Occidental Petroleum Corporation (OXY) Q2 2017 Earnings Report, Transcript and Summary

Good morning and welcome to the Occidental Petroleum Corporation second quarter 2017 earnings conference call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Richard Jackson, Vice President of Investor Relations. Please go ahead, sir.

Thank you, Lora. Good morning, everyone, and thank you for participating in Occidental Petroleum's second quarter 2017 conference call. On the call with us today are: Vicki Hollub, President and Chief Executive Officer; Jody Elliott, President of Domestic Oil & Gas; Ken Dillon, President of International Oil & Gas Operations; Cedric Burgher, Senior Vice President and Chief Financial Officer; and Rob Peterson, President of OxyChem. 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 the 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 second quarter 2017 earnings press release, the Investor Relations supplemental schedules, our non-GAAP to GAAP reconciliations, and the conference call participation slides can be downloaded off our website at www.oxy.com. I'll now turn the call over to Vicki Hollub. Vicki, please go ahead.

Thank you, Richard, and good morning, everyone. One the first quarter earnings call we announced our plan to achieve cash flow break even after funding the dividend and growth capital. As a reminder over the past few years we executed strategic initiatives to divested lower margin, lower return oil and gas production but to replace it with higher margin, higher return production from our Permian resources business. This was a return focus strategy with the objective of insuring that every dollar we invest delivers the highest possible return. To reach the cash flow needed to be break even at $50 WTI and cash flow neutral at $40 WTI. We determine we would need incremental production of 80,000 BOE per day from Permian resources along with the additional cash flow that was expected from our chemicals and midstream businesses. Today I will update our progress with the plan but first I will share some second quarter highlights. On July 13, the board approved an increase to our quarter dividend, this is the fifteenth consecutive year we’ve increased our dividend and as indicative of our core belief that dividend growth drives long-term share price appreciation. We believe dividend growth along with the earnings growth that will be generated from our returns focused pathway to breakeven, we’ll maximize shareholder return over the long-term. The confidence that I, our board and our management team have in our ability to significantly grow shareholder value is based on the quality of our assets, the capability of our organization and the strength of our pathway to breakeven. Our pathway to breakeven begins with the best portfolio of assets that Oxy has had and it’s nearly 100 years history. But it’s not enough to have great assets, we must also ensure we continue to increase margins through further cost reductions. To accomplish this, we’ve implemented a value based development approach along with innovative operations and technology applications. We’re seeing exciting progress across all of our assets. Our value based development approach has already resulted in 400 additional Permian resources locations year-to-date with breakevens under $50. We expect further additions through the remainder of the year exceeding our original guidance of 400 location additions during 2017. And finally, with the efforts of the housing gas team the plan reached operating rate of 75,000 BOE per day net to Oxy. We’re also managing our portfolio, during the quarter we announced multiple Permian transactions which resulted in the addition of low decline assets that will increase our operating cash flow by $80 million in 2019, with no incremental cash outlay. Turning to slide five, we have clarified what it means for Oxy to be breakeven at lower oil prices. Upon completion of our plan, we will be cash flow neutral at $40 WTI, meaning we’ll cover the dividend and the production sustaining capital within operating cash flow. At $50 WTI, we’ll also be able to generate 5% to 8% production growth. This chart walks you through the milestones we need to achieve this plan. Our entire organization is laser focused on our breakeven plan, in fact we introduced this plan as the key metric for our compensation across the organization. All the decisions that management will make in the upcoming quarters will align with achieving these goals. Slide six, illustrates our progress towards the breakeven plan. The chemical segment achieved a full quarter of operations at the new Ingleside ethylene cracker. However, our first cash distribution from the JV will be received in the third quarter due to funding of JV working capital during the second quarter. We did benefit from additional caustic soda volumes associated with the full quarter of operations from the cracker. Additional chemicals cash flow will come in 2018 from the startup of the fourth CPE plan in the fourth quarter of this year and from improving product prices. Then mid-chain segment improves substantially due to widening differentials between Midland and the Golf Coast. Improved marketing spread was partially offset by sequential declines in the NGL prices and gas processing fees. Further increases in volume through the export terminals as well as the additional debottlenecking of our hosing will also add to our cash flow. Our oil and gas segment added 9,000 BOE per day of high margin production from Permian resources bringing us closer to our production target. And finally, as I said earlier, Permian transactions will improve annual cash flow generation by $80 million in 2019 at $50 WTI. Each quarter we'll show the progress towards our pathway to breakeven on the same slide. Slide seven quantifies the liquidity we have available to fund the gap between cash flow from operations and the capital needed to achieve our goal of cash flow breakeven at low oil prices. At the end of the second quarter, we had $2.2 billion in cash as well as TIGP units with a market value of about 800 million. We will manage our portfolio to contribute at least an additional 500 million to ensure we bridge the cash gap, if prices average $40 through 2018. To be clear even with an average oil price of $40 through 2018, we have sufficient cash and liquidity to cover sustained capital, the dividend and our resources growth needed for the $50 breakeven plan. I will now turn the call over to Cedric Burgher.

Thanks Vicki, Jody will cover our Permian activity so I will address other significant items. Total reported production was 601,000 BOE per day with ongoing production coming in at 594,000 BOE per day which was at the top end of our guidance range. Domestic operating cost were below guidance and capital cost are on track to meet total year guidance. We spend approximately $800 million on our capital program with the majority of our $3.6 billion capital budget anticipated for the second half of the year. As a reminder, we received our tax-free fund of approximately $750 million during the second quarter. Second quarter core earnings per share was $0.15 with cash flow on track for our breakeven plan. Reported income included one-time gains on the sales of domestic oil and gas assets including sales taxes and a noncash fair value gain on our plains equity investment. Chemicals second quarter earnings were well above our guidance as caustic soda exceeded priced continue to increase based on a favorable supply and demand balance and low inventory levels. Chemical production and sales volumes were stronger than anticipated across most product line slightly offset by higher ethylene and natural gas cost. The second quarter Chemicals income also benefited from a full quarter of contributions from the joint venture ethylene cracker in Ingleside, Texas. However, our first cash distribution will not be received until the third quarter. The cash distribution will be approximately $50 million which includes some catch up from the second quarter. Midstream second quarter core earnings also came in above our previous guidance reflecting improved Midland and Gulf Coast spreads, higher volumes to the Ingleside crude terminal and improved foreign pipeline income with the completion of the Dolphin pipeline in our Hosn plant maintenance in the first quarter. Midstream improvements were partially offset by lower NGL prices and gas processing fees. On Slide 10, second quarter cash flows included $600 million in proceeds from the sales of assets including South Texas and $360 million in acquisition payments primarily related to the Permian resources and international operations. With respect to guidance please refer to Slide 11 in today's investor presentation. Our full year 2017 ongoing production guidance has been narrowed to a range of $597,000 to $605,000 BOE per day. From prior guidance of 595,000 to 615,000 BOE per day, the low end was raised to reflect the new production increase from the previously announced Permian transactions. The high end of the range was reduced as we finalized our ramp up scheduled in that Permian resources and recognized accumulative uncertainty in OPEC quarters [ph] extensions, Columbia downtime and our non-operated production growth timing. Permian resources total year production guidance has been narrowed with an adjustment only to the top end of our guidance to reflect the sale of our Permian resources acreage and our non-operated production growth timing. EOR production guidance has been increased to reflect the other part of that transaction. We continue to expect production in Permian resources to exit this year at a growth pace of approximately 30% higher than 2016 levels. We expect our capital expenditures to ramp up to about $1 billion for both the third quarter and the fourth quarters and our full year capital spending to be about $3.6 billion. Lastly, I would like to call your attention to our investor slide appendix which has been reorganized to include additional details on our business including several slides on our environmental, safety and governance framework and commitment. Since joining Oxy in late May, I have been thrilled to learn more about OXY’s industry leading efforts in Carbon sequestration which we have highlighted on slide 34. I’ll now turn the call over to Jody.

Thank you, Cedric. Today, I’ll provide an update on our Permian business and the improvements we’ve made to the portfolio that will contribute to OXY’s cash flow breakeven goals. In June, we announced a series of transactions that monetized non-strategic Permian resources acreage to accomplish two things for us. One, enhance our low decline Permian EOR business and two, core up in an area of glass cut county that will now become a new development area. The Permian resources we divested had less value in OXY’s portfolio because of the expected timing of development, so we used it to provide liquidity to accelerate OXY’s pathway to cash flow breakeven and increase the value of our portfolio. We will continue to evaluate the tail of our Permian resources portfolio for additional value adding opportunities. The Seminole-San Andres Unit we acquired produces from the world-class San Andres reservoir and is a natural fit in our industry leading Permian EOR portfolio. Oxy has strategically pursued these assets since we became a non-operated partner in 2001, with an initial working interest of 7%. Overtime, we increased our working interest to 53% before the recent acquisition and now we’ll operate the assets with an 87% working interest. Our reservoir management expertise, operating experience and scale provide cost reduction and production optimization opportunities that will increase the value of this asset for Oxy. We’ve identified cost improvements of $5 per BOE that we target to realize by year-end 2017 and have an upside target of $10 per BOE that will bring the Seminole-San Andres Unit OpEx to parity with OXY’s nearby Denver Units CO2 flood. Turning to slide 14, beyond the operating cost opportunity, we have provided an initial estimate of resource potential for the Seminole-San Andres Unit. We estimate approximately 100 million barrels of resource potential with the less than $6 per BOE future development cost, which brings our Permian EOR total inventory of less than $6 FND to almost 1 billion barrels. We believe that OXY’s value base development approach which is grounded in subsurface characterization, operating capability and innovative technology along with the synergistic benefits from our scale in the area will provide significant upside to our initial resource estimates. I’d also like to highlight one additional milestone in the EOR business. In January, the US EPA approved the second monitoring, reporting and verification plan for injecting and storing CO2 safely in the Permian Basin as part of our CO2, EOR operations. Oxy was the first company to received EPA authorization for EOR with CO2 sequestration in 2015. EPA approval of these plans represents an important milestone in the development and commercialization of carbon capture, utilization and storage technology as an approach for long-term management of greenhouse gas emissions. We believe OXY's assets and expertise and enhanced oil recovery and CO2 sequestration provide a long-term competitive advantage under various possible carbon pricing scenarios in the future. Moving to Permian resources on Slide 15, we achieved our 2017 target of adding 400 locations to our less than $50 WTI breakeven inventory. We now have approximately 16 years of inventory at a 10-rig pace with less than a $50 breakeven. Improved capital efficiency and well performance added 255 locations and are based on repeated performance improvements from well design and technology that are sustainable and have further room for improvement. We've traded approximately 7000 total net acreage this year enabling us to convert shorter wells into higher value extended laterals bringing our less than $50 breakeven average lateral link to 8600 feet. We’ve also evaluated approximately 15,000 new net acres which added 100 locations to our less than $50 breakeven inventory. Our inventory now covers approximately 302,000 net acres which includes the effect of the divestitures during the year. As we progress our value based development approach we see continued potential for improvement in our inventory by applying new technology and enhancing operating efficiency. We continue our subsurface characterization to customize the development plans and well designs that will maximize the value of each section. Although we meet our 2017 less than $50 breakeven target of 400 locations, we believe we still have opportunity to further grow this number by year end. On Slide 16, updated our all-in capital intensity outlook through 2019, this metric provides an estimate of total annual CapEx for each 1000 barrels of annual average wage production during the given calendar year. Our improvements in 2017 to 2019 are the result of thoughtful development planning and created facilities infrastructure designs that increase facility utilization over the life of the field. We've also progressed our subsurface characterization and focused on understanding the why as opposed to just to what. For example, in Barilla Draw we utilized our advanced subsurface characterization that pin point a specific landing zone that would allow for maximizing SRV within the Wolfcamp A. This identification and execution of the why, resulted in a well specific landing point for the light of 16 edge, which contributed to an OXY record 30-day IP of 3200 BOE per day. As with our inventory we believe there is still upside to further improve our growth plans, all of our forecast assumptions are based on demonstrated performance where we have enough data to conclude that the improvements are sustainable. Our most recent improvements in well productivity, capital efficiency and improvements from applications and new data analytics projects represent upside opportunities. We also expect cost savings from logistics hubs multi-lateral drilling and additional water recycling that have not been recognized in the plan. We estimate there could be at least another 10% improvement as we continue development in our core areas through 2019. We believe our capital intensity is best in class and will the primary driver in providing OXY's growth while generating cash in 2019 and beyond. Turning to Slide 17, I'll provide an update on Permian resources drilling activity. Permian resources exited 2Q with 11 operated rigs an increase of four from the end of the first quarter. The increase in second quarter activity was late in the quarter which will primarily benefit production in the fourth quarter of 2017 and the first quarter of 2018. In the second half of 2017, we’ll operate five rigs in the greater San Dunes area, four rigs in the Greater Barilla Draw area and two rigs in the Midland Basin. As we build out infrastructure and progress our subservice characterization, we expect to move additional activities in the Mexico in 2018 and beyond. Resources are currently on the 30% CAGR trajectory based on our current development activity plans. You will also see that we lowered our expected rig count in 2018 and 2019 by one rig for both scenarios which is the result of the value based improvements we’ve discussed and that improved our inventory and reduced the capital intensity. I’ll now turn the call back over to Vicki Hollub.

Thank you, Jody. We’re fully on track to achieve our plan as shown across our oil and gas chemical industry businesses as each beat our second quarter expectations. Additionally, our teams are exceeding goal to increase value within the plan, we’ve already met our Permian resources inventory improvement goal by adding 400 additional locations below $50 breakeven, and we expect to add more. We were able to complete multiple Permian transactions to add value and enhance our plan as announced this quarter. We ended the quarter with more cash on the balance sheet than we had at the end of the first quarter and we have ample liquidity to fully fund our plan at any old price. We will now open it up for your questions.

[Operator Instructions] And our first question today will come from Doug Leggate of Bank of America.

So, Vicki, I wonder if I could just ask you to elaborate a little bit on the full year guidance. There seem to be a number of moving parts and I know it’s not easy to answer that in a quick question. But, CapEx is obviously backed loaded it looks like OpEx cut production but I’m also interested in slide 17 when you’re showing this 13-rig count basically coming on about six months earlier. So, can you just walk us through what the nature of the bringing the top end of the guidance is and how that impacts your timing of when you expect to get the incremental I guess is certainly 1,000 barrels a day in the Permian. I’ve got a follow up, please.

Okay. Thanks Doug. Our guidance really does not indicate any change in our confidence or in our pathway to breakeven as we’ve laid out. Actually, this is just a narrowing of the guidance, our business teams are progressing and working and achieving exactly what we need them to and actually where as I mentioned in my script, we’re really ahead of schedule in terms of performance. But there are several reasons that we did it, first we increased the low end of our range 2,000 barrels a day to account for the increased second half production as a result of our Permian transactions. And then we -- secondly, we now have a greater clarity on the redeployment of our South Texas sale proceeds. For example, we had said we would be able to deploy those into those proceeds and the Permian resources which we have done. And that activity is taking place in the second half of this year and now we expect that with the pad development that we had going on, some of that production will actually go into January and February. So, the activity we got better clarity on the timing of that. Third, our updated range really reflects some uncertainties around a number of things that have happened. Earlier in the year we had expected that the announced six-month quotas for OPEC would be in place and now that’s been extended for a full year. Also, we've had some impacts of electrical storms in the Permian in the second quarter, we wanted to take that into account and we've also had some third-party processing outages. In our own EOR business we had two unplanned plant client outages which are now behind us and we wanted to a be a little bit conservative with Columbia with respect to pipeline outages we been able to manage that recently and expect to be able to manage it but we don’t feel that there will be upside there. And then with respect to our Permian non-operative positive we are seeing indications that a lot of companies now starting to cut their capital. So, we feel like there could be some risk on the upside and again there are risk on the upside because we did increase the bottom side our range. And having said all that we felt like that it was small but wanted to make sure that we provided clarity around what we expect.

Just to be clear on Slide 17 the earlier addition or move to 13 rigs I guess would be there in a couple of months, middle of next year looks like about the number for 80,000 barrels per day is that right?

The 80,000 barrel a day really is going to be dependent on our efficiency improvements and how well we're able to move from pad to pad, logistics and several things. So, I'm not prepared to just to accelerate that schedule, we've said that it would be happened by the end of 2018 or first of 2019. I don’t think that we see anything right now that would prompt us to change them.

Okay my follow up hope is quick one, is another slide question on Slide 7, it looks as if I'm eyeballing this right, I guess you have broken it out, 0.5 billion to 2 billion of portfolio management I guess you called it, is that half in respect of the oil pricing or whether its $40 to $50 [indiscernible], I'll leave it there. Thanks.

What we're going to do is, we’re make the right decisions from a monetization and value stand point, so where they are assets that we certainly feel would be best monetized for them to add value to the shareholders that’s what we will do. We not going to monetize things that are not value adding, meaning we’re not going to sell assets that we think would add more value if we kept them for development. So, we will look at that and make the decisions as we go, we're not going to try to target any upper end; we just think we need to make the best value decision.

Our next question will come from Charles Robertson of Cowen and Company.

Thank you and thank you for all the update on the operational side but my question comes, I would appreciate your thoughts behind the 15th consecutive year of raising your dividend and you could expand on that appreciate it. Thank you.

As I said we felt like that, we have extreme confidence in our plan and we know we can execute this. So, we felt it important to continue to increase our dividend. We know that there are holders that expect that to happen and needs to happen for some of the holders of our stock. We wanted to do a modest increase at this point and expect that as we achieve our cash flow neutrality in our breakeven that we will then be able to grow our dividend more in line with our value growth.

And our next question will come from Evan Calio of Morgan Stanley.

On the strategic plan, your strategic plan now evolves this lower stress case at 40. And given the capital efficiencies can you discuss the $50 side and is the 5% to 8% growth is that the sweet spot for growth or where improvements would rather lower to $50 threshold or could that allow the growth to drive higher. Just trying to understand how you see the upper end evolving with improving productivity or commodity price?

Well, one thing that we do expect to see is we do expect efficiency improvements. This plan that we’ve rolled out is very conservative, it does not include many of the things that Jody’s team is working on in the Permian resources business. And it also really doesn’t take into account some of the things internationally that we’re seeing that great success with, with respect to some of the capital efficiency improvements there as well as the improved recovery in OpEx reductions. So, I think that certainly our plan is conservative, so with the $50 oil price there would be potential for further increases, but in terms of production, but what we want to do is make the best decision so we would just look at market condition, we’d look at our other opportunities for use of capital and make a decision is to what’s the best thing to do. I believe overtime, because of the assets we have, we have the potential to grow more. But we’ll make those decisions as we get to that point.

Great. And my second question on the Permian. In your allocations, you’ve achieved your full year guidance to add the 400 horizontal locations sub 50 by mid-year versus full year. Maybe you discuss what drove that earlier, does that mean you are ahead of your guidance and should we expect another update before year-end. Just color on that process would appreciate.

Yeah, this is Jody. Thank you for the question. Yeah, we have achieved that goal that we set out of 400. I’m still working on your stretch goal of 600 locations as well. But we do think we can continue to progress that better well productivity, some really innovative things around pad development sequencing, moving a little more activity over the next year and in the Mexico longer laterals you see in the slides that we’ve extended our average lateral length in the inventory. And that doesn’t stop, right so I think that will continue to add sub 50 inventory. Plus, we’re marching through the other 300,000, 350,000 acres that we really haven’t fully evaluated. We knocked off another 15,000 this last time. So, probably not every quarter an update on inventory but maybe every other quarter we would provide an update.

And our next question comes from Philip Gresh of JPMorgan.

Vicki I think one of the concerns I've heard from investors with the cash flow targets that have been outlined its just the timing of it, you mentioned end of '18 early '19, so I was just hoping that you could frame up some of the interim milestones you're thinking about here potentially exit rate '17, how much of this you think you might be able to achieve and I guess I'm thinking perhaps the mid-stream the chemicals pieces etcetera, do you think you could get 500 million to 600 million of this by the end of '17 or anything else you would be comfortable sharing on that front?

I think that certainly -- I think by the end of this year we will make more progress, we're going to see probably our biggest incremental changes in beginning in Q1 of 2018 because lot of the ramp up in Permian resources will really start to pay off in Q1. So, I would certainly expect to have significant incremental progress towards our goal by that time. But some of the other things will happen in mid like 2018 for example we expect the [indiscernible] expansion will be certainly before the end of 2018, the four CPE will be at the beginning of 2018 that’s the plant in Louisiana. We're going to see next quarter as we mentioned, the cash flow from the cracker starting to come in from the JV, so that should actually be happening next quarter, will help toward the end of this year. We expect that we will see incremental from the export terminal, we do plan to expand it a bit, but we're not sure the timing on that but that could also occur later in 2018. So, the closure things are immediate cash flow next quarter from the JV, the four CPE beginning of 2018 and then we're looking at [indiscernible] toward the end and the incremental growth from the Permian, while it wasn’t a straight line from the time we announced it, over the next couple of quarters is really they are ramping up, they are going to start, they will see good fourth quarter production and then they are on a very strong trajectory going into the 2018. So, the growth in 2018 is going to be well above the 30% CAGR from Permian resources.

And then you outlined how you see the balance sheet progressing from a cash standpoint, how you see things progressing to help fund the growth plan. I'm wondering how you think about acquisitions at this point, you did the swap etcetera but when you say they are in the next 12 to 18 months acquisitions are still something you're looking at or is it more just your organic growth in the portfolio management on the other side.

That going to be mostly organic growth. Where we see opportunities to continue to increase our working interest or do bolt on acquisitions we would do those. But we're so confident with this organic execution plan that we have that we're really focused on it and making sure that happens.

Okay if I could just ask one last one, Vicky I kind of asked you about this in other conference a month ago, but perhaps you could just refresh us on the 5% day growth rate in this long-term target versus may be targeting a slightly lower growth rate and covering the dividend sooner and I ask this kind of in the context of seeing a lot of E&P companies out there missing numbers, stocks getting hit on a weaker production outlooks and it seems like the cash flow oriented stocks have been doing much better on the execution front and from a share price perspective. So, just curious on your thoughts on this.

Yeah. I’m want to emphasize that our growth rate right now and what we’re doing over the next 18 months is, we’re just replacing cash flow from those assets that we exited or divested. So, this high growth rate that you’re seeing is a consequence of that, we need to replace the cash flow, we want to do that as quickly as we can and beyond that once we are cash flow neutral at 40 and breakeven at 50 with the 5% to 8% we will be -- we will stay within cash flow. And we expect over time, our cash flow to continue to increase. And that’s our goal.

And our next question comes from Roger Read of Wells Fargo.

Yeah. Thanks. good morning. Maybe the follow up on Phil’s question here on the dividend, for the growth rate potentially why not talk about maybe a higher growth rate in the dividend or some growth rate in the dividend versus slightly slower production growth number at $50?

I’m sorry Greg -- Phil, could you repeat that question, you’re asking why not growth, I’m sorry, Roger you’re asking…

Yeah. So, the dividend is laid out at 2.4, 2.4 and then the production growth and just kind of getting back to the question that Phil asked. Why not talk about dividend growth blended with production growth as opposed to just a production growth number, or is just the goal here the toggle is always is production growth and the dividend secure at 40. I’m just trying make sure I understand where you kind of you’re laying out a sort of a drilling plan in 2019 and our productivity plan. How does that come back to the dividend?

Right. In this interim as we are on this breakeven plan, the dividend is going to be -- the increases will be modest as we’ve just show you. However, once we get beyond that the growth in the dividend will be consistent with our value proposition and that we’ll grow that accordingly. So, as we’re growing production, growing value, growing cash flow beyond the breakeven and our dividend at that point will certainly start to resume a healthier growth rate. And it will be according to at that point what the best use of capital is, best use of the cash. But it’s not that the dividend will not grow, it will beyond this breakeven plan. Does that answer that Roger?

Okay. Great. Yeah it does, more of a timing issue here getting through this period and then focus on it. Okay. And then Jody maybe switching gears to you or Vicki if you want to keep on with it. In the appendix slide 25, 26, I think there was one or two more showed, it look like outperformance versus type curves. I was just wondering is that predominantly lateral linked which looks like some of it or is this kind of what’s driving that improvement?

Yeah, Roger it’s a combination of things. It is better, continued subsurface understanding and progression and refining our landing points, changing our stimulation designs to maximize stimulated rod volumes so that connection to the reservoir and lateral length is really all of those things. If I had to wait, I might probably say that the landing point in stimulation changes are driving the bulk of that.

And our next question comes from Paul Sankey with Wolfe Research.

I guess to would be remising me not to ask you about gas, oil ratios given the opposition in the Columbian scale of your position in your experience. What's your prospective on this latest controversy that too [ph] much as regards OXYs competitive position.

Paul this is Jody, thank you. I think as we've talked all along we really emphasize our subsurface work whether that’s geologic work or reservoir engineering and so the understanding of GOR [ph] behavior, it's not new to us, it is not a surprise for our assumptions, we model, we do more than just decline curve analysis, we have multiple defector [ph] changes like go through the life of this well, we model the GOR increase when you get to bubble point, we use rate transient analysis, we use reservoir modeling so it is a full cycle engineering analysis. And so, our plans have got those reservoir behaviors built into our forecast over the next couple of years, our GORs actually stay fairly flat based on the mix of new development and declining development. So that’s well understood by us and built into our plan.

Looks like as though was playing the gas oil ratio bingo there and you excluded points for bubble point but you didn’t manage to throw in big data.

Thanks, the big data is really is analytics, it's not big data, its analytics that helps us get even better at that, so we're adding statistical models on top of the engineering analysis whether it's in reservoir, whether it's in geology, completions drilling, we're seeing that across the board with our analytics projects and that just refines our confidence on our EOR predictions, on our type curve predictions even more as we move forward. It's some of the technology thing that Vicki mentioned that really aren’t based into this cash flow to breakeven plan, they act as upsides for us as we continue to solve those kind of though problems out there.

Could you contrast, I know you are all over the Permian but can you talk about how things differ across acreage and where you might be differentiated or not as the case may be as regards some of these issues.

Our activity set over the next several years is predominantly in a Delaware basin, where we're positioned where we had good rock positions, its geo pressured for most of those benches that extends the period of time before you start having GOR effects. So, I think we're well positioned from an inventory standpoint relative to some of our competitors with respect to GOR.

Got it, Vicki if I could just pin you down slightly, you're talking a lot about breakevens and then as you cost dividend increases, I think you know the market is getting tired of what is quite a modest time to ultimately to be a breakeven. But it feels as if the opportunities is better than it ever has been and can you not be more ambitious about your dividend growth over time, I'm for example pinning it to future volume growth assuming the margins were constant. Wouldn’t it be reasonable to say that in the future we can get a 5% to 8% annualized dividend growth as our target? Thanks.

I do expect that to be not only possible but likely, I just didn’t want to pin my sub down to a range on that, but that’s really time to target [Multiple Speakers] but that’s our goal, it’s in the interim we’re just trying to get to the milestone of being able to then refocus and get our dividend growth back.

Thank you. And our next question comes from Pavel Molchanov of Raymond James.

Thanks for taking the question. You’ve broken out your PAGP holding of $0.8 billion in the slide. And I remember the last time you sold some of that, I think it’s about 2.5 years ago. Is there a threshold for the yield on that stock where you would feel compelled to monetize it?

Yeah, Pavel this is Cedric. Really our approach is to be opportunistic, we have a number of assets in our portfolio that don’t produce cash or not much and those would be likely candidates for sale earlier. But clearly the plant units from a long-term perspective are not core to our business and therefore a source of liquidity. But, the way we look at it they’re throwing off good cash, we think it’s a well-run company with good assets and so, we’re happy to continue to hold on to those units and look for an opportunistic time to sell them down the road.

Okay. Quick question about the sustaining capital under the $50 versus $40 scenarios. The difference is only 10%, $200 million, is there a certain amount of conservatism in another words if oil were $10 lower than your base line wouldn’t sustaining capital be meaningfully lower than in 2.1 billion potentially?

Sustaining capital does go down with oil prices because we would expect as you’re alluding to service company cost and some of our CO2s tied to oil prices. So, it would go lower, what the estimate that we have on our slide though is what we believe today without significant efficiency improvement. So, it’s conservative.

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

Couple of questions on the Permian. You highlighted the coming shift in rigs in to New Mexico. Wondered if you could talk a little bit more about the decision to do that and the implications on the returns there versus the returns elsewhere in the Permian portfolio like the Southern Delaware and Midland Basins and also given that it’s topical, can you speak to how you see the rest associated with navigating drilling horizontal wells around areas where there are legacy vertical wells particularly in the Midland?

Yes, Brian the reason for the shift in the Mexico is really kind of grounded in our capital intensity calculations. The Mexico, because of the stack pace and very good stack pace is not like we have a primary bench and then three or four secondaries'. There are three or four primary benches that compete very well, very high returns and so it’s that nature that drives us toward more in the Mexico kind of second in the tier would be the Texas, Delaware and then Midland Basin. I mean, those two aren’t that different but they just have different production profiles with the wells as we drill and that’s why we're in a more dominated with our activity still [ph] on the Delver side. The risks of drilling with vertical wells a lot of the areas we're developing are not historical vertical development or they were done in a way that you still have a lot of room between those verticals wells for not having any collision areas. A lot of our New Mexico development that we're going to is clean acreage in very little historical development if it was, it was in shallower reservoirs. We got a long history of this. You’ve got to remember, we've been in the Permian for a long time at 25,000 wells, a lot of experience dealing with both vertical and now horizontal activity, we're doing more horizontal activity in our legacy EOR properties and on the central basin platform. So, it's something very manageable for us and I think the properties that we set themselves up well for continued horizontal development.

Thanks, and then on the technology side can you give us an update of some of the technology solutions that you're deploying such as I think most had lateral wells, one that you highlighted in the past. And if there is more to say on some of the predictive analytics, but then you already, that would be great, but, what the impact is on production or capital cost today.

We've got a great number of slides in the appendix that lays out the different projects that we’re working. We made a lot of progress here recently in one around reservoir management of our injecting. So, both in Kim's business and [indiscernible] with steam and then northern Oman with the water flood and then our EOR business with CO2 floods we're deploying kind of the early versions of those tools that combine essentially low fidelity reservoir models with the statistical models that we can make changes in where our injecting goes on a greater frequency and so what that does, it allows us to get the biggest bang for the buck for every molecule of injecting that we put in the ground. So those are starting to get rolled out and from a technology standpoint that’s all kind be done in the cloud. So, from an IT stand point, we’re able to do this work from Oman all the way back here to Houston and again that’s our starting point but technology applies to all three geographic areas. On the drilling side we're pushing out our bit trajectory data analytics tool, so we've been through kind of our early round of validating where the bid is based on serving equipment being 45 or 60 foot behind the bit, that’s now starting, start beginning to get penetrated across multiple rigs and what that does is it again it keeps you in zone, it allows you to build you curves more accurately because you know where you are instead of projecting where you are and that results in better wells, if you stay in zone longer. So that’s a couple of examples but there is a long list that we continue to push forward on the technology front.

And the multi-lateral wells, have there been any examples there?

We're continuing to as we spoke before, we have one that we have completed the stimulation on, we have others planned. The impact of multi-lateral is really when we move into our second and third and fourth bench kind of development. So, we continue to move down that path kind of no new news there on multilateral.

And our final question today will come from Jeffrey Campbell of Tuohy Brothers.

Good morning. Vicki, I was just wanted to ask you, I’m looking at the various illustrations of the $40 and $50 per barrel spending and the 30% CAGR and the Permian resources and your remarks about replacing solid cash flows. Is the overall message that you’re going to maintain this spending plan through 2018 regardless of oil prices or is there any chance that you would pull back if prices really swooned. And in particular what I’m trying to understand is that the spending that you’re outlining is really necessary to drive the efficiencies that are going to continue to lower cost further out?

Well first of all, as long as we’re investing our dollars and things that deliver rate of return that are better than our cost of capital, we’ll continue to execute this plan. That also assumes that the fundamentals are there to support oil prices that are at least close to $40, because that’s about where we get the returns that we feel are appropriate for our dollar invested. With respect to, I think in slide seven shows the liquidity that we’ll have available to support that if that was the second part of your question at 40. And this is all for this 40.

But one other thing that I was just curious about is that and in addition investing for rates of return and so forth there has been a lot of illustration throughout the slice on driving cost lower overtime. And I was wondering if also part of this you want to get to a certain scale over the next 18 months to 20 months, that that’s going to help to drive cost further even going further out?

Yes, we set the $40 and $50 as milestones and we do believe that going forward beyond that in and again those are conservative because we haven’t baked in a lot of the things that we’re trying that we believe have a good possibility of working out. So, we do believe that overtime we’ll continue to lower our cash flow neutrality that will continue to improve our operations and drive our cost down and our margins up. So, this to us is just a milestone. And Cedrick, you have something to add?

I'll just say that the point of slide seven was to show you at $40 that we’ve got the liquidity path that works obviously, so we’re planning for the worst if you will, if things were to go below that on a sustainable basis then we would of course reassess the whole world probably would, but even as low as $40 WTI, we’ve got a path that this plan we can execute from a liquidity standpoint.

Okay. Well, that was really helpful. And just going back quickly Jody to your remarks about the multiple core opportunities in New Mexico as opposed to Texas and Midland. Slide 26 highlights that the Wolf Camp A and the Wolf Camp B are your core zones in the Midland Basin, but there has been pretty good success in the lower spread very in the Midland Basin as well. I was just wondering is that the zone that you’re looking at, does that have the possibility to maybe become a third core zone overtime?

Yeah. It does and in this new core development area that the transactions allowed us to develop their spray berry activity there as well, in New Mexico its second bone, its first bone its third bone, its XY, it's another zone in between the XY and the Wolfcamp, that’s the beauty of New Mexico again as there is more what I would call premium benches, per acre of opportunity that we have.

And if I could just, kind of going back to what Brian was asking about, when you look at all those two C [ph] basins in New Mexico, do you think of minimum amount of development that you will do with individual well bores and at some point, later on you'll come up with the multi laterals and how you’re thinking about that.

We take the multi-lateral -- we view multi-lateral as kind of an arrow in the quiver, it's one of many tools we have in our development plan. So, areas where we are location constrained, there are some environmentally sensitive areas that we operate in, there is BLM acreage, we're trying to minimize our footprint and so if you have multiple benches that’s a lot of well heads if you do them all by one well at a time. So, we take that into account when we think about the development plan of an area of whether we want to deploy multi-lateral in that future development or not.

And that concludes our question and answer session. I would like to turn the conference back over to Vicki Hollub for any closing remarks.

To close I would just like to reiterate our excitement and our confidence in our plan. The quality of our assets, the capability of our organization and the strength of our pathway to our breakeven plan is well understood by our organization and we're completely in line toward achieving our goals. But looking beyond our breakeven plan we're also confident in our ability to sustain our value proposition for the foreseeable future and that does include meaningful dividend growth beyond this breakeven plan. In addition to the multi decade reserves and resources that we have in the Permian basin and the long-term cash flow from OXYChem, we also have long-term contracts in the Middle East and Columbia and they will provide significant cash flow for multiple decades. So, we do have sustainability. So, I would like to thank you all for joining our call today and wish you happy day. Thanks.

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