontal wells by 35% from the 2014 cost of $9.2 million to a current cost of $6 million. We reduced our drilling days by 63% from 46 days in 2014 to 17 days in the fourth quarter of 2015. Across Permian Resources we're continuing to lower field operating expenses through optimized water handling, lower workover expenses and better downhole performance. Since the fourth quarter of 2014, we've reduced our operating cost per barrel by 26% and expect this trend to continue this year. In our Permian EOR segment we continue to lower our drilling costs and manage the operations to run our gas processing facilities at full capacity. With resilient base production and low capital requirements, the EOR business continues to generate free cash flow at low product prices. We've lowered our cash operating expenses by 21%, driven mainly by lower downhole maintenance and injectant costs. Phase 1 of CO2 injection at South Hobbs has continued and we have a production response sooner than expected. We expect Phase 1 production to peak in 2020. We expect Phase 1 and Phase 2 to develop 28 million BOE at just over $10 per BOE. Additionally, we've started a pilot project in South Hobbs testing the residual oil zone. It has the potential to add about 80 million barrels of reserves. These residual oil zone reserves can be added between $3 and $7 per barrel of development costs. Given the current oil price, we will focus investment to achieve four goals

[Christopher M. Degner:]

Thank you, Jody. We'll now open it up for questions.

[Operator:]

We will now begin the question-and-answer session. Our first question comes from Evan Calio of Morgan Stanley. Please go ahead.

[Evan Calio:]

Hey. Good morning, guys. My first question is, one of your key or primary peers, they cut their dividend today two thirds after repeated defenses. I know your balance sheet is superior yet the macro has changed that underpins their decision. Can you discuss how you perceive your dividend sustainability through this cycle, and are there leverage levels or other metrics that would result in a change in your current priorities?

[Vicki A. Hollub:]

Yes, Evan, to begin I'd like to refer you to slide 23. What we've done really is planned our programs over the next few years to – based on actually the strip prices. Although we actually believe that prices ultimately will be higher than the strip, we don't expect prices to really recover much until very late this year or maybe early next year and recover only to slightly above the curve. But based on the cash that we have on hand and what we project our situation will be over the next few years, we do expect to be able to make it through this cycle and get back to reasonable oil prices and secure our dividend throughout this entire process. We're organizing our plans and our activities around that. And the good thing about our portfolio is we have the flexibility to ramp up and down as necessary to ensure that we meet our priorities. And as we said, the top priority is just the maintenance and safety of our operations and then we're going to pay the dividend and we've got the cash to do that. And generally, the way we look at it is we can use our cash flow from operations to cover our capital programs and part of our dividends over some of the years. And then what can't be covered by our cash flow from operations, we'll certainly use the strength of our balance sheet to cover that. So we don't see a threat to our dividend going through this cycle.

[Evan Calio:]

Thank you. I have a related follow-up. The irony of a downturn I think is opportunities, maybe the best when liquidity is the lowest. And so any commentary that you have on the asset market and whether your views of the macro raise the hurdle for acquisition or change your views on what's potentially attractive. Such for instance, say a more longer lived, longer cycle resource versus a shorter cycle shale resource?

[Vicki A. Hollub:]

Yeah, I'd say that we never want to get away from what we truly are as a company and that's what I stated in here, is that we're very much a, on the oil and gas side of the business, an EOR type company and a company that looks for the longer life reserves like Al Hosn that provide cash flow. That would be like Al Hosn and Dolphin. So what we'll be looking at is are the assets that have the longer life reserves. We're very proud of our shale position and we think that the work we've done over the last few years has certainly proved it up to be an asset that we want to take full advantage of. But currently our shale production is less than 20% of our total company production. And we don't really want it to ever be much higher than that because we feel like to have the asset base we have, that's part of the reason we'll be able to make it through this cycle with our current low declines. So that's sort of asset we'll be looking for.

[Evan Calio:]

Appreciate it. Thank you.

[Operator:]

The next question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.

[Doug Leggate:]

Thanks, good morning everybody. Good morning, Vicki.

[Vicki A. Hollub:]

Good morning.

[Doug Leggate:]

Vicki, I wonder if I could follow up on Evan a little bit there. I'm looking at slide 7 which is the kind of classic slide you put up about the priority for the use of cash. You've talked about optimism in a rebound in oil prices but you still have growth capital ranked higher than share buybacks and acquisitions. And I guess my question is, you've kind of missed an opportunity here with the separation of California Resources to reduce your dividend burden by buying in your stock which was the original plan. Obviously, extenuating circumstances, but in the event of a rebound in oil prices, why does growth capital still rank above reducing the dividend burden? And I've got a follow-up please.

[Vicki A. Hollub:]

Let me point out, I'm very happy that we did not buy back shares. The $6 billion is going to really be part of what helps get us through this cycle. And so I think we're fortunate to have the cash that we on the balance sheet now and that's really what's protecting, helping to protect the dividend. But I would view the last two items on the list, the share repurchases and acquisitions to be right now, although we show one above the other, those we view as equally important. And what we're going to look for is the opportunities that arise through this cycle. We're not going to immediately go out and buy, repurchase shares, but what we want to do is look at how the cycle evolves over the next quarters, maybe even next year and a half or so, and look for opportunities and before we commit to share repurchases. But I would view those as right now both on the same level of priority. And Chris, do you have anything to add?

[Christopher G. Stavros:]

Yeah, Doug, I'll just follow up on what Vicki said. I think what she said is right. I think in addition to that, we're going to have to look at it on a return basis and clearly the goal over time will be to reduce the share count as it will help us fund the dividend and fund growth of the dividend over time. So I do still view, we still view share repurchases as important over time and a reduction of the share base over time. So we'll look at opportunities opportunistically to go ahead and do that. And it's just going to sort of depend on where things are, vis-a-vis the stock price and other opportunities that may come up for capital.

[Doug Leggate:]

Okay. I appreciate the answer, Chris. My follow-up is also referencing the slide deck on slide 41. You're showing the economics of your drilling backlog at different oil prices. I guess my question is that it would seem that a lot of companies are looking to drill their very, very best assets in the worst commodity environment. So I'm just curious as to why does that make sense if you're so optimistic on the recovery? Because obviously the offset, the alternative would be to allow production to decline but would also imply you're preserving value which I think one of your competitors talked about the other day and I'll leave it there. Thanks.

[Vicki A. Hollub:]

I'll start that but then let Jody add onto it. We actually were fortunate to be in the process of some development programs in key areas where we were kind of into a manufacturing mode. We already have the infrastructure installed. And so that's what's making our current program so economical and what we feel like is the right thing to continue to develop during this cycle. And Jody can add to that.

[Jody Elliott:]

Yeah, building on Vicki's comment there, this is some of our best areas but we really are leveraging more than just the best rock. It's the infrastructure that we've already invested in. There's good rock in all of those tranches of inventory. It's just the maturity of our development plans in some of those areas aren't quite as far along, so we would not develop those until we get those development plans further matured. And that's one of the focus areas we had this year is to move more of that inventory to the left side of that chart.

[Doug Leggate:]

Okay. I appreciate the answer. Thanks.

[Operator:]

Our next question comes from Ed Westlake of Credit Suisse. Please go ahead. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Yes. Good morning. Just again a follow-on I think to your answer about the types of assets in shale. So from that I'm taking that you're more interested in some of the long-lived assets. Maybe give a little bit of color as to where you think these opportunities may lie.

[Vicki A. Hollub:]

One of the things that we'd like to continue to consider is adding to our position in Permian EOR. We have the infrastructure there that really can't be duplicated by any other companies. We've got the 12 gas processing plants, 1,900 miles of pipeline and operate two CO2 source fields. So we have the infrastructure in place to continue expansion of our EOR operations in the Permian. And that would be for us one of our higher priorities. In addition, we see opportunities in Colombia to continue our work there. We this past year signed an agreement to develop another couple of water floods there. We think that's going be a good opportunity for us going forward. And in addition, in our three core areas in the Middle East, those are the kind of opportunities that we would continue to look for. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Okay, and then a totally separate question. At the back of the deck, you've got that great chart on – I should find the slide – on slide 41 that Doug mentioned about the inventory. Obviously there's a big flip between $50 and $60. And then if you look at the colors of the bars, you've got a lot of Bone Spring acreage, Spraberry and then the Wolfcamp B. Maybe just, and this is based on 4Q costs, hopefully those are the ones that you identified, that $6 million in the Wolfcamp and $6 million in East Midland. What are the biggest levers you think about taking that inventory that works at $60 down to $50?

[Jody Elliott:]

I think one of the biggest levers is multi-bench development, ensuring that the field development plans allow us to economically develop more than one good bench at a time. And so that's part of the redeployment effort of our technical staff to figure out multi-bench to drive better utilization of our infrastructure costs in those areas. That will be the biggest thing to move them to the left. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) I mean you mentioned reduced cluster spacing in some of those Bone Springs wells. I mean is there a lot more technology that you can still apply?

[Jody Elliott:]

I think there is. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Okay. Good to know. I'll keep in touch.

[Operator:]

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

[Philip M. Gresh:]

Hey, good morning.

[Vicki A. Hollub:]

Good morning.

[Philip M. Gresh:]

The first question is just on the guidance. There's obviously a lot of moving pieces here on the production side. But, Chris, just with respect to the 1Q, the 620,000 to 630,000, I believe you said that that would exclude the asset sales, the domestic asset sales, but it does not have anything contemplated in there for the Middle East asset exits. So I wanted to clarify that, and then just generally ask how that's going and how you would expect that 72,000 barrels a day of non-core Middle East to roll off as the year progresses.

[Christopher G. Stavros:]

Sure. Thanks Phil. On the guidance, just to make it comparable for you to reconcile it, I mean the way I would think about it is that you've got the Piceance in the US that we'll exit or it would be sold and close this quarter. So that will come out of the system. And then there is production in there for Bahrain as well. So combined, I would tell you that it probably amounts to about 50,000 to 60,000 BOE per day on a like-for-like basis, that to adjust for sort of our ongoing core production for the guidance that I gave for the full year of 2016. So that would be the reconciliation.

[Philip M. Gresh:]

Okay. And then just as you think about more broadly all of the Middle East assets, how do you see that progressing through this year?

[Vicki A. Hollub:]

Currently we're continuing with our operations in Bahrain, and we are working with our partners there to lower our exposure. But in Iraq we're progressing with the terms of the exit according to our contract terms. So we should be winding down in Iraq and that's going to be transferred to one of the national oil companies. So we will be out of there by we're hoping mid-year. Yemen, that's pretty much our contracts have expired and we're reducing our exposure in the one area that we currently have and expect to be able to exit that by mid-year as well. So everything is progressing. In Libya we're not quite to the point where we have been able to develop a specific exit strategy and specific steps because of the uncertainties around that process with the government, but we have stopped our capital investment in Libya and we're only spending the funds necessary to maintain the operation safely.

[Philip M. Gresh:]

Got it. Okay. And then, Chris, my follow up is just on the balance sheet, understanding the willingness to protect the dividend. Is there a level of debt, whether it's debt to cap or debt to EBITDA? Oxy's always been fairly conservative on the balance sheet and for good reason. Just wondering if there's a level where you get less comfortable.

[Christopher G. Stavros:]

Well whatever that level is, we don't plan to take it there. So that's one of the reasons that we maintain a strong balance sheet, that it allows us to pay the dividend and not be overly concerned about it. And I think our view is that we sort of take a measure of offense on this and sort of view ourselves as competitively advantaged as an investment vehicle within the sector. So you keep a strong balance sheet with low debt because you're a dividend payer and having a lot of debt as a company in this sector, just the two don't mix. So that's sort of how we view it.

[Philip M. Gresh:]

Okay. Fair enough. Thanks.

[Operator:]

Our next question comes from Ryan Todd of Deutsche Bank. Please go ahead.

[Ryan Todd:]

Thanks. Good morning. Maybe if I could follow up a little bit on the capital outlook over the next couple years. You highlight $500 million of committed capital in 2016 that will roll off by year-end 2016. Is there any offset to this that's set to ramp into 2017? Or should we expect, on an apples-to-apples budget, does the budget roll by $500 million into 2017? And would this likely be – would you likely fill that gap with accelerated activity in the US onshore?

[Vicki A. Hollub:]

Really in 2017 our only committed capital is the $100 million, and so we do expect the $500 million to be reduced to $100 million. And the rest of our capital program will be based on what we see with respect to oil prices. But nothing committed other than the $100 million and the maintenance capital that we'll need to allocate.

[Ryan Todd:]

Okay. And I guess maybe as one follow up to that, you're going to two to four rigs in the Permian you said for the second half of the year. Can you talk a little bit – and I guess at a high level you've provided us in the past with what you felt was kind of a maintenance CapEx number for yourself. Do you have an updated view on what your maintenance CapEx is generally as an overall business in terms of holding production flat, and maybe a similar number to what you think you need either from a rig or a spend level to keep Permian Resources flat?

[Vicki A. Hollub:]

Permian Resources is a challenge because our teams keep improving so much there. The efficiency gains they've made over the last couple of years has just been incredible. And Jody and I were talking about that this morning, and the reason we gave the range of two to four is we used to think that it would take more than four rigs to offset our decline. But we're certainly convinced now that with the efficiency gains we're having and particularly the way that Jody and his team are starting to develop the fields, we think it could be less than that. Jody, I'll let you provide some additional color on that.

[Jody Elliott:]

No, that's clearly correct, Vicki. Every day our teams amaze us with new drilling records, new production records. So predicting that exact rig count to keep production flat kind of changes month to month.

[Ryan Todd:]

But I guess is roughly the goal to size your activity levels from the middle of this year to kind of hold the Permian Resources flat? Is that roughly what you're trying to target?

[Jody Elliott:]

That level would probably – flat to slightly increasing.

[Ryan Todd:]

Great. Thank you.

[Operator:]

Our next question comes from Roger Read of Wells Fargo. Please go ahead.

[Roger D. Read:]

Thank you. Good morning.

[Vicki A. Hollub:]

Good morning.

[Roger D. Read:]

Guess I'd like to probably go down the path some of the other guys have as well. On the thinking about the drilling efficiencies and following up on the answer to the last question, two to four rigs maybe allows you to stay flat. Is it a function of more above ground, below ground or a combination of the two that's driving this? And I'm thinking of the slide 33 where you show drilling days and best is still significantly better than average. And then the comments earlier about the – I think it was specifically the benches, being able to develop those as a way to get the cost down. What's the way we should think about it maybe for 2016 and then beyond 2016?

[Jody Elliott:]

It's really about all the things you mentioned. It's drilling performance. It's well completion performance. I think the biggest gains we've had this year is the integration of our subsurface understanding into that execution activity as well, keeping wells in zone, keeping them in the sweet spot, engineering frac designs differently, optimizing cluster spacing, optimizing sand concentrations. All those things I think lead us to being able to do more with less, not just drilling days and drilling cost.

[Roger D. Read:]

And then as you think out beyond this year, what do you think gives you the greatest upside potential? Not just the bench that you mentioned earlier, is there anything else we should think about?

[Jody Elliott:]

I mentioned multi-bench. I think that's one. I think the other is really optimizing infrastructure, both our internal infrastructure and working with others to take advantage of infrastructure in the two different basins.

[Roger D. Read:]

Okay, great. And just my follow-up, unrelated. Al Hosn, I was wondering if we can get a little more of an update on just how that's performing relative to your expectations. The turnaround coming in Q1, I assume, is a normal part of the startup process. And maybe how we should think about it latter part of this year on forward.

[Edward A. Lowe:]

Yeah, this is Sandy Lowe. We're in the warranty shutdown, which is common for all these projects. And we had produced over nameplate for several weeks before the shutdown. We expect the year to give us slightly over nameplate as an average, after the shutdown of course. And it's performing very well.

[Roger D. Read:]

Great. Thank you.

[Operator:]

Our next question comes from Paul Sankey of Wolfe Research. Please go ahead.

[Paul Sankey:]

Hi. Good morning everybody. Again going back to the efficiencies, you said fairly clearly that it was reliability, productivity, optimization. Can you first try and strip out how much of the performance improvement has simply been lower oil prices and how much is organic, and sustainable? And secondly, could you highlight or contrast how you're differentiated from others in the Permian in any of those themes? Thanks a lot.

[Jody Elliott:]

I think the majority of that improvement is organic. We've gotten price improvements and we worked that part of the equation hard. But most of it is boots on the ground, engineering geoscience work, time to market improvement, integrated project planning, all those things internally which gives me high confidence that it's sustainable going forward.

[Paul Sankey:]

Right. And you think it can continue as well, I think you've said. You've talked about returns that are relatively low, what seems to be a fairly low view of the oil price for the rest of the year and beyond, even. Can you talk about what you think the breakeven price is for you guys for your returns in the Permian? And I'm aware that you've got both EOR, which is presumably a different answer from the unconventional. And then could you – I'll stop going on – but could you then also talk about how you compare to other companies in your view? Thanks.

[Vicki A. Hollub:]

First of all, Paul, I'd like to address the comparison to other companies. One of the things that we've been able to do in the Permian versus others is we've been there for a long, long time. So we've got a lot more data than other companies and we're doing more with that data. We have a lot of 3D seismic. We have, in addition to the 3D seismic, we have more than 20,000 wells from which we have data. So, and we have 4,400 outside operated wells. And I know you've heard all those numbers from me before, but we're really taking that data and taking it to the next level. We have a team that works with our resources team. And our resources team, I just have to say is incredibly efficient in what they've been able to do and to drive the drilling costs down, the completion optimization and all the things that Jody's talked about, they've done a great job. It's just been incredible. But in addition to that, the team supporting them from a downhole science standpoint is our exploitation team which takes all that data that we get from every well. And we utilize every bit of data we can, not only applying data analytics to it but taking a lot more data than the other people have access to. I think we still have the only horizontal core in the Permian. We're doing much more modeling around geomodeling and learning more about the thermal maturity and the migration of the hydrocarbons. So I think that's really helped here recently to make a big difference in the improvement of the resources wells.

[Jody Elliott:]

And I think to build on Vicki's comments, we recently held what we called a cost stand-down day where we took the entire company and stopped and said let's get creative. Let's get innovative on how we improve our business. We focused on SG&A. We focused on capital costs. We focused on operating expense. We focused on development opportunities and there's literally thousands of ideas that we have vetted and are currently vetting and that gives me even more confidence that we can move that hurdle breakeven lower for a number of these areas.

[Paul Sankey:]

And what is the hurdle breakevens on a full cycle, make your returns appropriate for Oxy basis?

[Vicki A. Hollub:]

The returns for the Permian EOR business, we have for Permian EOR a cash cost right now that's less than $20 and our DD&A is less than $10. We're continuing to drive that down. Expect that to go lower this year. So in our Permian EOR business, currently we can flex that around a bit by developing some of these ROZ developments which Jody mentioned in his presentation. Some of those developments get down as low as $3 on the F&D side. So we have a range of opportunities in the Permian EOR business that we can develop. Some of the ROZ developments that go down to an F&D of $3, those are fairly limited in size. So what we always try to do is blend the bigger projects that maybe have the $8 or $9 or $10 F&D with the smaller projects to get a blend of all of those. And on the Resources side, certainly our costs have been coming down there. The operating cost is down much lower than it was. The DD&A for our Resources business currently is higher because of the infrastructure that you always install up front. But the F&D costs, development costs on a per BOE basis is coming down. To tell you a number of where that's going to be, I think I'd hate to prematurely forecast something that I'm sure the teams are about to beat, but we're continuing to lower our costs in Resources.

[Paul Sankey:]

Just to press, can you give me a range at least?

[Vicki A. Hollub:]

On the Resources side?

[Paul Sankey:]

Yeah, I mean it's just really interesting to everyone because obviously we see it as the marginal, arguably the marginal cost of oil.

[Vicki A. Hollub:]

Yeah the Resources side I would say that we're in the total cash cost range of about $13 to $14. And we're working when we get our full development costs in line, our DD&A on the Resources side will be in the $10 range.

[Paul Sankey:]

Thank you very much.

[Vicki A. Hollub:]

Thank you.

[Christopher G. Stavros:]

Basically you've got positive cash margins here at the strip for the Permian Resources and EOR for sure, Paul. I mean that's the way I would think about it.

[Paul Sankey:]

Appreciate that. Thanks all of you.

[Operator:]

Our next question comes from John Herrlin of Société Générale. Please go ahead.

[John P. Herrlin:]

Yes. Thanks. Getting back to slide 41, will you make more of a push towards the Delaware given the relative economics of plays like the Bone Spring? And specifically for the sub $40 type inventory you highlighted, could you give me a better sense and maybe this is redundant, but could you give me a better sense of the split between the formation itself, the well design and also the infrastructure? Because obviously you're stressing the integrated nature of your approach, but certainly good rock matters. But I was wondering about how important your well design changes have been to lower that threshold?

[Jody Elliott:]

Yeah. John, that's a great question. We're really encouraged by the recent results with upsizing our fracs in the Bone Spring in New Mexico. But when you look at field development maturity and our infrastructure maturity, the Wolfbone has just got a jump start on that over on the Texas side. So early in the year, we'll be in the Wolfbone where we can take advantage of that infrastructure and as we get the field development plans matured in the Bone Spring area, incorporate more of the appraisal data that we've captured over this last year to ensure that we're as efficient as possible when we do put the rig back in New Mexico.

[John P. Herrlin:]

Okay. That's fine. Last one from me is you sold a lot of reserves during the year, about 600 million barrels. I was wondering if you could break them down geographically what you sold.

[Christopher G. Stavros:]

Yeah, the Bakken reserves were very small. I mean at the end of the day, I mean we didn't sell. These are sort of, I mean that we took down the PUDs basically in the domestic part of the business.

[John P. Herrlin:]

Okay. Thanks, Chris.

[Operator:]

And this concludes our question-and-answer session. We would like to turn the call back over to Chris Degner for any closing remarks.

[Christopher M. Degner:]

Thank you. And I'll turn the call over to Vicki for some closing remarks.

[Vicki A. Hollub:]

I just wanted to say I don't think we fully answered Paul's question. So to get back to that, in the EOR business with our cash costs and our DD&A of around $24 to $25, and then the Resources business, our cash costs and DD&A in the neighborhood of $22 to $23. That's basically about half of the price we're seeing on the strip, as Chris had said. Generally that delivers for us of about a 50% rate of return. So I just wanted to close with that.

[Christopher M. Degner:]

Okay. Thank you, Vicki, and thanks to everyone for participating on the call. Have a good day.

[Operator:]

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect your lines. Have a great day.