西方石油 (OXY) 2015 Q4 法說會逐字稿

Good morning and welcome to the Occidental Petroleum Corporation fourth-quarter 2015 earnings conference call.

All participants will be in listen-only mode.

(Operator Instructions).

Please note this event is being recorded.

I would now like to turn the conference over to Chris Degner, Senior Director of Investor Relations.

Please go ahead, sir.

Thank you, Carrie.

Good morning, everyone and thank you for participating in Occidental Petroleum's fourth-quarter 2015 conference call.

On the call with us today are Steve Chazen, OXY's President and CEO; Vicki Hollub, President and Chief Operating Officer; Jody Elliott, President of OXY Domestic Oil and Gas; Sandy Lowe, President of OXY Oil and Gas International; and Chris Stavros, Chief Financial Officer.

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

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

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

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

Our fourth-quarter 2015 earnings press release, the investor relations supplemental schedules, our non-GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off of our website at www.OXY.com.

I will now turn the call over to Vicki Hollub.

Vicki, please go ahead.

Thank you, Chris, and good morning, everyone.

Despite sharp declines in product prices, we had a strong year of production growth, particularly in Permian Resources and we made big strides in lowering our cost structure, as well as executing our strategic review.

I'd like to share highlights of our 2015 achievements.

First, Permian Resources growth exceeded our expectations as we reached our 2016 growth target of 120,000 BOE per day.

This was a year ahead of our original plan.

We increased production by 35,000 BOE per day for a year-over-year growth rate of 47%.

Al Hosn reached full production capacity and delivered an average of 35,000 BOE per day of production last year.

In total, we grew our production by 81,000 BOE per day, which was approximately 14% higher than 2014.

We reduced our cash operating costs by 14%, achieved SG&A savings of 16% and cut our average drilling and completion costs in Permian Resources by 33%.

As a part of our strategic review that we launched at the end of 2013, we sold our Williston Basin properties and made significant progress in our effort to exit non-core areas in the Middle East, including Iraq and Yemen, while also reducing our exposure in Bahrain.

This will lead to lower capital spending in the region.

Construction of the OxyChem ethylene cracker joint venture is on schedule and on budget for startup in early 2017.

We reached a settlement with the Republic of Ecuador for approximately $1 billion, of which we've collected $300 million and expect to receive the remaining proceeds in the coming months.

And we exited 2015 with $4.4 billion of cash on our balance sheet.

Now I'd like to reiterate our strategy and cash flow priorities.

I want to emphasize these have not changed.

Our overall strategy is to invest in projects that generate long-term value, achieving returns well above our cost of capital while maintaining a conservative balance sheet.

Our assets in Colombia, ISND in Qatar, Block 9 in Oman, Permian EOR, Dolphin and OxyChem provide significant earnings, require relatively low maintenance capital and provide free cash flow in this low price environment.

Our most recent addition to this list is our Al Hosn gas project, which is a 30-year joint venture with ADNOC in Abu Dhabi and the role of our Permian Resources business -- the role it will play in our strategy is to provide quick production growth as needed to support our cash flow.

Our top priority for use of cash flow is and always will be the safety and maintenance of our operations.

Our second priority will continue to be funding the dividend.

Third is allocating capital to our growth projects.

The next priority for any remaining cash would be for potential asset acquisitions and/or share repurchases as opportunities arise.

Commodity businesses are inherently volatile.

We maintain a strong balance sheet to not only survive, but to take advantage of potential opportunities.

We will invest our capital prudently and maintain a flexible program as we maneuver through this low price cycle.

As I mentioned earlier, we made great progress last year on lowering our operating and SG&A costs.

We plan to further reduce these costs during 2016 and expect that the financial impact of executing on initiatives from our strategic review will be evident through lower cost and capital in the coming months.

In terms of our capital program for this year, our plan is to carefully reduce our activity levels without harming the strong progress we've made with our growth prospects.

We'll fund only those opportunities that exceed our rate of return hurdles.

Our 2016 capital program is expected to range from $2.8 billion to $3 billion.

This represents a nearly 50% reduction compared to the $5.6 billion spent during 2015.

This capital plan should approximate our expected cash from operations at current commodity prices.

The majority of this year's spending program will be allocated to the Permian Basin and to completing long-term projects in our chemicals and midstream businesses.

Our capital run rate is expected to be higher during the first quarter and following in subsequent quarters as committed project capital winds down.

In Permian Resources, our drilling activity will be highly focused on areas in both the Midland and Delaware Basins where we have existing infrastructure allowing us to achieve higher returns.

Our level of activity will help preserve efficiency gains achieved over the past year.

In Permian EOR, we'll take advantage of reduced cost for labor and materials to modify and expand existing facilities to increase our capacity to handle and inject greater quantities of CO2.

This will enable us to implement additional CO2 projects.

These projects will have longer duration and a typical production response time of one to two years.

This will result in a modest increase in capital for our EOR business versus last year.

Chris will provide greater detail on this year's capital program in a few moments.

Despite the reduction in capital spending, we expect overall company production from our core assets to grow 2% to 4% on average compared to 2015.

Our core assets are pro forma for the expected divestments in areas we plan to exit, including the Piceance Basin, Iraq, Yemen and Libya, along with lower exposure in Bahrain.

The full-year contribution of production from Al Hosn and the startup of Block 62 in Oman should add approximately 35,000 BOE per day of production this year.

Overall, domestic production is anticipated to decline slightly through the year primarily due to declining natural gas and NGL volumes caused by the curtailment of drilling activity in our gas assets in late 2014.

We expect a modest increase in production from Permian Resources versus last year and will hold our Permian EOR production flat.

Turning to our oil and gas reserves, the good news is that we managed to keep our proved producing reserves essentially flat in 2015 due to our development programs and improved recovery from some of our Permian Resources wells.

We continued to see strong performance from our Permian Resources drilling program, which enabled us to replace 214% of our resources' production, excluding net sales and revisions.

Our development programs added 149 million BOE of proved reserves.

Our year-end 2015 proved reserves totaled 2.2 billion BOE consisting of 79% proved developed reserves, up from 71% proved developed reserves at the end of 2014.

Our liquids reserves comprise 74% of our total proved reserve base.

In summary, while the macro environment remains challenging for the industry, we delivered strong production growth during 2015, we lowered our cost structure and continued to execute on our strategic review.

Although we expect commodity prices to gradually recover, we've set our plan to be more aligned with a lower price environment.

We're fortunate to have great set of assets with relatively low base decline rates that provide us with enormous flexibility for our capital.

We believe our continued focus on returns, improved cost structure and strong balance sheet provide us with the opportunity to emerge from the current cycle as a stronger company relative to our peers.

I'll now turn the call to Chris Stavros for a review of our financial results and further details on this year's capital program.

Thanks, Vicki and good morning, everyone.

As Vicki indicated, we continue to have three main objectives over the long term -- generate rates of return on invested capital that are well above our cost of capital, sustainability and growth of our dividend and moderate volume growth of the business.

With regard to returns, we need to strike a balance between managing our capital within the very low commodity price environment and also ensuring that our business is properly positioned for a recovery.

We don't believe that a depleting or shrinking business over the long haul can maintain high rates of return and part of our model is to balance the need for growth and the safety and sustainability of the business while maintaining attractive returns.

Our focus is generating attractive returns and making investments through the cycle in long-term assets that provide us with stable cash flow to see us through during weaker periods.

Despite the low price environment, we've been able to realign our business to focus on our core areas, reduce our overall cost structure through capital efficiencies, lower our total operating costs and SG&A while significantly increasing production in our Permian Resources operations.

In the Middle East/North Africa, the Al Hosn gas project was brought to full capacity by midyear and we also moved forward with exiting some of our non-core assets in the region and eliminating the capital associated with those businesses.

In terms of our capital spending, we adjusted our program last year in response to the sharp decline in product prices with our full-year 2015 expenditures coming in at $5.6 billion, a 36% reduction from the prior year.

Despite this reduction in our spending, we grew our total oil and gas production volumes by 14% from last year.

As we look into 2016, we remain focused on allocating our capital where we have the best returns, including winding down our capital commitments for longer-term projects.

We estimate our 2016 total capital program to be between $2.8 billion to $3 billion and no higher than $3 billion.

This year's capital budget represents a nearly 50% reduction in our overall spending compared to last year and only a third of what we spent in 2014.

The oil and gas segment is expected to comprise approximately two-third of our overall spending this year compared to nearly 80% last year.

We expect the majority of our total 2016 spending will be allocated to our domestic oil and gas business, primarily in the Permian Basin, with roughly 21% to be spent in Permian Resources and about 17% going towards Permian EOR.

We expect this year's spending in our international oil and gas operations to be about half the level of outlays seen in 2015.

Capital allocated toward our Middle East/North Africa oil and gas business is expected to be roughly 21% of total spending with the majority going towards Oman.

The year-over-year decline of about 56% in the Middle East is partly the result of our exit from several countries and our plan to run a more focused business targeting our core areas.

The remaining third of this year's overall capital spending is expected to be split nearly equally between our chemical and midstream businesses of which $500 million of the total is capital committed for projects that we expect to be completed by the end of 2016.

Turning to our results, our core financial results for the final quarter of 2015 were a loss of $129 million or $0.17 per diluted share, a decrease from both the year-ago quarter and also the third quarter of 2015.

The decline in core results is nearly all attributable to weaker commodity prices.

Reported results for GAAP purposes for the fourth quarter were a loss of $5.2 billion or $6.70 per diluted share.

The reported results include $5.4 billion of net after-tax charges mostly related to asset impairments.

OXY follows the successful efforts method of accounting where we review our proved oil and gas properties for indications of impairment whenever events or circumstances indicate that the carrying value of the oil and gas properties may not be adequately recovered such as when there's a significant drop in the futures curve.

During the course of the year, the carrying value of our operations in the Middle East/North Africa was reduced by $4.5 billion with $3 billion of this taken in the fourth quarter.

This action was due to a combination of our exit from non-core areas and the reduction of our exposure to unprofitable projects in the region in an effort to focus the business on improving profitability.

Impairments of our domestic properties amounted to $2.2 billion for all of 2015 and approximately $870 million for the fourth quarter.

Almost half of the total year impairments in the US were due to the exit of non-core assets in the Williston and Piceance basins; the other half related to the reduction in the futures price curve, as well as management's decision not to pursue activity associated with certain non-producing acreage.

In addition, we took a charge of $520 million in the fourth quarter associated with our Century gas processing plant as a result of Sandridge's inability to provide volumes to the plant and in order to meet their contractual obligations to deliver CO2.

Oil and gas core after-tax results for the fourth quarter of 2015 were a loss of $189 million and down $206 million on a sequential quarterly basis.

For the fourth quarter of 2015, total Company oil and gas production volumes from ongoing operations averaged 671,000 BOE per day, 75,000 BOE per day higher compared to the prior-year period and essentially flat with third-quarter volumes.

This excludes production from the Williston assets for all periods.

Our fourth-quarter 2015 worldwide realized oil price of $38.68 per barrel fell by $9.10 a barrel or 19% compared to third-quarter realizations of $47.78 a barrel and down 46% compared to the prior year's fourth quarter.

Domestic oil production was 190,000 barrels per day during the fourth quarter, a sequential quarterly increase of 2000 barrels per day and an increase of 19,000 barrels per day from the year-ago period.

Production in our Permian Resources business grew to 118,000 BOE per day during the fourth quarter, up 40% from the prior year.

Volumes were also able to grow sequentially despite weather-related outages.

Oil and gas cash operating costs were $9.95 per BOE for the fourth quarter of 2015 and $11.57 per BOE for the total year 2015 compared to $13.50 per BOE for the prior year.

The reduction in cost was seen in both our domestic and international operations and reflects decreased activity in downhole maintenance and a lower overall cost structure.

The DD&A for full-year 2015 was under $16 per BOE compared to $17 per BOE seen during 2014.

Taxes other than on income, which are directly related to product prices, were $1.32 per BOE for the 12 months of 2015 compared to $2.45 per BOE in the prior year.

Fourth-quarter exploration expense was $13 million.

Chemicals fourth-quarter 2015 pretax core earnings were $116 million compared with third-quarter earnings of $174 million and $160 million in the year-ago quarter.

The sequential quarterly decrease primarily reflected weaker chlorovinyls demand and lower PVC prices, which negatively impacted margins.

This was partially offset by higher caustic soda prices and lower energy costs.

Midstream pretax core results were a loss of $45 million for the fourth quarter of 2015 compared to income of $31 million in the third quarter.

The sequential decline in the fourth quarter was mainly attributable to lower oil marketing and power generation margins.

The marketing results continue to reflect lower margins due to the narrowing of the Midland and Gulf Coast differentials as the increase in oil supply lowered premiums in the Gulf coast.

The power generation business reflected lower seasonal spark spreads and higher maintenance costs in the fourth quarter.

Looking at our 12-month cash flow for 2015, we generated $4.8 billion of cash flow from continuing operations before working capital.

Working capital changes was a use of $880 million, the majority of which occurred during the first half of the year.

Capital expenditures for 2015 were $5.6 billion, a 36% decline from the $8.7 billion we spent in 2014.

We received over $700 million of net proceeds from activity associated with asset divestitures and acquisitions, which included fourth-quarter proceeds of approximately $600 million for our Williston assets.

In the second quarter, we completed a bond offering issuing senior notes for which we received net proceeds of roughly $1.5 billion.

We indicated at the time of the offering that the proceeds would be used to partially pre-fund some of our debt maturing in the first half of 2016.

Earlier this week, we used cash on hand to retire $700 million of our senior notes that had matured.

We returned $2.9 billion of cash to our shareholders by paying $2.3 billion in dividends and repurchasing 7.4 million of our shares for approximately $600 million.

Our long-term debt to capitalization was 22% at year-end.

The worldwide effective tax rate on our core income was 29% for the fourth quarter of 2015 and 86% for the total year.

Looking into 2016, as we show on slide 23 in the handout, we started the year with $4.4 billion of cash.

During the fourth quarter, at $42 WTI, we generated operating cash flow before working capital of approximately $900 million or roughly $3.6 billion on an annualized basis.

Every dollar change in the oil price impacts our cash flow by about $100 million annually.

We expect to receive an additional $900 million of cash this year from our settlement with Ecuador of which we have collected $300 million to date and approximately $300 million of proceeds from asset sales during this quarter.

Earlier this week, S&P reaffirmed our A credit rating, along with a stable outlook.

Turning to our oil and gas production, for purposes of year-to-year comparison and in terms of providing guidance for 2016, volumes are pro forma and exclude assets we have either already or plan to divest or exit from this year.

These assets would include Williston and Piceance in the US and Iraq, Yemen, Bahrain and Libya in the Middle East/North Africa.

On this same-store sales basis, we expect our full-year 2016 production to grow 2% to 4% or in the range of 570,000 to 585,000 BOE per day compared to about 560,000 BOE per day last year.

In the US, we have ceased all gas drilling activity and will focus our capital in the Permian in an effort to grow our oil volumes and as justified by attractive returns.

We expect our total domestic oil and gas production to be in the range of 270,000 to 285,000 BOE per day in 2016, which includes oil production growth of about 4% and partly offset by modest declines in gas production.

More than two-thirds of our domestic production volumes are expected to be oil.

Production in Permian Resources is expected to average 123,000 BOE per day during the first half of 2016, an increase of 8% compared to the same period last year.

Permian EOR volume should remain relatively flat at about 145,000 BOE per day while providing stable cash flow.

In our core international areas in the Middle East and Colombia, we expect production to increase to roughly a 300,000 BOE per day this year compared to 268,000 BOE per day in 2015 as a result of a full year's contribution from Al Hosn, as well as the startup of gas production from Block 62 in Oman.

In terms of production for the first quarter, on a reported basis and unadjusted for pending divestments or exits, we expect our total production to be in the range of 620,000 to 630,000 BOE per day.

Permian Resources volumes should increase about 3000 BOE per day sequentially to 121,000 BOE per day.

Production in the Middle East is expected to be negatively impacted in the quarter by about 15,000 BOE per day due to scheduled maintenance turnarounds at both Dolphin and Al Hosn.

Our DD&A expense for oil and gas is expected to be approximately $15 per BOE during 2016.

The combined depreciation for the chemical and midstream segment should be approximately $675 million for the year.

Cash operating costs for the domestic oil and gas business should be about $13 per BOE during 2016, about $1 per BOE lower than last year's level for our ongoing operations.

Exploration expense for the year is estimated to be about $75 million pretax with $25 million of that anticipated in the first quarter.

The realignment of our business helped us make strong progress in lowering our SG&A costs last year by more than $200 million.

In the current environment, we expect to reduce these costs by at least another $100 million into 2016.

Price changes at current global prices affect our annual operating cash flow by about $100 million for every $1 per barrel change in WTI.

A swing of $0.50 per million BTUs in domestic natural gas prices affects annual operating cash flow by about $40 million.

We expect our first-quarter 2016 pretax chemical earnings to be about $140 million.

Our chemical operations are essentially a margin business and so while our costs may decline as a result of lower energy prices, prices for the chemical products we sell continue to be driven by demand.

Using current strip prices for oil and gas, we expect our 2016 domestic tax rate to be at 36% and our international tax rate to be about 55%.

I will now turn the call over to Jody Elliott, who will discuss activity around our Permian operations.

Thank you, Chris.

Today, I will review 2015 highlights from Permian Resources and Permian EOR and provide guidance on our program for 2016.

2015 was a very successful year.

Permian Resources achieved our 2016 growth target ahead of schedule by reaching 120,000 BOE per day in November.

We achieved this milestone by leveraging our advancements in geoscience, reservoir characterization and integrated planning to deliver better wells in less than half the time and at two-thirds of the cost versus 2014.

Throughout 2015, we reduced our OpEx cost by over 20% by improving field reliability, productivity and optimizing our surface and subsurface engineering.

Our Permian EOR segment generated free cash flow in a low price environment and had its best safety metrics of all time.

Turning to Permian Resources, in the fourth quarter, we achieved record production of 118,000 BOE per day, a 40% increase versus the prior year.

Oil production increased to 76,000 barrels per day, a 2% increase from the previous quarter and a 49% increase from a year ago.

Winter storms at the end of December impacted total quarter production by approximately 1300 BOE per day.

For the full year, the business achieved production of 110,000 BOE per day, a 47% increase versus the prior year.

Permian Resources continues to drive down capital costs through improved execution and drilling and well completions and reduced time to market.

For each of our core development areas, we continue to monitor both our early time well performance and cumulative production to ensure our development approach is providing maximum value.

In addition to improving individual well performance, we optimized field development value through pace, well sequencing, flowback designs to reduce cleanouts and fluid handling cost, artificial lift designs to maximize long-term production and facility plans to ensure maximum utilization over time.

Our Delaware Basin well performance continues to be strong.

We placed 19 horizontal wells on production in the Wolfcamp A benches in the fourth quarter.

We continue to increase well performance by optimizing the density of our completions and proppant loads and drilling longer laterals.

For example, the Priest E 1H well achieved a peak rate of 1659 BOE per day and a 30-day rate of 1247 BOE per day.

The HB Morrison B 12H achieved a peak rate of 1487 BOE per day and a 30-day rate of 1176 BOE per day.

In New Mexico, we're delivering more productive wells by increasing our proppant concentration and reducing cluster spacing.

For example, the second Bone Spring Cedar Canyon 27 #6 produced at a peak rate of 2498 BOE per day and a 30-day rate of 1750 BOE per day at an 82% oil cut.

In the Delaware Basin, our Wolfcamp A 4500 foot well cost decreased by about 45% from the 2014 cost of $10.9 million to a current cost of $6.2 million.

We reduced our drilling time by 26 days from the 2014 average of 43 days to 17 days.

And our new area of the Midland Basin, we brought the Adams 4231 Wolfcamp A online in the fourth quarter at a peak rate of 2167 BOE per day and a 30-day rate of 1841 BOE per day.

We also brought online the Merchant 1409A well at a peak rate of 1345 BOE per day and a 30-day rate of 1132 BOE per day.

Both wells are producing at over 80% oil cut.

In the Midland Basin, we made similar improvements in well cost and drilling days in the Wolfcamp A formation.

We reduced these costs of the 7500 foot horizontal wells by 35% from the 2014 cost of $9.2 million to a current cost of $6 million.

We reduced our drilling days by 63% from 46 days in 2014 to 17 days in the fourth quarter of 2015.

Across Permian Resources, we're continuing to lower field operating expenses through optimized water handling, lower workover expenses and better downhole performance.

Since the fourth quarter of 2014, we've reduced our operating cost per barrel by 26% and expect this trend to continue this year.

In our Permian EOR segment, we continue to lower our drilling cost and manage the operations to run our gas processing facilities at full capacity.

With resilient base production and low capital requirements, the EOR business continues to generate free cash flow at low product prices.

We've lowered our cash operating expenses by 21% driven mainly by lower downhole maintenance and injectant costs.

Phase 1 of CO2 injection at South Hobbs has continued and we have a production response sooner than expected.

We expect Phase 1 production to peak in 2020.

We expect Phase 1 and Phase 2 to develop 28 million BOE at just over $10 per BOE.

Additionally, we've started a pilot project in South Hobbs testing the residual oil zone.

It has the potential to add about 80 million barrels of reserves.

These residual oil zone reserves can be added between $3 and $7 per barrel of development costs.

Given the current oil price, we will focus investment to achieve four goals -- accelerate geoscience characterization and modeling programs to enhance recovery, well performance and field economic returns; minimize base decline and set up major growth programs in both resources and EOR; focus on game-changing technologies and applications; and accelerate continued improvement in both execution and cost.

One of the key drivers of our gains in well performance has been integrating our technical understanding of the subsurface to optimize well completions.

Slide 41 illustrates our inventory of Permian Resources' well locations by breakeven prices.

By improving both well cost and performance, we continue to make more inventory economically viable in a low-cost environment.

For example, we transferred about 700 locations from above the $60 per barrel hurdle to under $60 per barrel.

Furthermore, we moved 350 locations under the $40 per barrel hurdle.

We expect to continue lowering the hurdle point on our inventory as we move forward.

With current oil prices, our activity in 2016 will focus on core locations that require minimal infrastructure investments.

In addition, we'll gather high priority appraisal data to support future development and initiate seed projects for long-term growth in EOR.

Over the first half of this year, we will reduce our rig count to between two and four drilling rigs in the Permian.

Our technical staff and engineers will focus on long-term projects, enhancing base production, preparing full field development plans to ramp up activity when oil prices recover.

We're taking appropriate steps to preserve the efficiency gains achieved and are well-positioned for growth as prices recover.

I will now turn the call back to Chris Degner.

Thank you, Jody.

We will now open it up for questions.

We will now begin the question-and-answer session.

(Operator Instructions).

Evan Calio, Morgan Stanley.

Good morning, guys.

My first question is one of your key or primary peers cut their dividend today two-thirds after repeated defenses.

I know your balance sheet is superior, yet the macro has changed.

It underpins their decision.

Can you discuss how you perceive your dividend sustainability through the cycle and are there leverage levels or other metrics that would result in a change in your current priorities?

To begin, I'd like to refer you to slide 23.

What we've done really is planned our programs over the next few years based on actually the strip prices.

Although we actually believe that prices ultimately will be higher than the strip, we don't expect prices to really recover much until very late this year, or maybe early next year and recover only to slightly above the curve.

But based on the cash that we have on hand and what we project our situation will be over the next few years, we do expect to be able to make it through this cycle and get back to reasonable oil prices and secure our dividend throughout this entire process.

We're organizing our plans and our activities around that, and the good thing about our portfolio is we have the flexibility to ramp up and down as necessary to ensure that we meet our priorities.

And as we said, the top priority is just the maintenance and safety of our operations.

And then we're going to pay the dividend and we've got the cash to do that.

And generally the way we look at it is we can use our cash flow from operations to cover our capital programs and part of our dividends over some of the years and then what can't be covered by our cash flow from operations, we'll certainly use the strength of our balance sheet to cover that.

So we don't see a threat to our dividend going through this cycle.

Thank you.

I have a related follow-up.

The irony of a downturn I think is opportunities may be the best when liquidity is the lowest.

And so any commentary that you have on the asset market and whether your views of the macro raise the hurdle for acquisition, or change your views on what's potentially attractive?

For instance, more longer lived, longer cycle resource versus a shorter cycle shale resource.

Yes, I would say that we never want to get away from what we truly are as a company and that's what I stated in here is that we're very much on the oil and gas side of the business, an EOR type company and a company that looks for the longer lived reserves like Al Hosn that provides cash flow -- that would be like Al Hosn and Dolphin.

So what we'll be looking at are the assets that have the longer lived reserves.

We're very proud of our shale position and we think that the work we've done over the last few years has certainly proved it up to be an asset that we want to take full advantage of.

But currently our shale production is less than 20% of our total Company production and we don't really want it to ever be much higher than that because we feel like to have the asset base we have that that's part of the reason we'll be able to make it through this cycle with our current low declines.

So that's the sort of asset we'll be looking for.

Appreciate it.

Thank you.

Doug Leggate, Bank of America Merrill Lynch.

Thanks.

Good morning, everybody.

Good morning, Vicki.

Vicki, I wonder if I could follow up on Evan a little bit there.

I'm looking at slide 7, which is the classic slide you put up about the priority for the use of cash.

You've talked about optimism and a rebound in oil prices, but you still have growth capital ranked higher than share buybacks and acquisitions.

I guess my question is you missed an opportunity here with the separation of California Resources to reduce your dividend burden by buying in your stock, which was the original plan, obviously extenuating circumstances.

But in the event of a rebound in oil prices, why does growth capital still rank above reducing the dividend burden?

And I've got a follow-up, please.

Let me point out, I'm very happy that we did not buy back shares.

The $6 billion is going to really be part of what helps get us through this cycle.

And so I think we're fortunate to have the cash that we have on the balance sheet now and that's really what's protecting -- helping to protect the dividend.

But I would view the last two items on the list, the share repurchases and acquisitions, to be right now -- although we show one above the other.

Those we view as equally important and what we're going to look for is the opportunities that arise through the cycle.

We're not going to immediately go out and buy -- repurchase shares.

But what we want to do is look at how the cycle evolves over the next quarters, maybe even next year and half or so and look for opportunities and before we commit to share repurchases.

But I would view those as right now both on the same level of priority.

Chris, do you have anything to add?

I will just follow up on what Vicki said.

I think what she said is right.

We are going to have to look at it on a return basis and clearly, the goal over time will be to reduce the share count as it will help us fund the dividend and fund growth of the dividend over time.

So I do still view -- we still view share repurchases as important over time and a reduction of the share base over time.

So we'll look at opportunities opportunistically to go ahead and do that and it's just going to depend on where things are, vis-a-vis the stock price and other opportunities that may come up for capital.

Okay.

Appreciate the answer, Chris.

My follow-up is also referencing the slide deck, only on slide 41.

You're showing the economics of your drilling backlog at different oil prices.

I guess my question is it would seem that a lot of companies are looking to drill their very, very best assets in the worst commodity environment.

So I'm just curious as to why does that make sense if you are so optimistic on the recovery because obviously the offset of it -- the alternative would be to allow production to decline, but it would also imply you're preserving value, which I think one of your competitors talked about the other day.

And I will leave it there.

Thanks.

I'll start that, but then let Jody add onto it.

We actually were fortunate to be in the process of some development programs in key areas where we're kind of into a manufacturing mode.

We already have the infrastructure installed and so that's what's making our current programs so economical and what we feel like is the right thing to continue to develop during this cycle, and Jody can add to that.

Yes, building on Vicki's comment there, this is some of our best areas, but we really are leveraging more than just the best rock.

It's the infrastructure that we've already invested in.

There's good rock in all of those tranches of inventory.

It's just the maturity of our development plans in some of those areas aren't quite as far along, so we would not develop those until we get those development plans further matured.

And that's one of the focus areas we have this year is to move more of that inventory to the left-side of that chart.

Okay.

I appreciate the answer.

Thanks.

Ed Westlake, Credit Suisse.

Yes, good morning.

Just again a follow-on I think to your answer about the types of assets in shale.

So from that, I'm taking that you're more interested in some of the long-lived assets.

Maybe just give a little bit of color as to where you think those opportunities may lie.

One of the things that we'd like to continue to consider is adding to our position in Permian EOR.

We have the infrastructure there that really can't be duplicated by any other companies.

We've got the 12 gas processing plants, 1900 miles of pipeline and operate two CO2 source fields.

So we have the infrastructure in place to continue expansion of our EOR operations in the Permian and that would be for us one of our higher priorities.

In addition, we see opportunities in Colombia to continue our work there.

We, this past year, signed an agreement to develop another couple of water floods there.

We think that's going to be a good opportunity for us going forward and in addition, in our three core areas in the Middle East, those are the kind of opportunities we would continue to look for.

Okay.

And then as a totally separate question, at the back of the deck, you've got that great chart on slide 41 that Doug mentioned about the inventory.

Obviously, there's a big flip between $50 and $60.

And then if you look at the colors of the bars, you've got a lot of Bone Spring acreage, Spraberry and then the Wolfcamp B. Maybe just -- and this is based on 4Q costs -- hopefully those are the ones that you identified, that $6 billion in the Wolfcamp and $6 million in East Midland.

What are the biggest levers you think about taking that inventory that works at $60 down to $50?

I think one of the biggest levers is multi-bench development, ensuring that the field development plans allow us to economically develop more than one good bench at a time and so that's part of the redeployment effort of our technical staff to figure out multi-bench to drive better utilization of our infrastructure cost in those areas.

That will be the biggest thing to move them to the left.

You mentioned reduce cluster spacing in some of those Bone Springs wells.

Is there a lot more technology that you can still apply?

I think there is.

Good to know.

I will keep in touch.

Phil Gresh, JPMorgan.

Good morning.

The first question is just on the guidance.

There's, obviously, a lot of moving pieces here on the production side, but, Chris, just with respect to the 1Q, the 620,000 to 630,000, I believe you said that that would exclude the asset sales, the domestic asset sales, but it does not have anything contemplated in there for the Middle East asset exits.

So I wanted to clarify that and then just generally ask how that's going and how you would expect that 72,000 barrels a day of non-core Middle East to roll off as the year progresses.

Sure.

Thanks, Phil.

On the guidance, just to make it comparable for you to reconcile it, the way I would think about it is that you've got the Piceance in the US that we'll exit or be sold and closed this quarter, so that will come out of the system.

And then there's production in there for Bahrain as well.

So combined I would tell you that it probably amounts to about 50,000 to 60,000 BOE per day on a like-for-like basis to adjust for our ongoing core production for the guidance that I gave for the full year of 2016.

That would be the reconciliation.

Okay.

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

Currently, we're continuing with our operations in Bahrain and we're working with our partners there to lower our exposure, but in Iraq we're progressing with the terms of the exit according to our contract terms.

So we should be winding down in Iraq and that's going to be transferred to one of the national oil companies.

So we'll be out of there by, we're hoping, midyear.

Yemen, that's pretty much -- our contracts have expired and we're reducing our exposure in the one area that we currently have and expect to be able to exit that by midyear as well.

So everything is progressing.

In Libya, we're not quite to the point where we have been able to develop a specific exit strategy and specific steps because of the uncertainties around that process with the government, but we have stopped our capital investment in Libya and we're only spending the funds necessary to maintain the operation safely.

Got it.

Okay, and then, Chris, my follow-up is just on the balance sheet.

Understand the willingness to protect the dividend.

Is there a level of debt, whether it's debt to cap or debt to EBITDA?

OXY has always been fairly conservative on the balance sheet and for good reason.

Just wondering if there's a level where you get less comfortable?

Well, whatever that level is we don't plan to take it there.

So that's one of the reasons that we maintain a strong balance sheet that it allows us to pay the dividend and not be overly concerned about it.

And I think our view is that we sort of take a measure of offense on this and sort of view ourselves as competitively advantaged as an investment vehicle within the sector.

So you keep a strong balance sheet with low debt because you're a dividend payor and having a lot of debt as a company in the sector just -- the two don't mix.

So that's sort of how we view it.

Okay.

Fair enough.

Thanks.

Ryan Todd, Deutsche Bank.

Thanks.

Good morning.

Maybe if I could follow up a little bit on the capital outlook over the next couple of years.

You highlighted $500 million of committed capital in 2016 that will roll off by year-end 2016.

Is there any offset to this that's set to ramp into 2017, or should we expect, on an apples-to-apples budget, does the budget roll by $500 million into 2017 and would this likely be -- would you likely fill that gap with accelerated activity in the US onshore?

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

Okay.

And maybe, I guess maybe as one follow-up to that, you're going to two to four rigs in the Permian, you said, for the second half of the year.

Can you talk a little bit -- and I guess at a high level you provided us in the past with what you felt was kind of a maintenance CapEx number for yourself.

Do you have an updated view on what your maintenance CapEx is generally as an overall business in terms of holding production flat and maybe a similar number to what you think you need either from a rig or a spend level to keep Permian Resources flat?

The Permian Resources is a challenge because our teams keep improving so much.

The efficiency gains they've made over the last couple of years has just been incredible and Jody and I were talking about that this morning and the reason we gave the range of two to four is we used to think that it would take more than four rigs to offset our decline, but we're certainly convinced now with the efficiency gains we're having and particularly the way that Jody and his team are starting to develop the fields, we think it could be less than that.

Jody, I will let you provide some additional color on that.

That's clearly correct, Vicki.

Every day, our teams amaze us with new drilling records, new production records.

So predicting that exact rig count to keep production flat kind of changes month-to-month.

Is roughly the goal to size your activity levels from the middle of this year to hold the Permian Resources flat, is that roughly what you are trying to target?

That level would probably flat to slightly increasing.

Great.

Thank you.

Roger Read, Wells Fargo.

I guess I'd like to probably go down the path some of the other guys have as well on thinking about the drilling efficiencies and following up on the answer to the last question.

Two to four rigs maybe allows you to stay flat.

Is it a function of more above ground, below ground or combination of the two that's driving this?

And I'm thinking of the slide 33 where you show drilling days and best is still significantly better than average and then the comments earlier about the -- I think it was specifically the benches, being able to develop those as a way to get the cost down.

What's the way we should think about it maybe for 2016 and then beyond 2016?

It's really about all the things you mentioned.

It's drilling performance; it's well completion performance.

I think the biggest gains we've had this year is the integration of our subsurface understanding into that execution activity as well, keeping wells in zone; keeping them in the sweet spot; engineering frac designs differently; optimizing cluster spacing; optimizing sand concentrations.

All those things, I think, lead us to being able to do more with less, not just drilling days and drilling cost.

And then as you think out beyond this year, what do you think gives you the greatest upside potential, not just the bench that you mentioned earlier.

Is there anything else we should think about?

I mentioned multi-bench.

I think that's one.

I think the other is really optimizing infrastructure, both our internal infrastructure and working with others to take advantage of infrastructure in the two different basins.

Okay, great.

And just my follow-up, unrelated, Al Hosn, was wondering if we can get a little more of an update on just how that's performing relative to your expectations.

The turnaround coming in Q1, I assume, is a normal part of the startup process and maybe how we should think about it latter part of this year on forward.

Yes, we're in the warranty shutdown, which is common for all these projects and we had produced over nameplate for several weeks before the shutdown.

We expect the year to give us slightly over nameplate as an average after the shutdown, of course, and it's performing very well.

Great.

Thank you.

Paul Sankey, Wolfe Research.

Again, going back to the efficiencies, you said fairly clearly that it was reliability productivity optimization.

Can you first try and strip out how much of the performance improvement has simply been lower oil prices and how much is organic?

And secondly -- and sustainable -- and secondly, could you highlight or contrast how you're differentiated from others in the Permian in any of those themes?

Thanks a lot.

I think the majority of that improvement is organic.

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

Right.

And you think it can continue as well?

I think you said you've talked about returns that are relatively low -- what seems to be a fairly low view of the oil price for the rest of the year and beyond even.

Can you talk about what you think the breakeven price is for you guys for your returns in the Permian?

And I'm aware that you've got both EOR, which is presumably a different answer from the unconventional.

And then could you -- I'll stop going on -- but could you then also talk about how you compare to other companies in your view?

Thanks.

First of all, Paul, I'd like to address the comparison to other companies.

One of the things that we've been able to do in the Permian versus others is we've been there for a long, long time, so we've got a lot more data than other companies and we're doing more with that data.

We have a lot of 3D seismic.

We have -- in addition to the 3D seismic, we have more than 20,000 wells from which we have data.

And we have 4400 outside operated wells and I know you've heard all those numbers from me before, but we are really taking that data and taking it to the next level.

We have a team that works with our resources team.

Our resources team, I just have to say, is incredibly efficient in what they've been able to do and to drive the drilling costs down, the completion optimization and all the things that Jody has talked about, they've done a great job.

It's just been incredible.

But in addition to that, the team supporting them from a downhole science standpoint is our exploitation team, which takes all that data that we get from every well and we utilize every bit of data we can, not only applying data analytics to it, but taking a lot more data than other people have access to.

I think we still have the only horizontal core in the Permian.

We're doing much more modeling around geomodeling and learning more about the thermal maturity and the migration of hydrocarbons.

So I think that's really helped here recently to make a big difference in the improvement of the resources wells.

And I think to build on Vicki's comments, we recently held what we called a cost standdown day where we took the entire Company and stopped and said let's get creative, let's get innovative on how we improve our business.

We focused on SG&A.

We focused on capital cost.

We focused on operating expense.

We focused on development opportunities.

And there's literally thousands of ideas that we have vetted and are currently vetting and that gives me even more confidence that we can move that hurdle breakeven lower for a number of these areas.

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

The returns for the Permian EOR business, we have a, for Permian EOR, a cash cost right now that's less than $20 and our DD&A is less than $10.

We're continuing to drive that down.

Expect that to go lower this year.

So in our Permian EOR business, currently, we can flex that around a bit by developing some of these ROS developments, which Jody mentioned in his presentation.

Some of those developments get down as low as $3 on the F&D side.

So we have a range of opportunities in the Permian EOR business that we can develop.

Some of the ROS developments that go down to an F&D of $3, those are fairly limited in size.

So what we always try to do is blend the bigger projects that maybe have the $8 or $9 or $10 F&D with the smaller projects to get a blend of all of those.

And on the resources side, certainly our costs have been coming down there.

The operating cost is done much lower than it was.

The DD&A for our resources business currently is higher because of the infrastructure that we've -- that you always install upfront, but the F&D costs, development cost on a per BOE basis is coming down.

To tell you a number of where that's going to be, I think -- I'd hate to prematurely forecast something that I'm sure the teams are about to beat, but we're continuing to lower our costs and resources.

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

On the resources side?

Yes.

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

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

Basically, you've got positive cash margins here at the strip for the Permian Resources and EOR for sure, Paul.

That's the way I would think about it.

Appreciate that.

Thanks all of you.

John Herrlin, Societe Generale.

Thanks.

Getting back to slide 41, will you make more of a push towards the Delaware given the relative economics of a place like the Bone Spring?

And specifically for the sub $40 type inventory you highlighted, could you give me a better sense of maybe -- maybe this is redundant -- could you give me a better sense of the split between the formation itself, the well design and also the infrastructure because obviously you're stressing the integrated nature of your approach, but certainly good rock matters, but I was wondering about how important your well design changes have been to lower that threshold?

John, that's a great question.

We're really encouraged by the recent results with upsizing our fracks in the Bone Spring into Mexico, but when you look at field development maturity and our infrastructure maturity, the Wolfe/Bone has just got a jumpstart on that over on the Texas side.

So early in the year, we'll be in the Wolfe/Bone where we can take advantage of that infrastructure and as we get the field development plans matured in the Bone Spring area and incorporate more of the appraisal data that we've captured over this last year to ensure that we're as efficient as possible when we do put the rig back into Mexico.

Okay.

That's fine.

Last one for me is you sold a lot of reserves during the year, about 600 billion barrels.

I was wondering if you could break them down geographically, what you sold.

Yes, the Bakken reserves were very small at the end of the day.

We didn't sell.

These are sort of -- we took down the PUDs basically of the domestic part of the business.

Okay.

Thanks, Chris.

This concludes our question-and-answer session.

We would like to turn the call back over to Chris Degner for any closing remarks.

Thank you.

And I will turn the call over to Vicki for some closing remarks.

I just wanted to say I don't think we fully answered Paul's question.

So to get back to that -- in the EOR business with our cash cost and our DD&A of around 24 to 25 and then in the resources business, our cash cost and DD&A in the neighborhood of 22 to 23, that's basically about half of what -- the price we're seeing on the strip, as Chris had said.

Generally that delivers for us about a 50% rate of return.

So just wanted to close with that.

Okay.

Thank you, Vicki, and thanks to everyone for participating on the call.

Have a good day.

The conference has now concluded.

Thank you for attending today's presentation.

You may now disconnect your lines.

Have a great day.