西方石油 (OXY) 2017 Q1 法說會逐字稿

Good morning, and welcome to the Oxy First 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.

Thank you, Kate.

Good morning, everyone, and thank you for participating in Occidental Petroleum's First 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; Chris Stavros, Chief Financial Officer and Senior Vice President; and Rob Peterson, President of OxyChem.

In just a moment, I will turn the call over to Vicki Hollub.

As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws.

These statements are subject to the risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements.

Additional information on factors that could cause results to differ is available on the company's most recent Form 10-K.

Our first quarter 2017 earnings press release, the Investor Relations supplemental schedules, our non-GAAP to GAAP reconciliations and the conference call participation slides can be downloaded off our website at www.oxy.com.

I'll now turn the call over to Vicki Hollub.

Vicki, please go ahead.

Thank you, Richard.

And good morning, everyone.

I'd like to focus on 3 topics in my opening remarks.

First, I'll provide you an update on our portfolio optimization initiative, and I'll share what this means for our near-term growth plans.

Then I'll highlight some components of what you believe is our differentiated value-based approach.

And last, I'll provide details on our plan to get to cash flow breakeven after funding the dividend and growth capital.

Turning to Slide 4. In 2013, we began our strategic review process to divest the low-margin, low-return assets and assets that simply could not compete for capital within our portfolio.

We allocate capital based on the net present value of the project, the returns it generates, the cash flow profile, the reserves added and its capital intensity.

To support our value proposition, we need a balanced blend of short-cycle, high-growth investments along with low-decline, long-term cash flow.

But in both categories, we need relatively high-margin, high-return assets, and we need the ability to control our own destiny.

By this, I mean we need a high-quality development inventory with the potential to sustain our growth over the long term without needing to depend on acquisitions or the decisions of others.

As a final step of our strategic review process, we have now divested of our South Texas Gas properties, which were our last noncore upstream asset.

Our remaining upstream assets are all within our core areas, which are the Permian Basin, Colombia, Oman, Qatar and Abu Dhabi.

The proceeds from the South Texas sale will be redeployed in the Permian Resources.

Given the Permian Resources margins are 3x higher than South Texas Gas, only 9,000 barrels of oil equivalent per day of resources production is needed to replace the cash flow from the 27,000 barrels of oil equivalent produced by South Texas.

As we have been going through this optimization process, we've been replacing the lower-margin, low-return divested production with better quality, higher margin, high return production in order to restore our cash flow.

About half of the divested production has been replaced with incremental production from Permian Resources, Al Hosn and Oman.

The first component is our -- the remaining growth needed to restore our cash flow to cover growth capital is $50 WTI will come mostly from our Permian Resources business.

As you know, even in a $40 to $50 price environment, our resources developments generate high returns with low risk due to the quality of the rock, scalability of the development and availability of services.

I want to point out that this has not been a shrink-to-grow strategy.

This has been a deliberate drive to ensure the capital we invest will deliver the highest possible returns.

This is the returns-focused strategy.

We now have the highest portfolio that I believe we've ever had, but a great portfolio is not enough.

We must also ensure we do the things necessary to maximize its value.

On Slide 6, I'd like to share how we're doing that.

We have centered our entire business on a differentiated, value-based development approach.

The 3 goals on the left-hand side of the slide may seem basic to running an oil company but can be hard to achieve in actual practice.

Our organization and culture are grounded in recovering more oil at less cost, while continually building the required inventory to sustain and improve our results.

Before I highlight several components of our approach, I'd like to say that we make decisions and weigh trade-offs that may differ from our competitors because we're focused on creating shareholder value over a long term.

The first component is our niche.

We have proven and long been known for our ability to get more reserves out of reservoirs than others can.

That achievement starts with strong technical capability, a solid understanding of the subsurface and the application of cutting-edge technologies to develop and manage the reservoir over the full life of the reserve.

We have done this in conventional, tight and unconventional reservoirs in many areas of the world.

We've done it with primary, secondary and tertiary recovery methodologies, onshore and offshore, in desserts and in jungles.

We've taken a similar approach in Permian Resources where the key to our success has been investment in technology and a rigorous internal workflow of subsurface characterization.

We first needed to understand the reservoir and the fluids within the reservoir.

Only then could we confidently understand where to land a wellbore, how to design the stimulation, how many wells are optimal per section and the minimal infrastructure needed to support it.

While many of our competitors are busy drilling the most wells per section, we're focused on drilling the optimum number of wells per section for less cost to recover the same if not more oil through an infrastructure that's designed to deliver the highest net present value rather than to support a peak production rate.

To do this requires a strong technical capability, detailed integrated planning and an innovative culture across the entire organization.

The second component is the early adoption of external trends because I believe this is where we truly separate ourselves from the pack.

For example, several years ago, we recognized that data analytics would be big for our industry.

Early adoption has been key to enable full integration of this technology into our culture.

Only culture will allow new technologies like data analytics to drive sustainable business results.

The reality is that as we are rolling data analytics out to all of our disciplines we're starting to find things that we had not previously seen and in many ways that we didn't expect.

This will have a material impact on our future business and financial performance.

We believe that if you're thinking long term you need to be thinking about data analytics now.

Turning to my final slide, Slide #8.

I want to reinforce that getting to a lower cash flow breakeven after dividend and growth capital is a top near-term priority.

As always, our financial goal is to grow our dividend and company value by making returns-focused investments that will drive 5% to 8% average production growth over time.

The pathway to this lower breakeven oil price is clear to us, and the actions listed on the slide will all work together to help us reach our goal.

It is important to note that we plan to accelerate cash flows from the tail of our portfolio to help fund the production growth needed to achieve our lower breakeven target.

The tail of our portfolio includes Permian Resources acreage that is not strategic to us but synergistic and valuable to others.

This will be done as needed and opportunistically.

On the right side of the slide, we have identified key milestones and accelerators.

Our incremental growth target is 80,000 barrels per day, above our 2016 average production rate, including the replacement of the South Texas cash flow.

To fund this growth capital, we disclosed $2.2 billion of cash sources.

Beyond these sources, we're continuing to work several options across our portfolio that will accelerate value creation, including asset trade, partnerships and sales.

We're looking for win-win scenarios for ourself and other companies.

We believe oil prices could be lower for longer, and then only the companies with high-quality assets and top-tier operational performance will be up to the challenges our industry will face over the next few years.

We believe we are well positioned to meet these challenges.

I'll now turn the call over to Chris Stavros.

Thanks, Vicki.

And good morning, everyone.

Today, I'll focus on the following: a brief summary of our first quarter 2017 financial results; cash flow balance sheet and liquidity items; and then I'll come back at the end of all of our prepared remarks to close out with guidance for oil and gas production, the other business segments and related items for the second quarter and full year of 2017.

Our first quarter 2017 reported income for GAAP purposes as well as our core income was $117 million or $0.15 per diluted share.

While higher product prices were a big factor in our sequentially improved earnings results, all of our operating segments demonstrated better-than-expected results.

For the first time in nearly 3 years, the arrows are clearly pointing in a favorable direction for all of our core businesses.

In addition to higher product prices, our realized prices for both oil and NGLs relative to benchmarks showed a marked improvement on a sequential quarterly basis and helping improve overall oil and gas profitability.

Much of this was due to better-than-expected Midland to Cushing differentials during the quarter.

First quarter oil and gas production volumes averaged 584,000 BOE per day, and all of our reported data incorporates production volumes for our South Texas Gas properties, which have been sold.

Permian Resources production grew 6,000 BOE per day, up 5% on a sequential quarterly basis to 129,000 BOE per day in the first quarter and in line with our earlier guidance.

More than 80% of the quarter-on-quarter improvement in resources production came from oil growth.

Our total cost in oil and gas, including cash operating cost, DD&A and G&A, had a positive sequential pretax impact of about $130 million.

Despite the planned and unplanned downtime, our international oil and gas operations generated more than $200 million of cash flow after capital during the first quarter.

Chemicals generated first quarter pretax core earnings of $170 million, up $18 million sequentially and exceeding our earlier guidance.

First quarter results reflected higher caustic soda, PVC and VCM volumes along with higher caustic soda prices and partly offset by higher ethylene and energy prices.

Midstream pretax core results were a loss of $47 million for the first quarter and similar to last year's fourth quarter.

The better-than-expected results in the most recent period were supported by higher-than-expected throughput at the Ingleside export terminal and better NGL realizations.

Turning to our cash flows for the first quarter of 2017, we generated nearly $1.1 billion of cash flow from continuing operations before working capital.

Changes in working capital consumed approximately $390 million of cash during the quarter.

Working capital usage is typical for us during the early part of the year and primarily due to the timing of payments for property taxes and other cyclical payments.

In addition, we also had a build in our accounts receivable largely due to rising prices for some key products in our chemical segment and with cash collection lag by about a month.

We also used some working capitals.

We incurred some line fill in our pipelines as our storage and export terminal at Ingleside ramped up its capacity.

Under the current product price environment and our expected pace of development activity, we anticipate this use of working capital to be behind us and with some modest reversal expected during the remainder of the year.

Capital expenditures for the first quarter were $750 million, with oil and gas spending representing about $600 million.

We expect our capital to ramp up to about $950 million in the second quarter and continue at this pace for the remainder of the year as we ramp up our activity.

Based on the anticipated pace of activity in Permian Resources, we would expect our full year capital spending to be towards the higher end of the $3 billion to $3.6 billion range we had indicated earlier this year.

We ended the first quarter with $1.5 billion of cash on hand.

As Vicki mentioned, we closed on the sale of our South Texas Gas properties for net after-tax proceeds of nearly $600 million, the bulk of which were received in April.

These assets were in decline and did not compete for capital relative to our investment opportunities in the Permian.

Our plan is to redirect the proceeds towards our high-return development in Permian Resources and in an effort to drive higher value oil production growth.

Together with proceeds from the sale of South Texas and the cash tax refund of approximately $700 million anticipated in coming weeks, we expect to have a higher cash balance at the end of the second quarter.

We continue to hold our investment in the Plains All American Pipeline general partner, although we consider this to be noncore.

This, in addition to potential funding options that Vicki mentioned, provides us with a high degree of comfort in terms of leverage we have at our disposal to support our capital program.

Our ability to better capture the high-margin, high-return growth opportunities in Permian Resources also supports the future growth of our dividend.

Going forward, we will continue to free up capital from noncore or nonstrategic assets and seek opportunities to derisk portions of our portfolio in order to reinvest in the Permian Resources.

I'll now pass the call over to Rob Peterson, who will provide some insight around our chemicals business.

Thanks, Chris.

And good morning, everyone.

In February, OxyChem safely completed the commissioning of our ethane cracker that will produce 1.2 billion pounds per year of ethylene at our Ingleside, Texas, facility.

The project is a 50-50 joint venture between OxyChem and our long-term partner Mexichem.

The project included a dedicated 115-mile ethane pipeline and storage down in Markum, Texas.

This project is the first grassroots cracker built in the United States in over 15 years.

Completion of the project both on time and on budget, while maintaining tremendous health and safety performance throughout this construction, is a testament to our employees and our contractors to execute and deliver on objectives.

The cracker has been operating at the designed capacity since the latter half of March.

In addition, we improved on our ability to transport ethylene to and from our market in Markum, Texas, storage dome through our pipeline.

Most importantly, the ethane produced by the cracker is being consumed at our Ingleside facility in the production of VCM, nearly all of which is being exported to Mexican facilities in Mexico and Colombia where they convert to VCM into PVC and PVC piping systems.

The successful completion of the project and the structure of our partnerships in Mexichem assures that the cracker will continue to operate at a higher operating rates over the course of our 20-year agreement and that both parties will receive returns on investment that well exceed our cost of capital.

This investment is not based upon a need to secure merchant sales of ethylene or new VCM business but rather allows us to further back integrate our value chain to support existing business with Mexichem.

This value-based approach is in alignment with our overall company goals.

While we continue to invest our chemical operations, including our latest investment in geyser in Louisiana that will provide the feedstock for the production of next-generation refrigerant, the completion of the ethylene project marks the conclusion of a significant capital spending cycle over the past 5 years.

OxyChem's focus will now turn to what it excelled it, maximizing the value of our assets to deliver significant free cash flow back to the parent company.

On Slide 14, I will give a brief overview of the current trends in the chloro vinyl market.

After a multiyear downturn that began in 2013, the chloro vinyl market has been on a trend to sustain earnings improvement since the second quarter of 2016.

The primary driver of earnings improvement is increased margins in the liquid caustic soda business.

OxyChem is the world's largest marketer of liquid caustic soda, selling approximately 3 million tons each year, and is the largest exporter of caustic soda in the United States, led by our advanced logistics from our Ingleside, Texas, facility.

Both domestic and export caustic soda prices have risen sharply.

While average domestic spot prices have risen nearly $190 per dry short tons since March of 2016, export prices improved nearly $250 per dry short tons in the same period.

In addition OxyChem just implemented an additional $60 per dry short ton in price increase for the second quarter every count where contract terms permit it.

On the PVC side of the business, we secured $0.06 per pound of price increases in the first quarter, as we worked to recover margin lost due to ethylene escalation since the second half of 2016.

We are committed to take the actions necessary to improve the profitability of this business segment to an acceptable level.

Two factors are the source of chloro vinyls business improvement: first, the conclusion of the consolidation of North American chlor-alkali producers, which had created significant turmoil in the market of chloro-vinyl products; second, the global absorption of significant new chlor-alkali and vinyl capacity built through 2014.

Further consolidation of North American producers is unlikely.

And with no significant chlor-alkali or vinyl capacity expansion on the horizon, we believe the current up cycle will persist beyond 2017.

Furthermore, we are encouraged by the emphasis of infrastructure replacement in the United States and the additional growth it could provide to PVC, which is the most cost-effective and sustainable solution to underground piping systems.

In closing, we are excited about our performance at OxyChem.

The completion of our heavy capital spending program concurrent with the business up cycle will create significant improvement in free cash flow generation for the company.

As we have indicated previously, we anticipate at least a $400 million improvement in year-over-year free cash flow generation, with the upside to that figure based on the favorable market conditions and OxyChem's strong market position.

As we look forward to 2018, full year contributions from the cracker along with the initial contributions from our refrigerant feedstock plant should provide in excess of $75 million of additional free cash flow.

I will now turn the call over to Jody Elliott.

Thank you, Robin.

Good morning, everyone.

Today, I'll provide an update on our Permian Basin business and how it's driving the plan that Vicki outlined in our opening remarks.

Our efforts in the Permian are a clear example of how our differentiated value-based approach generates growth and value through a sustainable competitive advantage.

As part of our corporate portfolio optimization, we will redeploy the proceeds from South Texas into 3 to 5 additional Permian Resources rigs, bringing the resources rig count to 11 to 13 by year-end, including outside operated.

This activity will increase resources 2017 capital to between $1.6 billion and $1.8 billion but without increasing OXY's capital budget of $3.6 billion.

This activity is aligned with our value-based approach to development and should result in a moderate increase of about 10,000 MBOE per day to the 2017 exit rate.

This impact will be more pronounced as we exit 2017 and enter 2018.

We are pursuing trades, partnerships and sales opportunities using the tail of our portfolio to fund accelerated growth within our core developments.

We understand the value benefits of acceleration and believe our Permian inventory can support monetization opportunities and high-value, long-term growth.

We also appreciate the necessity for value-based development and have found that the NPV benefits of acceleration can be quickly offset by suboptimal development plans, so we will be disciplined in our approach to maximize shareholder value.

Our value-based development begins with the subsurface and surface workflows where we ensure all key attributes are aligned, including bench and well sequencing, well spacing, infrastructure and technology advancements.

We continue to apply innovative technology into our plans, and we will provide additional disclosure as we deliver results there.

We understand the importance of cost leadership in our development plans, which starts with commercial strategies and partnerships to protect margins.

So we're taking the right steps to minimize OXY's exposure to cost inflation and supply constraints as activity ramps up.

As we work toward our OXY financial goals, both Permian businesses will play an integral part of the strategy.

Permian Resources is capable of generating free cash flow in 2018 at greater than 20% growth.

We will also continue modest investments in Permian EOR, which is currently generating free cash flow and provides a stable business to help manage through volatile market conditions.

For reference, the Permian EOR business provides about $35 million of operating cash flow for every dollar increase in oil price.

Turning to Slide 16.

I'd like to highlight the low-capital intensity growth in Permian Resources.

We can grow production at greater than 20% CAGR, while investing only $1.3 billion to $1.5 billion in CapEx each year.

That equates to approximately $30 million of CapEx for every 1,000 BOE per day of wedged production in the first year.

Achieving this capital intensity metric represents a 50% improvement from our previous performance.

Simply put, our development program is producing more oil with less cost.

The sustainability of our low capital intensity will be grounded in replenishing our low breakeven inventory by realizing the full potential of our high-quality reservoirs through subsurface engineering, technology advancements and thoughtful infrastructure design.

In 2017, we are targeting a 400-plus well increase in our less than $50 breakeven projects, which is about 3x our 2017 drilling pace.

We believe our Permian Resources capital intensity differentiates us from most of our peers and will allow us to grow production and generate free cash flow by 2018.

With the reinvestment of the South Texas proceeds, we're now on track for the 30% CAGR case.

However, we will continue to assess the pace of our development program to ensure alignment with overall corporate objectives.

Turning to our Greater Sand Dunes area on Slide 17.

We continue to see improvements in our Bone Spring program.

In previous calls, we've highlighted our top-tier second Bone Spring program, but our third Bone Spring and Wolfcamp XY wells are also yielding play-leading results.

We've optimized our well design and landing zone and expect to see continued improvement in returns as we get more oil and drill longer wells.

In Q2, we will drill 6 total, third Bone Spring and Wolfcamp XY wells that utilize existing facilities and contribute to the value-based, low-capital intensity growth.

Given the number of proven high-quality benches, New Mexico will continue to reduce its capital intensity and progress to multibench development, where we will realize more than a $10 breakeven reduction, as secondary benches can utilize many of the previous investments from the primary bench.

We currently operate 2 rigs in the Greater Sand Dunes area and could reach 5 operated rigs by year end.

Moving to Slide 18.

In our Greater Barilla Draw area, we're operating 3 rigs, and we'll add 2 additional rigs in the second quarter.

We continue to progress the detailed subsurface characterization in mapping in Red Bull South to ensure we maximize value, while also working the surface constraints to drill longer laterals.

In the short time we've operated Red Bull South, we've reduced the completion cost by 23%, while improving well productivity.

In the Lockridge area of the Greater Barilla Draw, we performed a Wolfcamp A and Bone Spring spacing test.

The wells are achieving type curve, but we found a new landing zone option that we expect to improve future results and add significant value to future development.

We expect to exit the year with approximately 4 to 5 rigs in the Greater Barilla Draw area.

Slide 19 demonstrates where our value-based development is yielding great results in 2 benches at our merchant area in Midland Basin.

The teams were able to optimize the landing zone and well design of the Wolfcamp B, which resulted in more oil and a significant increase to the economics of the program.

The better well productivity, long laterals and cost improvements have yielded 2 development benches with all-in breakevens under $40.

We currently have 2 rigs in Merchant and will average 2 rigs for the remainder of the year in Midland Basin.

On Slide 20, I'd like to introduce a new development technology we call single location sequenced laterals or SL2.

This is an example where we leveraged our experience with multilaterals in the Middle East to innovate the unique lower-cost design for onshore unconventional application.

The technology will allow us to operate multiple benches in a field at lower full cycle cost.

We believe this technology, which is licensed to OXY, will drop secondary bench breakevens by approximately 10 -- $5 a barrel.

We successfully completed our first multilateral in December 2016 and are designing many of our new wells to support the technology for future reentry.

While we will continue to pilot the technology in 2017, we expect the development application to be in the 2018 plus time frame, when second and third benches are more predominant in the development program.

On Slide 21, our logistics and maintenance hub located in Eddy County, New Mexico, features a transloading facility capable of handling 3 unit trains of frac sand with 30,000 tons of storage capacity.

In addition to frac sand, the logistics hub is also designed to handle hydrochloric acid from OxyChem, oil country tubular goods and to provide a base for maintenance and support of strategic drilling and completion services.

This project represents alignment of top-tier industry partners leveraging their strengths to remove cost inefficiencies from the overall value chain.

In addition to economic benefits, this approach provides us with a secured supply of critical materials as well as distribution channels.

With sand supply tightening and existing terminal space being contracted, this project secures OXY's ability to execute our development program in Southeast New Mexico without concern for scarcity of supply.

This provides OXY the benefit of backward integration, with each partner managing their corresponding core businesses to remove the operational and business risk associated with the conventional vertical integration model.

Based on the win-win value assessment for OXY and our partners, we're evaluating options for additional logistics and maintenance hubs in Greater Barilla Draw and the Midland Basin.

Our efforts in the Permian Basin are a clear example of how through differentiated, value-based approach generates growth and value through a sustainable competitive advantage and differentiates us from our peers.

I'll now turn the call back over to Chris Stavros for guidance.

Thanks.

With respect to guidance, we expect our full year 2017 company-wide production growth from ongoing operations and adjusted for the sale of South Texas to be in a range of 4% to 7% or between 595,000 or -- to 615,000 BOE per day.

This is unchanged adjusted for South Texas relative to what we've said historically.

This includes a modest impact of OPEC quota constraints and volume effects under our production sharing contracts due to higher oil prices.

Our long-term production growth expectations remain at 5% to 8% per year.

As a result of increased drilling activity later in the year, we expect production in the Permian Resources to exit this year at a growth pace approximately 30% higher than year-end 2016 levels.

For the second quarter, we expect a significant recovery in total company ongoing production volumes and in the range of 580,000 to 595,000 BOE per day.

Production of Permian Resources is expected to be between 135,000 and 140,000 BOE per day in the second quarter.

Every $1 per barrel change in WTI affects our annual operating cash flow by about $110 million.

In our midstream business, we see a return of profitability, as we expect the second quarter to generate pretax income of between $5 million and $15 million Foreign income from pipeline and other facilities should improve, as planned maintenance at Al Hosn and Dolphin was completed earlier in the first quarter.

A large portion of the financial improvement in midstream should be driven by wider oil price differentials between Midland and the Gulf Coast and partly as a result of rising production in the Permian Basin.

In chemicals, we anticipate pretax earnings of about $200 million for the second quarter as a result of continued improvement in caustic soda prices and the benefit of operations from the new joint venture ethylene cracker.

Looking forward, our chemicals business is on a pace to generate approximately $250 million per quarter of free cash flow for the remainder of the year.

I'll now turn the call back to Richard.

Okay.

Thank you, Chris.

Kate, we are now ready for questions.

(Operator Instructions) The first question is from Ed Westlake of Crédit Suisse.

Maybe if I can talk about the dividend coverage.

One of the numbers that helps when investors think about that is maybe the maintenance CapEx number, the CapEx to keep, obviously, your downstream units in operation and production flat.

I don't know if you have an update on that because, obviously, international cost is still deflating and the work you're doing in the Permian may have lowered that, so any color there would be helpful.

Yes, Ed, currently, we're seeing about a $2.2 billion sustaining CapEx, but we do expect that to come down.

We're seeing price improvements in international operations.

We're also, as you've heard, still seeing significant improvements in our Permian Resources business so that we expect as that capital intensity goes down this will also decrease.

But with our current situation, we're certainly less than $50 to be able to cover our sustaining capital and dividend.

Okay.

And then good color on the chemicals.

Thanks for that, that $400 million shift.

The midstream is improving, which is good to see.

I don't know if you'd be able to hazard a guess at where you sort of see midcycle midstream earnings with the Permian perhaps closer to filling up the pipe sometime next year or 2019?

Yes.

I think, Ed, certainly the arrows, as I said at the outset, the arrows are pointing in the right direction for that business as well.

I think the differentials are suggesting that we see profitable periods for the remainder of the year, frankly, certainly in the second quarter and in the back half of the year as well.

So it continues -- if conditions continue to sort of move in this direction as far as Permian production based on the rig adds that we've seen, it's frankly looking pretty good going even into -- exiting this year and certainly going into next year as well.

So you'd figure that there may be some acceleration around that point because I mean, obviously, some of it is related to contracts you have that needs certain volumes to be hit.

Yes.

We would be profitable in excess of any contracts we have in place.

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

Vicki, I'm not sure if you want to take this one.

But I think you've talked about the Permian previously being self-funding in 2018 at around $50.

With the high level of activity, and obviously, the -- I think Jody pointed to the higher end of the growth rate, what does that look like now?

Are you still self-funding at $50 oil in 2018 with the higher activity?

Doug, this is Jody.

Even with the higher activity rate, all it does is push that time frame out a few months in 2018.

So the improvement in capital intensity really does help that time frame for the Permian Resources breakeven.

Okay.

I appreciate that.

The question that continues to come up, obviously, is around the dividend, despite your assurances around breakeven and so on.

So I wonder, Chris, if you could address one specific issue, which is the roll-off of your Middle Eastern contracts in Qatar, I think '17 and '19, respectively.

What is the status of those contracts?

Is it a material free cash contribution and just a general kind of status updates of how that might affect the breakeven calculations as you move forward?

And I'll leave it there.

Doug, I'd like to start with that.

We feel that we're in a good situation in Qatar.

First, let me say, we don't have anything rolling off in 2017.

We actually -- our ISSD contract would be in October 2019.

But really, what we're doing today in Qatar is, I believe, some of the best work that we've done anywhere in our company in a long time, and I'm going to have Ken describe some of the things that we're doing there that give us some confidence that we'd be able to extend that contract.

Saad al-Kaabi, the CEO of Qatar Petroleum, the thing that mattered to him most is that we add the most value possible for every dollar we invest in Qatar.

We believe that with the success our teams are having there that we're going to be able to meet his expectations.

And our teams are working well to be able to share best practices to help each other, to accelerate some of the technical work and new technologies that we want to do.

So we've actually established something there that are different than being done anywhere offshore in the Middle East.

That, along with the fact that we successfully negotiated the extension of Block 9 contract in Oman, gives me a lot of confidence that we'll be able to continue.

I'll pass it on to Ken to give you some of the details around some of our activities.

It's Ken.

Our approach is basically the same as the one we went with for the Block 9 expansion.

Our goal is to remain the partner of choice in Qatar.

We're focused on technology reputation and operation excellence.

Our new innovative wellhead platform designs, which provide drilling slots 50% cheaper than conventional Middle Eastern platforms with 40% more capacity, are in detailed design at the moment.

Our next-generation reservoir models for ISND and ISSD are nearing completion and showing positive results.

And the combination of these 2 aspects mean we can deliver the same reserves for less than half the cost in our previously submitted Phase V proposal.

We're now starting to roll out OXY Drilling Dynamics and [OXY Lift], so we think we can make improvements on the Phase V performance, and we're already the low-cost operator in Qatar.

The last thing I would really like to emphasize is last year offshore we had 0 recordable incidents, and we've had none this year.

That's a really excellent workers' safety performance in Qatar and one that I think the team should be proud of.

So we're very focused on this.

We have regular meetings, and we continue to improve month-on-month.

Just to be clear.

It's sound obviously, you're pretty -- I can't help but to think you're pretty optimistic about being able to extend the contract for a number of reasons, but could you quantify the free cash contribution in current oil price environment just to kind of put that issue to rest?

Yes.

Doug, the best way I would put it is that the plan we have in place from the other assets, and as Vicki discussed, certainly around the Permian would more than make up for cash flow absence if that were happened in Qatar, I think it's what you're asking.

It's something that I would view as immaterial relative to the total cash flow that the company generates.

So by that, I mean, sort of less than 5% of the total cash flow that the company generates.

So I think that based on the plan that we just laid out, we can accommodate additional cash flow growth and opportunities from the assets that we've got to make up for any shortfall if that would occur, but we don't think that will happen.

So sub-$200 million sounds about in the ballpark [cat]?

That's probably right.

That's right.

And the next question is from Evan Calio of Morgan Stanley.

You guys are telegraphing a stronger commitment to higher Permian growth rate exiting, I think the guide was 30% is the high end of the range in 2017, and you said operational momentum asset sales and balance sheet to support.

I mean what -- how do you think about the financial flexibility and willingness to support -- continue to outspend if the commodity market remains challenging or any thresholds, specifically if you're kind of stepping up as that market is backing off some.

Yes, Evan, we want to continue to grow Permian Resources.

We are -- this is really a drive to continue to lower our cash flow breakeven for not only our growth capital but for additional opportunities in ways that we could use our cash.

So, currently, we'll continue to be active and aggressive with our development in the Permian Resources.

We're going to fund that through sources that we have.

And so this is -- in an oil price above $50, $50 or above, we're going to continue on our -- on this path to get to a lower breakeven for our growth capital as well.

Now if commodity prices are not what we expect, we would certainly adjust our plans because we do have that flexibility, but any -- the prices above -- $50 and above will continue as to plan.

And with what we see, we expect that this year we will average better than $50.

And the next year will be, we think, even better than that.

Oil prices are doing pretty much what we expected them to do.

We expected to see volatility earlier in the year.

We expect to see that until inventories come down much further than they have so far.

So we do have contingency plans, but as of right now with what we see, we'll continue aggressively on this path.

And Evan, this is Jody.

I think that's a reason why we provided you the kind of guidepost between the 20% and the 30% CAGR case to show you that even with growth, there's some flexibility in the capital depending on commodity price.

Right.

And then I guess you're running the exit rate at 11 to 13, which is well above the 9-year average for 2018, but it sounds like that's like something you'll address as you go into that budgetary period.

Exactly.

Second question.

You guys are talking about adding 500 locations to your sub-$50 Permian resource inventory in 2017.

Could you just provide color on what's driving the additions or where is the focus?

Is this -- are these new locations or moving existing locations down the cost curve or kind of within that -- the 350,000 acres in your portfolio whether you don't have associated location count, any color on that program would be helpful.

Yes, Evan, good question.

And you kind of sound a little like Vicki.

I give her 400, and she changes it to 500, so it's 400-plus.

But our stretch is bigger than that.

It's really coming from multiple places.

It's second and third bench development in existing areas, so taking benches that may not have been profitable and finding ways to make them profitable through either the lower capital intensity, the better production rate.

It is some from the acreage outside of the core areas, but again, you got to remember our inventory is big in those core areas.

So we're not just working one area; we're working both.

I think the other thing that's really we see happening is wells -- we're not adding wells in some cases, but we're moving them to the left in that inventory curve.

So the breakevens are coming down, so really working in all 3 areas.

And Evan, I let me add.

I do appreciate you driving up Jody's targets.

The next question is from Roger Reed of Wells Fargo.

I guess I'd like to kind of understand as we think about some of the cash margin and the cash breakeven here, the sale of your South Texas assets, how does the cash margin of something like that compare to the reinvestment?

I recognized it's not a sell yesterday, get the cash flow tomorrow kind of thing.

But what's the general -- today to, say, Q1 next year thought process on something like that?

Well, what we looked at was the replacement ratio, which is 9 -- or which is 3:1 for resources production versus South Texas production.

And with the funds, we've added sufficient rigs to be able to make up that difference in that cash flow within about 5 to 6 months.

That's pretty nice cash payback, huh?

Yes, it is.

And then a follow-up to an earlier question on the midstream.

Expectation is that as pipelines start to fill you're able to recapture some of the differential in the midstream, something that hasn't been a case over the last, probably, 18 months, but there's also a lot of expansion of the pipeline system going on.

So I just sort of thinking as we look to '18, has some of that recapture potential slip from '18 and maybe in the '19?

Just any clarity you can offer there.

But currently, the expansions haven't really occurred, so we're still seeing some benefit from that.

Now we expect that through the rest of this year we'll see benefit.

Going into 2019, it'll depend on the growth trajectory within the Permian Basin, but we do expect significant growth.

So we're right now anticipating continued improvement in our Permian -- in our Midland -- our midstream business because of that.

Any way to think about quantifying that though in terms of -- I'm just really trying to think.

There's typically a utilization level to think about, but then there's also the actual differential but -- I mean, where are we today on utilization relative to where you think we need to be to start seeing the capture that differential?

I think we're capturing it now.

It's clear in our results and that was, as I said in the prepared remarks, that was a large portion of the driver for the second quarter improvement.

And based on how things are transitioning, it should potentially accelerate in the back half of the year.

So I think you're sort of seeing that.

The next question is from John Herrlin of Societe Generale.

With respect to big data, could you be a little bit more specific about what you're doing?

Is it for better frac-ability, better design on your wells?

What specifically are you doing and what kind of savings do you think it will bring you?

John, this is Jody.

It's really multiple areas.

One of the first areas was a multivariant analysis combining both geologic data and completion data to speed up the process of finding optimum frac designs.

We're utilizing analytics and OXY Drilling Dynamics.

It's what we call OXY Drilling Dynamics 2, which is putting predictability of motor yields and motor performance into that program.

It's around reservoir modeling, being able to take what we do as a very -- the slower process for reservoir optimization using very robust models, we actually use -- are using a low-resolution model that we can optimize the injectant more on a real-time basis.

That applies in Mukhaizna for steam flood.

It will apply to our water floods, and then we will move to our CO2 floods.

So these higher cost injectants get optimized on a day-to-day basis.

And I could just keep going here.

The list is longer than the resources to tackle these, so we're putting them in priority order.

We're really excited about what analytics can do to real step changes in our business going forward.

Great.

Then the next one for me is on your logistics hub.

Is this enough for your intermediate-term growth?

Or will you be building another one down the line?

So in Southeast New Mexico, it's sufficient for intermediate and long-term growth.

There's quite a bit of capacity there.

We also see it -- as you mature in an area and you move off of the rapid growth and now you're into the day-to-day operating cycle, we have enough space there that you can start thinking about maintenance shops for pumping units and compressors.

And so it migrates over time from a capital logistics and maintenance hub to a -- to an operating hub.

And so we're looking in both Barilla -- Greater Barilla Draw now and Midland to see what aspects of the Southeast New Mexico project makes sense there.

Your next question is from Paul Sankey of Wolfe Research.

Vicki, historically, the company's differentiation, and you spoke about differentiation in your comments as being the dividend and the growth in the dividend.

I assume that the low breakevens that you're talking about and everything else are ultimately aiming towards the growth in the dividend approximately in line with volume growth.

Is that fair?

And could you also just repeat the free cash flow numbers from chemicals?

And if you could, give us the number for the quarter that would be all part of the same thought process.

Yes, Paul, the -- we're trying to drive our cash flow breakevens down just for that.

What we want to do is be positioned to be able to resume a significant growth of the -- or maybe I should say moderate growth, not exactly the growth we've seen over the last 10 to 15 years prior to the downturn in the dividend, but we do want to grow the dividend at a meaningful rate.

So that's the reason for this accelerated growth to get to a lower breakeven.

The chemicals?

Rob?

Free cash flow from chemicals should be in the range of about $750 million for the year.

That's for year, and that's a -- that could then be considered a run rate?

Plus the additional $75 million I described in the prepared remarks for the contribution full year the cracker and the refrigerant plant.

The run rate, Paul, as I said, is $250 million for each quarter for the remainder of the year, and then it accelerates into '18.

The next question is from Phil Gresh of JPMorgan.

My first question is just going back to the cash flow breakeven at $50 WTI.

The slide is talking about including growth capital in the numbers.

So I was wondering what total capital number you're using there?

Would it be kind of consistent with the $3.6 billion that you're talking about for this year or a higher number?

Ultimately -- for 2018, the number would be higher.

But on a run-rate basis, the -- to provide the 5% growth would be somewhere in the $3.6 billion to $3.9 billion range.

Okay.

So if I look at that slide then and I take 36 or something slightly higher and a dividend of about $2.4 billion, that would imply CFO of around $6 billion at $50 WTI.

And Chris, I know a couple of quarters ago for this year you talked about I believe at $50 it's $4.5 billion.

So I was just wondering what drives a 1/3 increase in the implied CFO to get to that breakeven?

What drives it higher is the better margins and better productivity and better wells that we're seeing in the Permian Basin, number one; better margins and the refocus of the capital that we've discussed today from South Texas and from other things going forward.

What drives it is the improvement relatively versus several quarters ago in the chemicals business.

What drives it is the improvement in the midstream business that we're seeing that we had not seen several quarters ago.

So there are several items that, frankly, are -- have changed in a markedly better way that sort of give us more confidence in our ability to sort of generate that higher number going forward with the reinvestment and better conditions in some of the other businesses.

Okay.

Last question, just the domestic OpEx number.

Chris, I think it went from 13 to 14 for the year.

I was just wondering what was the main driver of higher domestic OpEx.

Yes, the main driver really is just reconstituting the number for the absence of South Texas going forward and a little bit higher prices for injectant CO2 prices.

That's really it.

The next question is from Brian Singer of Goldman Sachs.

Appreciate some of the specifics on big data in response to the earlier question.

I wanted to probe on what you think is uniquely going to be OXY here.

Because I think beyond the secondary and tertiary recovery that has long been an OXY strength, it seems like you're confident in the ability to drive higher recovery rates from primary drilling versus peers.

And wanted to see what you think gets you the superior recovery rate versus simply increasing recovery rate at a similar pace as your competitor.

Yes, Brian, this is Jody.

At this point, probably not talking about what recovery mechanism might be the optimum, we just -- we've got experience everywhere, [Kenz], Mukhaizna field, the Qatar field, in our EOR business.

We find ways to get the most recovery out of these reservoirs economically.

And so we believe the unconventional business is an incredible target because the recoveries in primary are so low.

And so we believe OXY is uniquely positioned to find that extra 5% or 10% additional recovery and leverage the infrastructure investment we've already made in those fields.

And that is in part by the various types of data analytics that you mentioned in response to the earlier question that you think will end up being more proprietary?

Well, I think analytics plays a role there in accelerating your learning because you can do many things by analyzing the data quickly with different models that prevent you from having to do them with experiments or trials in the field.

But it will be a combination of data analytics, field trials, laboratory work, research work that then point us to the right application of a technology depending on which type of reservoir.

Again, it all begins with the core understanding of the reservoir.

Does the underlying rock fabric have some higher fraction of conventional fabric?

Is it truly a source rock shale, very high organic?

That application will be specific on -- to the reservoir.

And then on the SL2, the multilateral wells, can you talk to the time line for pilot results and what those pilots look like versus the schematic on Slide 20?

So the -- we've completed our first one.

We've drilled the second lateral, and the key part of that is we have stimulated the second lateral.

So as the second lateral depletes, we're in the process of removing the frac string and then we'll put it on our official lift.

We'll do more of those this year.

The real application of the technology plays out in '18 and beyond because that's when you're doing your second and third bench development as a higher proportion of the program.

One very quick one, Chris.

Did you say earlier you expect 2Q asset sale proceeds to be net after tax?

We said -- or I said that I expect the proceeds from South Texas to be nearly $600 million net after tax.

And the final question today comes from Doug Terreson of Evercore.

I just have a quick question on corporate governance and specifically your new documents which indicate a little bit of a shift away from the returns-based metrics that you've used historically in favor of payouts that are based on total shareholder return, which is pretty similar to that of your peers.

And so when you consider the emphasis on returns and value in your materials and commentary today, which is pretty prominent, my question is was this change undertaken because returns and other measures appear to be to subsumed by total shareholder return in your view?

Or is something else at work here?

Meaning, why did we have to shift there?

We had a shift because it was really a situation where we wanted to ensure that we were still looking at the metrics with respect to how others are performing.

In the cyclic industry that we're in, we were in a situation where returns were very much impacted, as you know, by oil prices.

Now we're in a situation where we have internally target for all of our executives that are based, to some degree, on a returns metric.

Going forward, we expect to resume including the returns metric as a part of our performance management programs; and that'll be because of the fact that we believe that in the situation that we're in today, we're now generating positive earnings, will generate again positive returns on capital employed.

And that's always been something that's been important for us, and it will be and as is today an internal metric.

Okay.

So it's as important as it's ever been, it sounds like.

Oh, it is.

We're -- that's why we've talked about it so much today.

We -- we're really building our business, and we've gone through this whole process of -- this painful process, I'll say, of exiting 300,000 barrels a day to get us into position where every dollar we spend goes for the highest possible return project.

Exiting the things that we did, with the timing that we had, has now given us the opportunity to grow production with the best possible quality assets.

And you look at it, every asset we have today is generating double-digit returns from capital employed.

And so we're better positioned now to take advantage of that, and our company is going to be able in the future to excel in that area.

This concludes our question-and-answer session.

I would like to turn the conference back over to Richard Jackson for closing remarks.

Thank you, Kate.

We would just like to thank everybody for joining us today and look forward to future discussions with our team.

Thanks.

The conference has now concluded.

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