西方石油 (OXY) 2017 Q2 法說會逐字稿

Good morning and welcome to the Occidental Petroleum Corporation's 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, Laura.

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 and Gas; Ken Dillon, President of International Oil and 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 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, and our non-GAAP to GAAP 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 Hollub.

Vicki, please go ahead.

Thank you, Richard, and good morning, everyone.

On the first-quarter earnings call, we announced our plan to achieve cash flow breakeven after funding the dividend and growth capital.

As a reminder, over the past few years, we executed a strategic initiative to divest of lower-margin, lower-return oil and gas production, with the plan to replace it with higher-margin, higher-return production from our Permian Resources business.

This was a returns-focused strategy with the objective of ensuring that every dollar we invest delivers the highest possible returns.

To reach the cash flow needed to be breakeven at $50 WTI and cash flow neutral at $40 WTI, we determined 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'll update our progress with the plan, but first I'll share some second-quarter highlights.

On July 13, the Board approved an increase to our quarterly dividend.

This is the 15th consecutive year we have increased our dividend, and is 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, will 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 in its nearly 100-year 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 have implemented a value-based development approach, along with innovative operations and technology applications.

We are 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 Al Hosn Gas team, the plant reached operating rates 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 5, we have clarified what it means for Oxy to be breakeven at lower oil prices.

Upon completion of our plan, we'll be cash flow neutral at $40 WTI, meaning we will cover the dividend and the production sustaining capital within operating cash flow.

At $50 WTI, we will 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 a 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 6 illustrates our progress towards the breakeven plan.

The chemicals 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 a full quarter of operations from the cracker.

Additional chemicals cash flow will come in 2018 from the startup of the 4CPe plant in the fourth quarter of this year, and from improving product prices.

The midstream segment improved substantially due to widening differentials between Midland and the Gulf Coast.

Improved marketing spread was partially offset by sequential declines in NGL prices and gas processing fees.

Further increases in volume through the export terminal as well as additional de-bottlenecking of Al Hosn will also add to 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 will show the progress towards our pathway to breakeven on this same slide.

Slide 7 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 of cash as well as PAGP units with a market value of about $800 million.

We will manage our portfolio to contribute at least an additional $500 million to insure 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 sustaining capital, the dividend, and our resources growth needed for the $50 breakeven plan.

I'll 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 costs were below guidance, and capital costs are on track to meet total year guidance.

We spent approximately $800 million in 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 refund 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 sale of domestic oil and gas assets, including South Texas; and a non-cash fair value gain on our Plains equity investment.

Chemicals' second-quarter earnings were well above our guidance, as caustic soda prices continued 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 lines, slightly offset by higher ethylene and natural gas costs.

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 to Gulf Coast spreads; higher volumes to the Ingleside crude terminal; and improved foreign pipeline income, with the completion of the Dolphin Pipeline and Al Hosn planned 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 schedule in the Permian Resources and recognized cumulative uncertainty in OPEC quotas extensions, Colombia downtime, and our nonoperated 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 nonoperated 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 approximately 30% higher than 2016 levels.

We expect our capital expenditures to ramp up to about $1 billion for both the third 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 slides 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 on slide highlighted on slide 34.

I will now turn the call over to Jody.

Thank you, Cedric.

Today, I will 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 nonstrategic 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 Glasscock County that will now become a new development area.

The Permian Resources acreage 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 tale 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 this asset since we became a nonoperated partner in 2001, with an initial working interest of 7%.

Over time we increased our working interest to 53% before the recent acquisition, and now will 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 have 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's OpEx to parity with Oxy's nearby Denver Unit 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 less than $6 per BOE future development cost, which brings our Permian EOR total inventory of less than $6 F&D to almost 1 billion barrels.

We believe that Oxy's value-based 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 a 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 receive 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 in 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 have 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 have traded approximately 7,000 total net acres this year, enabling us to convert shorter wells into higher-value extended laterals, bringing our less than $50 breakeven average lateral length to 8,600 feet.

We have 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 met 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, we have updated our all-in capital intensity outlook through 2019.

This metric provides an estimate of total annual CapEx for each 1,000 barrels of annual average wedge production during a given calendar year.

Our improvements in 2017 through 2019 are the result of thoughtful development planning and creative facilities and infrastructure designs that increase facility utilization over the life of the field.

We have also progressed our subsurface characterization and focused on understanding the why, as opposed to just the what.

For example, in Barilla Draw, we utilized our advanced subsurface characterization to pinpoint 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 Lyda 16H, which contributed to an Oxy record 30-day IP of 3,200 BOE per day.

As with our inventory, we believe there's 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 of new data analytics projects represent upside opportunities.

We also expect cost savings from logistics hubs, multilateral 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 be 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 will operate five rigs in the Greater Sand 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 subsurface characterization, we expect to move additional activity to New Mexico in 2018 and beyond.

Resources is currently on a 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 a result of the value-based improvements we've discussed 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, chemicals, and midstream businesses, as each beat our second-quarter expectations.

Additionally, our teams are exceeding goals 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 have 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 oil price.

We will now open it up for your questions.

(Operator Instructions).

Doug Leggate, Bank of America.

I'm actually quite impressed that she got my name pronunciation right.

That's a first.

Anyway, 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 that it's not easy to answer in a quick question.

But CapEx is obviously backend-loaded.

It looks like OpEx cut production.

But I'm also interested in slide 17 when you are showing the 13 rig count basically coming on about six months earlier.

So can you just walk us through what the nature of that -- bringing the top end of the guidance is, and how it impacts your timing of when you expect to get the incremental -- I guess it's now 71,000 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 we're, 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 wanted to -- we now have greater clarity on the redeployment of our South Texas sale proceeds.

For example, we had said we'd be able to deploy those into -- those proceeds into Permian Resources, which we've 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 have going on, some of that production will actually go into January and February.

So the activity, we've 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 Permian in the second quarter.

We wanted to take that into account.

And we've also had some third-party plant processing outages.

In our own EOR business, we had two unplanned plant outages which are now behind us.

And we wanted to be a little bit conservative with Colombia with respect to pipeline outages.

We've 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 nonoperated position, we are seeing indications of a lot of companies now starting to cut their capital.

So we felt like there could be some risk on the upside.

And again, these are risks on the upside because we did increase our -- the bottom side of our range.

And having said all that, we felt like that it was small, but we 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 you'll be there in a couple of months -- middle of next year looks like about the number for 80,000 barrels a day.

That sound about right?

The 80,000 barrels 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 at this point to accelerate that schedule.

We've said that it would be -- happen 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 that.

Okay.

My follow-up hopefully is a quick one.

It's another slide question, I'm afraid, slide 7. It looks, if I'm eyeballing this right -- I guess you've kind of broken that out -- $0.5 billion to $2 billion of asset sales -- portfolio management, I guess you've called it.

Does that happen irrespective of the oil pricing or whether it's $40 or $50, Vicki?

And I'll leave it there.

Thanks.

What we're going to do is we're going to make the right decisions from a monetization and value standpoint.

So where there are assets that we certainly feel would be best monetized for them to add value to the shareholder, that's what we'll do.

We're don't have -- we're 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.

Thanks for the answers.

I appreciate it.

Charles Robertson, Cowen and Company.

Thank you for all of the updates on the operational side.

But my question comes -- I would appreciate your thoughts behind the 15th consecutive year of raising your dividend.

And if you could expand on that, appreciate it.

Thank you.

Yes, 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 that there are holders that expect that to happen, and that 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 and our breakeven, that we will then be able to grow the -- our dividend more in line with our value growth.

All right.

Thank you very much.

Evan Calio, Morgan Stanley.

Welcome back, Cedric.

Thanks, Evan.

My question on the strategic plan, that your strategic plan now involves 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 either lower the $50 threshold, or could that allow the growth to drive higher?

I'm just trying to understand how you see the upper end evolving with the improving productivity or commodity price.

Well, one thing that we do expect to see is that we do expect efficiency improvements.

This plan that we have rolled out is very conservative.

It does not include many of the things that Jody's team's working on in the Permian Resources business.

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 is the improved recovery and OpEx reductions.

So I think that this -- certainly our plan is conservative.

So with a $50 oil price, there would be potential for further increases, -- in terms of production.

But what we want to do is make the best decision.

So we would just look at market conditions.

We'd look at our other opportunities for use of capital, and make a decision as to what's the best thing to do.

I believe, over time, because of the assets we have, we have the potential to grow more.

But we will make those decisions as we get to those -- to that point.

Great.

And second on the -- my second question on the Permian.

In your locations you have 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?

Or just that color around that process I'd appreciate.

Yes, and this is Jody.

Thank you for the question.

Yes, we have achieved that goal that we set out of 400.

I'm still working on your stretch goal for me 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 into New Mexico, longer laterals.

You see in the slides that we've extended our average lateral length in the inventory, and that doesn't stop.

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 of that this last time.

So probably not every quarter an update on inventory, but maybe every other quarter we would provide an update.

Great.

I'll leave it there.

Thanks, guys.

Phil Gresh, JPMorgan.

Vicki, I think one of the concerns I've heard from investors with the cash flow targets that have been outlined is just the timing of it.

You mentioned end of 2018 or early 2019.

So I was just hoping maybe you could frame up some of the interim milestones you are thinking about here.

Potentially exit rates, 2017, how much of this you think you might be able to achieve.

And I guess I'm thinking perhaps the midstream, the chemicals pieces, et cetera.

Do you think you could get $500 million to $600 million of this by the end of 2017?

Or anything else you'd 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 a 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 toward our goal by that time.

But some of the other things will happen in mid to late 2018.

For example, we expect the Al Hosn expansion will be certainly before the end of 2018.

The 4CPe 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'll 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 closer things are immediate cash flow next quarter from the JV, the 4CPe beginning of 2018, and then we're looking at Al Hosn toward the end, and the incremental growth from the Permian.

While it wasn't a straight line from the time we announced it, it's -- 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 2018.

So the growth in 2018 is going to be well above the 30% CAGR for Permian Resources.

Got it.

Okay.

And then you've outlined how you see the balance sheet progressing -- or, from a cash standpoint, how you see things progressing to help fund your growth plan.

I'm wondering how you think about acquisitions at this point.

You did the swap, et cetera.

But would you say that there are, in the next 12 to 18 months, acquisitions are still something you are looking at?

Or is it more just the organic growth and the portfolio management on the other side?

It's going to be mostly organic growth.

Now, where we see opportunities to continue to increase our working interest or do both on acquisitions, we would do those.

But I -- 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 ask just one last one.

Vicki, I kind of asked you about this at a conference a month ago.

But perhaps you could just refresh us on the 5% to 8% growth rate and this long-term target, versus maybe targeting a slightly lower growth rate and covering the dividend sooner.

And I ask this in the context of seeing a lot of E&P companies out there missing numbers, stocks getting hit on weaker production outlooks.

And it seems like the cash flow oriented stocks have been the ones that have been doing much better on the execution front and from a share price perspective.

So just curious on your thoughts on this.

Yes, I 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 -- it's 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're cash flow neutral at $40 and breakeven at $50 with a 5% to 8%, we will be -- and we will stay within cash flow.

And we expect over time our cash flow to continue to increase, and that's our goal.

Okay.

Thanks, Vicki.

Roger Read, Wells Fargo.

Maybe to follow up on Phil's question there on the dividend for -- well, the growth rate potentially why not talk about maybe a higher growth rate in the dividend, or some growth rate in the dividend, versus a slightly slower production growth number at $50?

On sorry, Phil -- could you repeat that question?

You're asking why not grow -- I'm sorry, Roger.

You're asking (multiple speakers)

Yes.

So the dividend is laid out at 2.4 or 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 production growth and the dividend is secure at $40?

Am just trying to make sure I understand where you -- you are laying out a drilling plan to 2019 and a 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 shown you.

However, once we get beyond that, the growth in the dividend will be consistent with our value proposition in that we will grow that accordingly.

So as we're growing production, growing value, growing cash flow beyond the breakeven plan, then 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 cash.

But it's not that the dividend will not grow.

It will, beyond this breakeven plan.

Okay, great (multiple speakers).

Yes, it does.

More of a timing issue here of 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 looked like outperformance versus type curves.

I was just wondering, is that predominantly lateral length, which looks like some of it?

Or is this -- kind of what's driving that improvement?

Yes, 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 rock volumes, so that connection to the reservoir; and lateral length.

It's really all of those things.

If I had to weight them, I'd probably say that the landing point and stimulation changes are driving the bulk of that.

Okay.

I appreciate it.

Thank you.

Paul Sankey, Wolfe Research.

I guess it would be remiss of me not to ask you about gas/oil ratios, given your position in the Permian, the scale of your position, and your experience.

What's your perspective on this latest controversy that's emerged as regards Oxy's competitive position?

Thanks.

Paul, this is Jody.

Thank you.

I think as we've talked all along, we've really emphasized our subsurface work, whether that's geologic work or reservoir engineering.

And so, the understanding of GOR behavior, we've -- it not new to us.

This is not a surprise for our assumptions.

We model; we do more than just decline curve analysis.

We have multiple B factor changes that go through the life of this well.

We model the GOR increase.

When you get to bubble point, we use great 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 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.

Well, Jody, I was playing gas-oil ratio bingo there, and you scored a point for bubble point, but you didn't manage to throw in big data.

(laughter) Thanks.

The big data -- or really it's analytics.

It's not big data; it's 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, or 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 EUR predictions, on our type curves predictions, even more as we move forward.

It is some of the technology things that Vicki mentions that really aren't baked into this cash flow to breakeven plan.

They act as upsides for us as we continue to solve those kind of tough problems out there.

Can you contrast -- I mean, 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?

So, our activity set over the next several years is predominantly in the Delaware Basin.

Where we are positioned, we have good rock positions; it's 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, in due course, dividend increases.

I think the market is getting tired of what is quite a modest aim, ultimately, to be at breakeven.

But it feels as if the opportunity set is better than it ever has been.

And can you not be more ambitious about your dividend growth over time?

For example, pinning it to future volume growth, assuming that 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 myself down to a range on that, but that's really (multiple speakers) target.

Well, you fell for that trap (laughter).

(laughter) But that's our goal.

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.

Pavel Molchanov, Raymond James.

You have broken out your PAGP holding of $0.8 billion in the slides.

And I remember the last time you sold some of this -- and I think this was about 2 1/2 years ago -- is there a threshold for the yield on that stock where you would feel compelled to monetize it?

Yes, 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 Plains 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 are throwing off good cash.

We think it's a well-run company with good assets.

And so we're happy to continue to hold onto those units and look for an opportunistic time to sell them, down the road.

And then a 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 other words, if oil were $10 lower than your baseline, wouldn't sustaining capital be meaningfully lower than $2.1 billion, potentially?

Sustaining capital does go down with oil prices.

Because we would expect, as you are alluding to, service company costs -- and some of our CO2 is tied to oil prices, so it would go lower.

With the estimate that we have on our slide, though, is what we believe today without significant efficiency improvements.

So it's conservative.

Okay, clear enough.

Appreciate it.

Brian Singer, Goldman Sachs.

A couple questions on the Permian.

You highlighted the shift in -- the coming shift in rigs into New Mexico.

And 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 on 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 risks 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 to New Mexico is really grounded in our capital intensity calculations.

New Mexico, because of the stacked pays and very good stacked pays -- it's not like you have a primary bench, and then three or four secondaries; there's three or four primary benches that compete very well, very high returns.

So it's that nature that drives us toward more New Mexico.

Second in the tier would be the Texas Delaware and then Midland Basin.

Those two aren't that different.

But they just have different production profiles with the wells as we drill them.

That's why we're more dominated with our activity set over on the Delaware side.

The risks of drilling with vertical wells, a lot of the areas we are developing are not historical vertical development, or they were done in a way that you still have a lot of room between those vertical wells for not having any collision areas.

A lot of our New Mexico development that we're going to is clean acreage and very little historical development.

And if it was, it was in shallower reservoirs.

We've got a long history of this.

You've got to remember, we've been in the Permian for a long time, have 25,000 wells, a lot of experience dealing with both vertical and now horizontal activity.

We are 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 have set themselves up well for continued horizontal development.

Great, thanks.

And then on the technology side, can you give us an update of some of the technology solutions you are deploying, such as -- I think multilateral well is one that you highlighted in the past.

And if there's more to say on some of the predictive analytics slide than you already said, that would be great.

But specifically what the impact is on production or capital costs today.

Yes.

We've got a great -- a number of slides in the appendix that lays out the different projects that we're working.

We've made a lot of progress here recently, and one around reservoir management of our injectants.

So both in Ken's business in Mukhaizna with steam, and in Northern Oman with the water flood, and then in our EOR business with CO2 floods, we are deploying 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 injectant goes on a greater frequency.

And so what that does is it allows us to get of the biggest bang for the buck for every molecule of injectant that we put in the ground.

So those are starting to get rolled out.

And it's -- from a technology standpoint, that's all being done in the cloud.

So from an IT standpoint, we're able to do this work from Oman, all the way back here to Houston.

And again, that's our starting point, but that technology applies to all three geographic areas.

On the drilling side, we're pushing out our bit trajectory data analytics tools.

So we've been through our early round of validating where the bit is, based on surveying equipment being 45 or 60 foot behind the bit.

That's now starting to get -- we'll 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 your 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's a long list that we continue to push forward on the technology front.

Thanks.

And the multilateral wells, have there been any examples there yet, or is that --?

We're continuing to -- as we've spoke before, we have one that we have completed the stimulation on.

We have others planned.

The impact of multilateral is really when we move into our second and third and fourth bench kind of developments.

So we continue to move down that path.

No new news there on multilateral.

Thank you.

Jeffrey Campbell, Tuohy Brothers.

Vicki, I just wanted to ask you: I'm looking at the various illustrations of the $40 and $50 per barrel spending, and the 30% CAGR in the Permian Resources, and your remarks about replacing sold 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 if the spending that you're outlining is really necessary to drive the efficiencies that are going to continue to lower costs further out.

Will, first of all, as long as we're investing our dollars in things that deliver rates of return that are better than our cost of capital, we will 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 slide 7 shows the liquidity that we'll have available to support that, if that was the second part of your question, at $40.

And this all assumes $40.

But one other thing that I was just curious about is that -- in addition to investing for rates of return and so forth, there's been a lot of illustration throughout the slides on driving costs lower over time.

And I was wondering if --

Yes.

-- also part of this is you want to get to a certain scale over the next 18, 20 months, that that's going to help to drive costs further, even going further out.

Yes.

We set the $40 and $50 as milestones.

And we do believe that going forward beyond that -- 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 over time we will continue to lower our cash flow neutrality, that we will continue to improve our operations and drive our costs down and our margins up.

So this, to us, is just a milestone.

And Cedric, you had something to add?

Yes, this is Cedric.

I'd just say that the point of slide 7 was to show you, at $40, that we've got a 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.

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 Wolfcamp A and the Wolfcamp B are your core zones in the Midland Basin.

But there has been pretty good success in the Lower Spraberry in the Midland Basin, as well.

I was just wondering, is that a zone that you are looking at?

Does that have a possibility of maybe become a third core zone over time?

Yes, it does.

And in this new core development area that the transactions allowed us to develop, there's Spraberry activity there as well.

In New Mexico it's 2nd Bone, it's 1st Bone, it's 3rd Bone, it's the XY; it's another zone in between the XY and the Wolfcamp, it's --.

That's the beauty of New Mexico, again, is there's more what I would call premium benches per acre of opportunity that we have.

And if I could, just going back to what Brian was asking about: when you look at all those juicy basins in New Mexico, do you think of some -- of a minimum amount of development that you'll do with individual wellbores?

And then at some point later on, you will come in with the multilaterals?

Or how are you thinking about that?

Yes, so we take the multilateral -- we view multilateral as 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's BLM acreage, we are trying to minimize our footprint.

And so if you have multiple benches, that's a lot of wellheads 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 multilateral in that future development or not.

Yes, that's a great point.

Thanks very much.

And this concludes our question-and-answer session.

I would like to turn the conference back over to Vicki Hollub for any closing remarks.

Thank you.

To close, I'd 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 aligned 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 Colombia.

They will provide significant cash flow for multiple decades, so we do have sustainability.

So I'd like to thank you all for joining our call today, and wish you a happy day.

Thanks.

The conference is now concluded.

Thank you for today ending today's presentation.

You may now disconnect.