西方石油 (OXY) 2018 Q1 法說會逐字稿

Good morning, and welcome to the Occidental Petroleum Corporation First Quarter 2018 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, Investor Relations.

Please go ahead.

Thank you, Kate.

Good morning, everyone, and thank you for participating in Occidental Petroleum's First Quarter 2018 Conference Call.

On the call with us today are Vicki Hollub, President and Chief Executive Officer; Cedric Burgher, Senior Vice President and Chief Financial Officer; Jody Elliott, President of Domestic Oil and Gas; and BJ Hebert, 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, as more fully described in our cautionary statement regarding forward-looking statements on Slide 2. Our earnings press release, the Investor Relations supplemental schedules and our non-GAAP to GAAP reconciliations and 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.

Our first quarter key highlights demonstrate the significant progress we made to increase the value of our business while delivering free cash flow and value-based growth.

Our low oil price breakeven plan will be achieved in the third quarter, 6 months ahead of our original estimate.

This accelerated schedule has been driven in part by better-than-expected performance from Permian Resources, which added 18,000 BOE per day this quarter, and is currently on a trajectory to deliver a 47% year-over-year growth rate.

This will be accomplished with only 11 operated rigs.

We're truly doing more with less, as we demonstrated by our increased guidance in all business segments.

It is important to note that our breakeven plan not only provides us with the ability to continue value growth in a low-price environment, it delivers significant upside in a higher oil price environment.

Slide 8 illustrates how leveraged our Permian EOR business is to higher oil prices.

EOR will generate significant incremental cash flow in the prevailing environment.

Similarly, chemicals and midstream have been positioned for long-term value creation, and are capitalizing on today's pricing and marketing spreads to generate substantial improvements in free cash flow versus our breakeven plan.

We have increased our full year guidance for these 2 businesses, and they are actually capable of generating over $2 billion of annual free cash flow.

As we did last year, we will continue to focus on enhancing our portfolio, increasing the value of our assets and using technology to drive superior operational performance.

On Slide 5, I'd like to point out a few important Permian Resources achievements during the first quarter.

First, we continued to bring wells online at basin leading rates and Greater Sand Dunes with an average 30-day IP of 31 BOE per day.

We also increased new well performance by nearly 50% in our current Barilla Draw development area.

Third, to support our growth in the region, we brought online our logistics and supply hub, Project Aventine.

We have already started to see the benefits of our differentiated approach in well cost improvement and reliability of wellsite resources.

Turning to Slide 6. Our value proposition has not changed.

It is enhanced.

The achievement of our breakeven plan strengthens our ability to provide a meaningful dividend with growth while maintaining a strong balance sheet, and will allow us to resume opportunistic share repurchases.

The part of our value proposition that we have significantly enhances our ability to exceed our oil and gas production growth targets with industry-leading returns.

The quality of our assets and the depth of our development inventory will enable us to deliver higher returns and higher growth rates within our cash flow from operations.

We believe our meaningful dividend, with a production growth rate greater than 8%, is a unique value proposition within our industry.

Our last slide, 7, illustrates the differentiated approach Oxy takes in developing our assets.

Across our businesses, we're focused on long-term value creation through exceptional technical work, life cycle planning, project execution and operations focused on maximizing margins.

In our oil and gas segment, our goal is to get the most oil out of our rock in the fastest time, at the lowest cost, and to sell at the highest price.

This means we start by understanding the potential of the reservoir through enhanced subsurface characterization.

This is not only critical to producing the best wells under primary development, but also under future EOR applications.

To ensure best time to market and service costs, we have developed operational capability and technology, created strategic logistic networks and relationships, and built key infrastructure, including our Ingleside Oil Terminal to access world refining markets.

As a result, we believe we are the best positioned company in the Permian to execute on the value-added growth strategy.

The benefits of our strategy are yielding significant productivity improvements, increased capital efficiency and better product price realizations.

We expect our differentiated approach to result in peer-leading value creation.

I'll now turn the call over to Cedric to review our progress towards the breakeven plan and our financial results.

Thanks, Vicki.

I will begin with an update on our breakeven plan, and then address financial results and 2018 guidance.

On Slide 10, we have updated our progress towards our breakeven plan at low oil prices.

We continue to make substantial progress on our plan and our exceeding targets across our businesses.

In an effort to be conservative on sustainable cash flow, we adjusted our first quarter cash flow from operations for positive seasonality and market-related items in midstream and chemicals, net of turnarounds in the Middle East, which is represented by the gray bar.

Once we achieve our remaining milestones, we will be well positioned in the future with the cash flow necessary for our $40 oil price business sustainability and $50 oil price business growth scenarios.

But we will continue to operate our business to reduce those breakevens even further.

Slide 11 illustrates our progress towards the breakeven plan.

In the chemicals business, the 4CPe plant began contributing to cash flow, and will achieve peak operating rate in the third quarter of this year.

We categorized additional chemical product pricing improvement as seasonal in the gray bar of other improvements to maintain conservatism in our plan.

In the midstream business, the Midland to Gulf Coast spread for the first quarter came within our guidance at $3.12 per barrel.

Additional midstream margin improvements for crude export, gas processing and crude inventory sales were categorized as seasonal in the gray bar of other improvements.

We also had planned turnarounds in the Middle East, which reduced quarterly cash flow, but will be back to normal rates in the second quarter of this year.

In the Permian Resources business, we grew 18,000 BOE a day, sequentially leaving 32,000 BOE a day, to achieve our breakeven plan goal.

Jody will give additional guidance on the timing of new wells online and production.

Shifting to our quarterly financial and operating results on Slide 13.

I'd like to start with our production results.

Total reported production for the first quarter was 609,000 BOEs a day, which exceeded the high end of our guidance of 603,000 BOEs a day.

Much of this was driven by execution and well productivity in Permian Resources, which came in well above the high end of guidance at 177,000 BOEs a day.

International also contributed to the production beat with our planned first quarter turnarounds at Al Hosn and Dolphin ahead of schedule and successful step-out wells in Colombia.

Total international production came in at 273,000 BOEs a day, above the high end of guidance of 271,000 BOEs a day, even after 2,000 BOEs a day of production impacts from production-sharing contracts.

Earnings improved across all segments, and our first quarter reported and core EPS was $0.92 per share.

Improvements in the oil and gas segment were mainly attributed to higher oil prices and lower DD&A rates.

Realized price -- oil prices increased by 14%, and our DD&A rate for the first quarter was 10% lower than the average 2017 DD&A rate.

Operating cash flow before working capital improved sequentially to nearly $1.7 billion, due to higher oil prices along with higher Permian Resources production as well as higher contributions from the chemicals and midstream segments.

We spent $1 billion in capital during the first quarter, in line with our full year capital plan of $3.9 billion.

We issued $1 billion in debt to retire $500 million of notes that were due in February, and for general corporate purposes.

Working capital changes included cash payments typical of the first quarter, including property tax and payments against our fourth quarter accruals.

Our chemicals and marketing businesses also experienced a working capital draw as the result of a receivable billed due to higher prices and volumes.

Chemicals first quarter core earnings of $298 million, came in above guidance of $250 million.

Pricing for caustic soda and other products continue to increase as global demand remain robust and purchased ethylene prices declined throughout the quarter.

Midstream first quarter core earnings of $179 million also came in well above our guidance.

Included is a gain on the sale of a domestic gas plant for $43 million.

Excluding the gain, midstream reflected improved earnings from crude exports, gas processing, and higher equity income from the Plains All American investment.

The better-than-expected result also included income from items considered timing related, such as crude inventory sales.

Our updated guidance is provided on Slide 15.

With respect to full year 2018, we raised our total production range in spite of a negative production-sharing contract impact of about 5,000 BOEs a day since our first quarter guidance.

The increase to the Permian Resources production range was mainly attributable to new -- improved new well productivity.

Jody will give additional detail on the outlook for our Permian Resources business.

International production is expected to benefit from Al Hosn volumes ramping back up to average 66,000 to 69,000 BOEs a day during the second quarter, and 83,000 BOEs a day in the third quarter.

Qatar will have planned downtime during the second quarter, which we expect to impact production by approximately 6,000 BOEs a day.

Our guidance now assumes $63 WTI and $67 Brent prices for the second through fourth quarters.

The guidance for the total year capital budget is maintained at $3.9 billion.

In midstream, our improved second quarter and full year guidance reflects the significant increases in Permian to Gulf Coast spreads.

In chemicals, our guidance increases primarily are due to higher caustic soda prices, and we now assume that they remain at current levels.

Our DD&A expense for the oil and gas is lower as a result of low refining and development costs last year.

First quarter domestic operating expense was up slightly over last quarter due to front-end loaded workover and maintenance activities in Permian EOR.

Lower operating costs in Permian Resources, which are forecasted to average under $7 per BOE, are expected to be offset by higher costs in Permian EOR for oil price-sensitive purchased injectant and higher energy-related costs.

We have updated our guidance for the total company effective tax rate to 32% in 2018, which reflects higher earnings from our domestic oil and gas business.

To close, we are off to a great start to the year, and we expect to reach a major milestone with the achievement of the breakeven plan in the third quarter.

We are significantly ahead of schedule right now, and we'll evaluate opportunistic uses of excess cash flow that we expect to be generated in the remainder of the year.

These could include sustaining current activity levels in Permian Resources, improving our balance sheet through net debt reduction and more investment in international and Permian EOR.

Last, and certainly not least, we now intend to resume our long-standing share repurchase program this year.

As a reminder, we have approximately 64 million shares remaining in our buyback program authorized by our Board of Directors.

Since the inception of the program, we have repurchased approximately 121 million shares for nearly $9 billion.

I'll now turn the call over to Jody.

Thank you, Cedric, and good morning, everyone.

Today, I'll provide an update on the continued improvements in our Permian operations and the progress we've made in delivering high-margin production growth to contribute to our breakeven plan.

2018 is off to a great start.

Our value-based development approach continues to deliver record wells, and operational improvements are lowering cost and reducing time-to-market.

On Slide 18, you'll see that our Permian Resources, New Mexico team delivered another quarter of play-leading results.

We turned 16 new Greater Sand Dunes wells to production that average 30-day rates of 3,100 BOE per day, which is in line with the step-change in productivity that began in the second half of 2017.

I also want to highlight a 2-well pad in the Wolfcamp XY bench that delivered an average 30-day peak rate over 10,000 BOE per day.

As shown on Slide 50, in the appendix, many of these record wells in New Mexico were stimulated with significantly less proppant than the industry average, which results in lower well cost and higher full-cycle value.

We continue to integrate our vast seismic data with improved geomechanic and petrophysical analysis that enable us to land the wells and the best part of the rock and stimulate the rock with a customized frac.

Our customized stimulation designs rely on our subsurface characterization workflows and analytics to balance well productivity with incremental cost, ensuring we're developing each section for maximum value.

Lastly, in New Mexico, we continue to appraise and delineate our acreage across Greater Sand Dunes.

We delivered 1 2nd and 1 3rd Bone Spring appraisal well in a field called Red Tank in the northern part of Greater Sand Dunes, which delivered an average 30-day peak rate of 2,300 BOE per day per well.

We're excited about these results, as they provide additional low breakeven inventory for future growth.

On Slide 19, we've updated our Permian Resources quarterly production guidance, and increased the midpoint for total year by 2,000 BOE per day.

Production in the first quarter of 177,000 BOE per day was above the high end guidance, which was driven by better-than-expected well results in Greater Sand Dunes and Greater Barilla Draw, and less downtime than expected from artificial lift installations on many new wells.

Many of the artificial lift installations scheduled for the first quarter were delayed to the second quarter, as pressure in the new wells remain high and were able to flow longer without intervention.

We expect to install lift on these wells in the second quarter, and the associated downtime is included in our production guidance.

Turning to Slide 20, I'll provide an update on Aventine, our maintenance and logistics hub located in Southeast New Mexico.

Since this one of a kind facility in the Permian began operations in February, we received sand from 14 separate unit trains, and supplied sand for 31 completions across Texas and New Mexico.

In March, the oil country tubular goods part of the facility became operational and since received approximately 1,400 tons of pipe, with over 1,000 tons delivered by rail.

We also began servicing wells with the new SANDSTORM system, which has reduced the number of trucks required to supply sand to the well site, and reduce the amount of time each truck takes to unload.

While the facility has started providing cost savings for our new wells, it also plays an important role in ensuring we can execute our plan.

As activity has ramped up, we've been able to avoid logistics and supply problems by servicing our wells from Aventine.

We expect this facility will be fully operational by the end of the third quarter, providing a competitive advantage for us in the Permian.

Finally, on Slide 22, we're delivering operational execution improvements that are reducing the cost of our wells and accelerating production by reducing time-to-market.

We've increased drilled feet per day, 23% in New Mexico, and 17% in Texas since the first half of 2017.

These efficiencies are a result of better well designs and improved wellsite operations from our proprietary Oxy drilling dynamics.

We've also seen improvements in our completions in New Mexico, where we achieved a 19% improvement in stages pumped per day compared to the first half of 2017.

These first quarter improvements demonstrate our strong executional capabilities and provide a foundation for us to bring online the wells we forecasted for the year with a potential for upside.

2018 will be a great year for our domestic assets.

Our Permian EOR business will continue to generate significant free cash flow while finding innovative ways to operate mature fields at lower cost.

Permian Resources is growing high-margin production at the lowest capital intensity level in its history, and providing cash flow for long-term sustainability.

And thanks to investment in our midstream business, we're positioned to maximize price realizations with oil and gas transportation agreements to the Gulf Coast with volumes in excess of our current equity production.

Lastly, we're also continuing to build future opportunities by advancing our understanding of EOR and unconventional rocks, and we'll provide updates in future calls.

I'll now turn the call over to Vicki.

Thank you, Jody.

I'd like to close by congratulating 2 members of our team on role changes.

Richard Jackson will be moving into Jody's team to lead our operations support groups.

Richard has been an incredible asset for the Investor Relations team, and will continue to be actively involved with our IR activity.

He has done an incredible job to change our communication and our -- and sharing our story with our investors and shareholders.

Replacing Richard as VP of Investor Relations is Jeff Alvarez.

Jeff most recently led the Permian Resources Texas Delaware business unit as President and General Manager.

Jeff's extensive international and domestic experience has prepared him to be our investment community spokesperson.

Richard and Jeff have a long working history together and will be transitioning over the next few months.

We'll now open it up for questions.

(Operator Instructions) The first question is from Brian Singer of Goldman Sachs.

Congratulations to Rich and Jeff.

Vicki, share repurchases have not been vocally high in the pecking order for use of free cash.

Can you talk to how you and the board will determine the magnitude and the timing of share repurchase?

And whether you view repurchases as more temporary to deploy excess free cash flow from above mid-cycle margins in midstream and pet-chem versus something more ongoing as an augmentation to Oxy's dividend?

It's important to note that, historically, we've always had a very active share buyback program.

And as Cedric mentioned, from 2005 to 2015, we had bought back about $9 billion in shares.

That's why we were paying a dividend over that time period of about $17 billion.

That dividend that we paid had a -- over that time period, had a CAGR of almost 14%.

So even though we pay a healthy dividend, share buybacks are a part of our cash flow priorities.

And in fact, we -- in our last presentation, on Slide 6, for the last quarter, we had listed that share buybacks would be a possibility in an environment above $60.

The reason we haven't talked about it here recently is the fact that we wanted to get a line of sight to see whether or not prices were going to remain that healthy, and we also wanted to get closer to our breakeven plan to resume our buyback program.

As for the amount, as Cedric said, we have quite a volume of share repurchases that are authorized by the board for us to make.

We'll begin those this year, but it really depends on the market conditions, pricing and other opportunities.

Great.

And then to shift my follow-up to the Permian.

You're planning an acceleration in the number of Permian Resources wells brought online in the second and third quarters, and you've guided to an acceleration in production and growth in the third and fourth quarters.

But what are the moving pieces around that and potential upsides?

What type of well productivity improvements, if any, have you factored in versus what you're seeing?

And how should we think about the natural decline rates in Permian Resources?

Brian, this is Jody.

We tend to take a cautious approach to updating our type curves and projections on new wells.

So as we get data beyond the 24-hour IP, beyond the 30-day IP, we really want to start seeing consistency in the 6-month cumes or even the 1-year cumes, we start up -- moving up our type curves.

So some of that is baked into this forward guidance.

The wells on line count, that we're confident about that given all the investment in Aventine and the logistics work and the improvements in our execution.

The variability in those numbers is really just the fact that a lot of these land right at the end of the quarter.

And so a few wells moving in or a few wells moving out changes your count, but it doesn't appreciably change your production forecast.

The next question comes from Guy Baber of Simmons & Company.

I wanted to start with just a point of clarification on the midstream.

But just to confirm here, the slide show that for every $0.25 per barrel widening in the spread, that's another $45 million of cash flow, annualized to the midstream, which is clear.

However, there is, I believe, a partial offset in terms of your upstream realization.

So can you just confirm for us what that sensitivity is on a net basis to Oxy at the corporate level, inclusive of the midstream benefits, but also accounting for the hit to the upstream realizations?

I just want to make sure that we're triangulating to the right bottom line as the guidance is premised upon a $6 to $7 spread, obviously, but we're currently sitting closer to $15 on a spot basis.

Guy, this is Cedric.

And that's a good question.

The net is about $30 million, so the $45 million minus $15 million.

I think that answers it.

Okay.

Perfect.

And then for my follow-up here, I wanted to ask an ops question.

But Jody, you alluded to this, and you have a slide on this in the back of your deck, Slide 50, I believe.

But you highlight how you all have drilled some of the most prolific wells in the basin in the last 12 months with a step function improvement in the recent quarters, yet you're seeming to do that without any meaningful increases in your completion intensity and at a completion intensity that's well below average for peers.

So that appears to bode pretty well for your capital efficiency.

So can you just talk about that dynamic in a little bit more detail?

Just trying to better understand the sustainability there, and what you're seeing kind of leading edge on the capital efficiency front.

Yes.

Guy, thank you for the question.

This all really starts with subsurface characterization.

It's what we've been talking about over the last year of improvements on geomechanics, geochemistry, and integrating our seismic and advancing our petrophysical modeling to better understand what we call flow units, and then how those flow units will behave with a stimulation.

That leads to then a better stimulation design that's customized for basically each well.

But from that customization comes efficiency gains built around standardization.

So all of the execution with leveraging Aventine with how we execute in the field, delivery of sand, the commercial arrangements that support that, then turn something that's very customized into something that's very manufacturing oriented.

So the combination of those things is really what's driving what we believe is kind of play-leading capital efficiency.

The other piece in the middle that I want to highlight is what the team does in the round of -- in the area of field development planning.

So they take all of those attributes and then optimize what's the best way to develop the field, or the different flow units.

Do we do them concurrently, do we do them individually?

How do you pace the rigs, how many rigs, how many frac cores?

And there's many, many iterations on trying to optimize that.

And the ultimate goal is maximum value per section.

And so our teams have gotten very, very good at that, but they also retain flexibility in those field development plans, so as we have new learnings, we have surprises, both positive and negative, we can adjust those plans accordingly.

So we really are hitting on all cylinders from subsurface through execution at the well head.

Congrats to you as well, Richard.

Thanks, Guy.

The next question is from Phil Gresh of JPMorgan.

First question is just on capital spending for this year.

The -- if I look at the Permian, specifically, they wells online in the first quarter are a fairly small percentage of the total year plan.

But the CapEx in the Permian, if I just take your guidance from the fourth quarter call divide it by 4, is tracking ahead of that.

So I just want to get an understanding of how -- it sounds like it was in line with your own expectations, but I just want to get an understanding of how you think about -- how that plays out.

And if you can maybe just dovetail in the comments about potentially looking to spend more capital to sustain activity levels in the international investments that you talked about?

Yes.

I'll let Jody cover a little bit more about the lumpiness of the resources business and what we had expected to see in the beginning of the year.

But when we laid out our program, we intentionally designed it so that toward the end of the year, we would have the flexibility to ramp down, and that's built into the capital program for 2018.

What we wanted to do is to be -- have the flexibility to ramp down to our $3.3 billion capital in 2019, if we were seeing a $50 environment -- so which is what we'd talked about.

Since we're not sure what pricing will do in 2019, and we want to stay within cash flow with our capital programs in the future, we haven't set that yet.

So what you're seeing is an upfront loaded 2018 capital.

With respect to how the wells fit into that, I'll let Jody talk about that.

Yes.

When you think about the plan for this year, the front end is considerably loaded with more facility activity.

In fact, in the second quarter, we'll be commissioning 2 large facilities in New Mexico.

And so as you move through the year, even though some of the well count is going up on a completion side, you're offsetting that with less facility spending.

That's -- the wells are also the plays where all of these efficiencies -- the benefits of Aventine which are just starting and which will grow over the year start coming into play.

And if I could just clarify, Vicki, the second part of that question around the activity levels and the potential for further investment in international and EORs, is that something that would lead to spending above the [3 9] for the year at this stage?

At this point, we haven't made any decisions regarding that, but what I will assure you is that we have flexibility.

We have a vast inventory of not only things to do in the Permian, but internationally.

We -- our opportunities are pretty much unlimited at this point with respect to what we're seeing.

But for the program this year, we haven't made any decision yet to increase our capital.

What we would consider doing at the most probably would be to sustain the activity level we have at this point.

But what we haven't made that decision yet.

We'll see how things look in the next -- over the next few months.

Got it.

Okay.

And then my follow-up is just around the balance sheet.

In past quarters, you've had slides there, where you've talked about asset sales as a means of bridging some of your spending gap, which obviously at higher prices isn't as necessary.

But does that mean that you're not looking to monetize these assets anymore?

And just in general, when you talked about your debt reduction objective, what would be the goal at this stage?

Where do you want gross debt or net debt, whatever metric you choose to go by?

This is Cedric, Phil.

On monetizations, we'll always be looking at high-grading, improving our portfolio.

If there are things that we can get a good value for that aren't core or strategic to us, then certainly would be looking at those kind of exits from the -- what we just did in the first quarter with the gas plant really wasn't -- we got a good price for it, and it was essential to what we needed to do.

In a lot of those, particularly in midstream areas, we can contractually cover our needs just as easily, you don't necessarily have to own the assets.

So there aren't any new big plans necessarily, but at the same time, we'll always be opportunistic with improving our portfolio.

With respect to the balance sheet and debt, we don't have a precise target other than we want to be at the strong side of the group within this -- the peer group.

We've got a good credit rating, a good strong balance sheet, and we would like to make some improvements to it.

But there's not -- there's nothing that's kind of a must have.

So improving the net debt with some of the organic cash flow we expect to be generating over the next few quarters is also on the list of things we'd like to do.

The next question is from Doug Leggate of Bank of America.

Richard, you're not going to (inaudible) good luck in your new role.

Two quick questions, if I may.

(technical difficulty)

I'm sorry, Doug, but you're cutting out.

Could you try to repeat that question for us, please?

Sorry, I apologize.

Can you hear me now?

Yes.

Okay.

So when I saw you last, you talked about achieving the milestone for cash breakeven as a potential turning point for the new Oxy strategy going forward.

I'm just wondering what you think is the right level of growth for a company of your size.

What do you think your portfolio can support?

I think what the portfolio can support and what we would be -- what's appropriate and prudent to do are maybe 2 different things.

Our portfolio would support significant growth rates, but we believe that our growth rate, certainly above 8%, is where we can be very efficiently and effective, and we think that that's the -- a growth rate that would be appropriate for our dividend level and for the other cash flow priorities we have, as we mentioned earlier, buybacks.

I'm not sure where that ultimate number would be.

It really depends on how efficient we get and how -- what types of projects come up.

But certainly, one of the things we always want to do is stay within cash flow, so it'll be somewhat driven by prices.

I appreciate that.

But just to be clear, as compared to the current 5% to 8% target, right?

That's right.

Because currently we've averaged 5% to 8% over the years.

We now have the capability to go well above that.

And how far above that we go, to say it more clearly, is going to be dependent on prices and cash available.

My follow-up is probably for Cedric, if you can still hear me.

Cedric, buybacks and dividend growth kind of go hand in hand, meaning that on a per-share basis, buybacks amplify dividend growth.

So I'm just curious, how do you think about the dividend policy going forward, in the context of restarting the buyback program.

Is that a per-share growth target on the dividend or an absolute CAGR on the dividend amount?

I'll leave it there.

Thanks, Doug.

No, on dividends, really our philosophy has not changed.

We are absolutely committed to the dividend as we've proven through the downturn.

We're not just sustaining it, but growing it at a modest rate.

It'll be dependent on our view of -- dividend is a long-term commitment.

Share buybacks are more opportunistic.

This may be the way to say it.

But on the dividend, we would look to continue with modest increases.

Because it's a long-term permanent commitment, if you will, the dividend, we look to do that at a more mid-cycle price.

So today, plus or minus $50 is what we have in mind.

So with the higher price, as we showed last quarter on Slide 6 of last quarter's presentation, that buybacks come into play when you are in a significantly higher price than $50 but -- so we kind of run our business on a $40 to $50 price deck in terms of being prepared for lower prices, running a low-cost business, and then look for dividend increases as we continue to improve our efficiencies, our well productivity, the Aventine, all of the things we've been talking about to drive our breakevens lower, we'll continue to do that.

And that's what will position us potentially for further dividend increases.

The next question is from Leo Mariani of Nat Alliance Securities.

Just wanted to follow up on one of the earlier comments that you guys made.

Obviously, your breakeven has been pushed forward to the third quarter, obviously, that's nice.

You talked about potentially higher CapEx later in the year, but you kind of specifically said that, that will likely be portioned over to International EOR.

I just wanted to kind of get your thought on that.

Why those areas versus Permian Resources, for example?

Do you see better returns in International EOR?

What's the thought behind that?

So for 2018, the -- if we increased our capital, it would be not beyond the program we currently have planned for international.

The -- if we -- any increase in capital this year would be to just sustain the Permian Resources business.

We do have some capital allocated to our international assets to do some appraisal work and evaluation for a little more aggressive program internationally, in 2019, if prices permit.

But that's probably what you're talking about is just the work to set up those programs for 2019.

Okay, that's helpful.

And I guess with respect to the Aventine hub, obviously, you guys have put a lot of time and effort on to getting that up and running.

If you kind of more to sort of do like a bit of a look back and kind of project forward, is there any way to kind of quantify what you might be able to save in terms of Permian Resources well costs?

Is there any way to kind of say, hey, look, once this is fully up and running by the end of the year, we can save 10%.

Is there any way to quantify that?

Leo, this is Jody.

Thanks for the question.

I think we've stated $500,000 to $750,000 of well kind of impact when we're up and running.

But the concept of Aventine actually wasn't just well cost focused, it was also securing supply.

And so we're really getting multiple benefits out of Aventine.

Clearly, we think we will drive costs down.

We have -- we've already shown that securing supply during this tight period has been very, very helpful, not just in New Mexico but supporting contingency, sand deliveries in Texas as well.

The other part that really starts growing over time are the efficiencies that are gained because we've got all of our strategic partners in place that can start whittling out all of the inefficiencies, the wasted motion that -- which does 2 things: it lowers our well cost, shortens time-to-market, but for our partners, it drives up their utilization.

So their profit per frac core, per rig crew, per flowback unit, all of those things go up because we're more efficient than the industry average.

And so the result of that is less pressure on price increase because they're driving higher margins.

So that's how we look at it.

The kind of the number we've talked about is $500,000 to $750,000 a well.

We think there's upside as the teams mature, not just in the physical assets, but how we work the process.

The next question is from Bob Morris of Citi.

Congratulations on the continued improvement in the Delaware Basin wells.

My first question is, you raised the guidance on the midstream pretax income and that's based on an assumed spread of $7, $8 from Midland to the Gulf Coast for the rest of the year, but that spread is currently around $15 and the strip on that is similarly wide.

Would you or could you given any thought to hedging that or trying to lock that in because that would be significant incremental cash flow that then you could use for the share buyback or otherwise?

I would say, Bob, up to this point, this quarter, we've -- we're seeing an average of just a little more than $8.

So we're -- while it might seem like we're being conservative, it's really based on some information and some of the spikes we're seeing go well above that.

But we're not sure we'll see that.

But with respect to your question, I'll pass that to Cedric.

Yes.

Bob, I'd love to lock in $15, if we could.

The truth is, there's no market really for hedging those differentials.

It's very thin and short term and just really nonexistent.

So it's a volatile market.

It's outlook is difficult to predict as we've seen.

Primary driver is pipeline utilization, which we expect to continue to be high until these new pipes come on, particularly in the second half of '19.

But as it stands, hedging is just not really an option available to us.

Yes.

And I suspected that the market was pretty thin.

And obviously, it would be nice to be able to lock that in.

My follow-on question is, I know you did mention you'd be opportunistic on noncore asset sales.

You did say last quarter, you expected to execute on some noncore asset sales this year.

Has either the recent deal at a very high per-acre value or the widening in these Midland differentials change your view or approach on executing on noncore assets sales this year?

No, it's still the same.

We will look for opportunities.

And the opportunities have to be compelling enough to execute on.

But we're still continuing to look at ways to monetize those things that are noncore to us.

The next question is from Matt Portillo of Tudor, Pickering, Holt.

Jody, you highlighted the value proposition of the Aventine Logistics Hub and the Northern Delaware Basin, which appears to have a very strong competitive advantage regionally.

I was wondering if you see similar logistics potential in the Southern Delaware and in the Midland basin?

Yes.

Matt, we sure do, but in a different scale.

Actually, the one in the Southern Delaware Basin is called palatine.

And it's more of a contractual relationship on sand transload.

Midland Basin's -- there's more access to infrastructure, and so you could service Midland out of either palatine or direct from some of the regional sand mines that are coming online.

It's a little less exposed.

Plus, our activity set is considerably lower in Midland.

So we're really focusing on the Delaware Basin to ensure we have logistics, maintenance capabilities, those kinds of things that are more regional to the activity to take out trucks, to take out inefficiencies and downtime.

Great.

And the follow-up question is actually around your export business.

As pipeline capacity ramps towards Corpus, you mentioned industry volumes will continue to increase, allowing you to expand your Ingleside dock capacity for crude oil.

My question actually revolves around your LPG asset base.

I know Oxy mothballed that facility due to lack of propane access.

And I was wondering, with some of the new greenfield NGL pipes potentially heading southbound, if you see the potential to bring this asset back into service?

We stay aware of all the activity in the area, and we were just keeping a watchful eye to determine at what point -- we believe, at some point that, that could be an opportunity for us.

But we don't see that now.

We're really focused more on expanding our -- the oil export part of that.

However, we're going to stay opportunistic with respect to how those pipelines play out and what opportunities might come our way.

The next question is from Pavel Molchanov of Raymond James.

This is Muhammed on behalf of Pavel.

First of all, when the buyback eventually does start, how should we think about it?

Should be a flex variable, as in will it remain relatively constant or flex up or down with free cash flow?

I think the way to think of it, Muhammed, is opportunistic.

We're going to be looking -- it's a competition for capital around here, and that's one great use of capital.

But we'll look at reinvestment and other options as well.

So -- and obviously, we'll be looking at the value of the shares.

So periods of weakness and things like that, we certainly could step in, but we'll be opportunistic with those buybacks.

A follow-up on a different topic, the Middle East.

It's now been almost a year since the economic embargo against Qatar started.

You've said in the past there hasn't really been a significant impact in you guys.

Is that still the same?

Or have there been any changes?

No, that's still the same.

It never really impacted our business very much.

And I think Qatar, in general, has made a lot of changes to the way the country now manages that.

And so we don't expect -- didn't see any and don't expect to see any problems with any of our operations.

The next question is from Roger Read of Wells Fargo.

Maybe to follow up on the dividend question that hasn't been quite beaten to death.

Cedric, if you look at your debt, and thinking about kind of the period we've just been through here, focusing more on cash flow neutrality at a low oil price environment than where we are today.

Do you look at any of your long-term debt and evaluate that as something you might prefer to retire, rather than buy back shares?

Certainly, we'd look at that -- have looked at it.

We know the terms, but -- so that's it.

That is one option that we could consider down the road.

So again framing it, hopefully, we've laid this out pretty clearly, but we have a plan that we're about to achieve, that means we can pretty much, in any reasonable oil price scenario, stay within the guardrails of cash flow.

And then with that, we've laid out our priorities, and net debt improvement is one of them.

And so in the short term, it likely means building cash a little bit, but there -- because most of our debt is termed out, as you've noted, but there are ways to bring that in and make some reductions there too over time.

But again, in that area, we'd be opportunistic.

I've worked on in the past debt buybacks and even the defeasance, and the defeasance is probably the last thing we'd want to do.

They tend to be expensive.

But there are ways to bring that debt in, and that's something we would look at over time should the cash flow continue to stay at a high level.

Okay.

And then maybe 2 quick questions on the Permian.

This call, no comments or at least, that I saw in the presentation, anything on acreage swaps or additions or anything.

Is that an indication the market's slowed down or just a quarterly kind of event?

And then the other question was, if you could help us -- just because it's been quite a while since we got to think about high oil prices having an impact on EOR ops or an OpEx, how -- what exactly is exposed, kind of what the percentage, maybe the right way to think about how that stair steps in a higher oil price environment?

Yes.

Roger, -- the first question on acreage trades, there's still a lot of activity there.

Last year, we did about 17,000 net acres in trades, and in the first quarter, we've done 11,000.

So there's still a desire to core up, be able to drill longer laterals, leverage your larger positions.

Without regard to EOR OpEx, it's primarily 2 things: it's energy.

So as the cost of electricity goes up, you have some exposure to energy.

And then some of the CO2 contracts have an oil price relationship.

We can follow up with you later on trying to help model that a little closer, but the things we control with well work and activity, that's all managed pretty well, and not so exposed to inflation.

Our improvement activities typically offset any inflation.

Roger, this is Cedric.

I just want to add one thing, just for clarification.

The first quarter financials in our cash flow, you'll see $177 million of acquisitions and $275 million of sales.

Where we talked about the roughly $150 million Delaware Basin gas plant sale, which was non-core in that sale number, but the other piece of it was really the swap.

So really, the acquisition we just broke -- the way we did from an accounting standpoint, we broke both the acquisition and the sale out in the financial statement.

But if you -- it really was done as one deal, and it was essentially a swap, a large one.

And the other thing I'll add, Roger, about EOR is that, we put the slide in there to show you it's leveraged to oil.

And the reason for that is, that it's about 80% liquids.

And so on a BOE basis, we have a higher liquid and higher oil production from EOR -- on a EOR basis -- on a BOE basis.

So that's why it's a -- that margin for even though OpEx will go up a little bit, we really benefit from higher oil prices in the EOR business.

The next question is from Jason Gammel of Jefferies.

Just wanted to come back to the guidance on the midstream, which obviously a very significant increase.

I realize that most of it is due to differential.

But if I just take the midpoint change in the differential and multiply it by the $45 million, rule of thumb, which sounds like maybe I should be using $30 million, I get about $625 million versus the $750 million step-up in the guidance.

So wondering if you could talk about any other factors that are positively affecting your outlook for the midstream this year?

Certainly, the midstream businesses has more than just that -- those contracts related to the takeaway.

The export terminal, in particular, has been doing fantastic this year.

As you know, we're a leader in that area, and so I think it might probably be the only thing I'd point to more specifically.

So that's the ability to capture the arbitrage between, let's say, Brent and Corpus Christi pricing or something along that one?

This is Richard.

I may help with one piece of that.

I wanted to clarify that the $45 million per $0.25 change, the midstream segment fully benefits from that.

The $30 million is really our upstream production.

It's based on Midland pricing, and so you'll see that in our realizations in our production schedules.

So take -- you do need to take the full $45 million and apply it to midstream, and that's the benefit.

Okay.

As to say, even that would be fairly significant uplift relative to just the rule of thumb that you're giving in guidance.

But maybe I could just transition your comments around essentially pipeline utilization rates being very high, and not really much relief until midyear next year.

I know you're only giving guidance for 2018, but should we be able to extrapolate that midstream is looking to have a pretty good first half of '19 earnings period as well?

Yes, that's our view.

If you look at the alternatives, rail would be great, but it's kind of got a $8 a barrel range.

But that's limited today to around 100,000 to 150,000 barrels a day in terms of rail capacity.

I think there be efforts to try to increase that, but there -- it's difficult to do.

And then trucking -- by the way, Slide 63 lays this out pretty well for you.

And then trucking, again it's a higher cost with around $12 or so a barrel.

So there will be kind of some upper limits you might think about.

However, with trucking, we've all seen bottlenecks there, the roads are crowded and in disarray, and getting trucks and getting truck drivers even is a difficult thing to do.

So it's a -- as we've said, the outlook for spreads is difficult to predict.

It's going to be bouncy for a while as all the takeaway systems are being stretched to their limits.

And the final question today comes from Michael Hall of Heikkinen Energy Advisors.

A lot of mine have been addressed.

I guess, just one I wanted to hit on, on the Aventine facility.

I guess, kind of dovetailing on the comment on crude by rail.

Is there any opportunity to, I guess, kind of refer any of that facility into a crude by rail terminal?

And to what extent might there be any interest in doing that?

Michael, this is Jody.

You recall we have 2.5x our equity oil production volume that we can move on pipe.

So for us, we wouldn't likely consider that as an option.

We really see this more as an operational facility to support.

Right now, mostly the capital side of the business [then] is you go through the full life cycle and it'll support the operating cost side of the facility as well.

Okay.

Yes, I guess, I was thinking about it from marketing business angle of service, another way to capture even more potential upside from the current situation, but it sounds like no.

And then, I guess, the other piece is just on local sand usage.

To what extent, if at all are you guys testing in the Delaware Basin, in particular, is, I guess, what I'm curious.

Michael, we see application of local sand in both the Delaware, Southern Delaware the Midland Basin.

Our preferred sand providers are coming online now with their local sand mine, so we will start utilizing more local sand as a percentage of the total.

We've done kind of the background work, the geoscience work, the lab work and all the tests, different sands, different sand quality.

So we're comfortable applying those.

It's just a matter of getting more activity in the local sand market.

This concludes our question-and-answer session.

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

I'd like to leave you with 3 takeaways today.

First, we are ahead of schedule for achieving our breakeven plan.

Second, our first quarter outperformance and the improving business results have led us to increase our full year guidance.

Finally, we will reinvest excess cash flow and our highest return opportunities.

And so to close, I'd like to thank all of our employees because they are the true drivers of our success.

Thank you for joining our call today.

The conference has now concluded.

Thank you for attending today's presentation.

You may now disconnect.