西方石油 (OXY) 2015 Q2 法說會逐字稿

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

(Operator Instructions).

Please note this event is being recorded.

I would now like to turn the conference over to Chris Degner.

Please go ahead.

Thank you, Emily.

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

On the call with us today are Steve Chazen, Oxy's President and Chief Executive Officer; Vicki Hollub, Senior Executive Vice President of Occidental and President, Oxy Oil & Gas; Chris Stavros, Chief Financial Officer.

In just a moment, I will turn the call over to our CEO, Steve Chazen, who will provide an updated outlook for 2015.

Our CFO, Chris Stavros, will review our financial and operating results for the second quarter and also provide some guidance for 2015.

He will be followed by Vicki Hollub, who will provide an update of our activities in the Permian Basin.

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 in the Company's most recent Form 10-K, our second-quarter 2015 earnings press release, the investor relations conference call slides, our non-GAAP to GAAP reconciliations can be downloaded off our website at www.oxy.com.

I will now turn the call over to Steve.

Steve, please go ahead.

Thank you, Chris.

We have made progress towards our objectives for this year.

Our principal goal for the year is to achieve cash flow neutrality, where our operating cash flow covers both our capital spending and dividend outlays at $60 per barrel realized oil prices.

We will achieve this goal through deploying our capital and operating cost savings into further production and cash flow growth, driven mostly by our Permian Resources business unit and the start-up of the Al Hosn Gas Project.

Year to date, we estimated about $450 million in captured cost reductions.

We expect our 2015 capital outlays to be about $5.8 billion as we have redeployed some of the cost savings in drilling more wells in our Permian Resources business unit.

In short, we are learning to do more with less and expect continued improvement in productivity through the year.

Despite volatile product prices, our oil and gas segment has been operating well in nearly all of our key assets.

We have increased total oil production by 16% since second quarter of 2014.

The focused development program in Permian Resources has driven most of the growth, as well as strong production volumes in Oman and Colombia.

We have also focused on optimizing our base production.

Rather than making headcount reductions during this downturn, we have sent many of our engineers out into the field to replace contractors.

They have done a good job of maintaining our base production and driving operating efficiency.

In the Permian, we have shifted our resources business to a focused development program.

We are drilling completing wells at a faster pace and have accelerated our time to market.

Total production increased by about 50% year over year and has again exceeded our internal outlook.

As such, we have increased our estimate of production for the second half of the year to 117,000 BOE a day.

Actual results continue to improve and outperform our internal outlook.

Al Hosn is a large world-scale project and the first of its kind.

It is reasonable to expect some operational pains as it is ramped up to full production.

In the second quarter of 2015, Al Hosn produced 18,000 BOE a day and sold its first shipment of sulfur.

Due to mechanical challenges in the sulfur recovery units, the plant was limited to 50% of capacity for most of the quarter and production was curtailed for most of the month of April.

Repairs to stabilize the sulfur units were completed in July and the plant has responded well as production has ramped up.

The plant is currently producing at about 50,000 BOE a day to us and we expect it to contribute about 30,000 BOE a day in the third quarter.

Despite a lower capital production, we expect production growth of 70,000 to 80,000 BOE a day in 2015, driven by the start of the Al Hosn Gas Project and focused development program in Permian Resources.

In the United States, we expect oil production growth of about 8%, partially offset by declines in NGLs and natural gas production.

Vicki Hollub will provide further details in the outlook for the US oil and gas business.

Construction on the Ingleside ethylene cracker is ahead of schedule and on budget.

There are currently 1,300 workers on site.

Construction is about 30% complete and over 80% of the equipment has been purchased and delivered.

We expect to be more than 70% through our capital spending on the project by year-end and for the plant to start up in early 2017.

As we capture price savings from suppliers and improve the efficiencies of our operations, we are able to do more with less spending.

Our capital spending in the second quarter declined by about $250 million and will continue to decline throughout the year.

As for our forecasted capital spending level, in some Middle Eastern assets it may be slightly higher than expected this year; however, the production sharing contract should allow us to quickly recover our capital costs with an increase in oil production.

We expect to exit this year at a quarterly spending rate of $1 billion to $1.2 billion.

If oil prices remain at current levels, around $50, our 2016 capital will be less than both the 2015 full-year and the fourth-quarter run rate.

Given our large acreage position and deep inventory, we have the flexibility to defer drilling and appraisal activities.

Although we will outspend our cash flow this year, we expect that going forward our operating cash flow will cover our capital expenditures and dividend payments, assuming $60 per barrel oil price realizations.

We continue to invest growth capital in the Permian resources segment.

Over the first half of the year, we did not make any meaningful acquisitions, nor do we have any in the pipeline.

The market for asset acquisitions in the Permian Basin has been heated, with new entrants paying sizable premiums for acreage.

With our deep inventory of assets, we will focus on organic growth, with a low possibility of selected bolt-on acquisitions that leverage our existing infrastructure and geologic understanding.

We have approximately 64 million shares remaining under our current share repurchase authorization.

At current stock price levels, we would view the stock as attractive for repurchase.

Now I will turn the call over to Chris Stavros for a review of our financial results.

Thank you, Steve, and good morning, everyone.

First, I want to highlight some new formatting around our quarterly disclosures.

We created a set of earnings release schedules that replaces the previous IR supplemental schedules.

The new format is more comprehensive, providing condensed quarterly financial statements, plus quarterly data going back for the entire prior year.

We generated core income of $165 million for the second quarter of 2015, resulting in diluted earnings per share of $0.21, an increase of $0.04 per share in the first quarter of 2015 and a decrease from $1.38 per share in the second quarter of 2014.

Worldwide oil prices improved about $6 a barrel in the second quarter of 2015, compared to the first quarter, but still remain well below prices comparable to last year.

US natural gas prices continued to decline, down about $0.40 per Mcf from the first quarter, and NGL prices stayed essentially flat.

Our second-quarter capital spending was about $1.5 billion, down 14% from the $1.7 billion we spent in the first quarter.

We continued to ramp down our capital program in the second quarter, focusing our development activity in core areas of the Permian Basin and parts of the Middle East with an emphasis on growing our production volumes and, importantly, our operating cash flow.

Despite the reduction in this year's capital program, we continued to grow our domestic oil and gas volumes, driven by our Permian resources operations.

Permian resources grew its oil production 78% in the second quarter, adding 31,000 barrels per day compared to the year-ago period, with total BOE growth of 51%.

Production from Permian resources improved 11,000 BOE per day sequentially, with 9,000 barrels per day coming from oil.

Turning to the specific business segments, oil and gas core after-tax earnings for the second quarter of 2015 were $108 million, $130 million higher than the first quarter and $833 million lower than last year's second quarter.

As I mentioned earlier, the largest impact to the change in year-over-year earnings was due to lower oil prices.

For the second quarter of 2015, total Company oil and gas production volumes averaged 658,000 BOE per day, an increase of 13,000 BOE in daily production from the first quarter and 78,000 BOE per day from the same period a year ago.

Total Company oil volumes were 433,000 barrels per day in the second quarter, 61,000 barrels per day higher than the year-ago period for an increase of 16%.

Total domestic oil and gas production averaged 333,000 BOE per day during the second quarter of 2015, up 7,000 BOE per day sequentially and 25,000 BOE on a year-over-year basis, with all of the increase coming from Permian resources.

This was partially offset by lower production from our Mid-Continent assets, where we have ceased our drilling activity.

Domestic oil production was 205,000 barrels per day during the second quarter, an increase of 7,000 barrels per day sequentially and up 26,000 barrels per day, or 15%, from the year-ago quarter, exceeding our earlier guidance for the period.

For the year to date, overall domestic production volumes have exceeded our expectations.

Our domestic production growth for the first six months of 2015 resulted in an additional $175 million of operating cash flow when compared to the last six months of 2014 and using current product prices for both periods.

We achieved this growth while reducing our domestic capital by $389 million.

In summary, we not only drilled and completed the wells, but sequentially grew both our production volumes and operating cash flow, which can be reinvested in the business.

International oil and gas production volumes averaged 325,000 BOE per day during the second quarter, up 6,000 BOE per day sequentially and 53,000 BOE per day on a year-over-year basis.

Production from the Al Hosn Gas Project increased by 9,000 BOE per day from this year's first quarter to 18,000 BOE per day in the second quarter and, as Steve mentioned, also realized the sale of its first shipment of sulfur.

Production was curtailed during much of the second quarter as mechanical modifications and adjustments were made to the sulfur recovery units.

These adjustments have been completed and we expect our net production to exit this month around 50,000 BOE per day.

Our second-quarter oil and gas cash operating costs of $12.10 per BOE declined 9% from the first quarter of $13.36 per BOE, due to lower surface and downhole maintenance costs, lower workover costs, as well as higher production volumes.

DD&A for the second quarter was $16.06 per BOE, compared to $15.35 per BOE during the first quarter.

Taxes other than on income, which are directly related to product prices, were $1.85 per BOE for the second quarter of 2015, compared to $1.63 for the first quarter of 2015 and $2.45 per BOE for the full year of last year.

Chemical pretax earnings were $136 million for the second quarter of 2015.

Results were lower than expected, due to higher ethylene feedstock costs and lower caustic soda prices, as well as some unplanned outages at two of our VCM plants.

Midstream pretax earnings were $84 million during the second quarter, compared to a loss of $5 million in the first quarter of this year and income of $130 million in the same period a year ago.

Our midstream segment is composed of physical marketing, pipelines, power, and gas processing.

Our physical marketing is exposed to spreads between WTI, Midland, and Gulf Coast pricing through multiple pipeline commitments.

In the second quarter, our midstream segment results benefited from wide price differentials.

We expect this benefit to partially reverse in the third quarter, as price differentials have narrowed.

Our gas processing business converts wet gas to NGLs.

Currently, NGLs are trading at an equivalent price of natural gas which is insufficient to cover the plant operating expenses.

Our domestic pipelines, as well as the Dolphin Pipeline, generate a relatively stable and strong stream of tariff income from transporting crude oil and natural gas.

Operating cash flow before working capital changes for the first six months of 2015 was $2.6 billion.

As I mentioned, higher production volumes resulting from our continued investment in the Permian, as well as improved oil price realizations, resulted in a sequential increase of about $400 million in operating cash flow before working capital changes to $1.5 billion in the second quarter.

Working capital declined by $950 million during the first six months of 2015.

At December 31 of last year, accounts payable was $5.2 billion, and as of June 30 of this year, it decreased by $1.1 billion to $4.1 billion.

This decrease was due to payments related to higher capital and operating spending accrued in the fourth quarter of last year, but not paid until 2015.

Total Company capital expenditures for the first six months of 2015 were $3.2 billion and about on track with our full-year 2015 capital budget of $5.8 billion.

Oil and gas spent $2.7 billion in the first half of 2015, with Permian resources expenditures comprising 47% of the total and the remaining $500 million split nearly evenly between chemicals and midstream.

The continued growth in our operating cash flow should help us to achieve our goal of being cash flow neutral after capital expenditures and dividends at oil prices of roughly $60 a barrel.

In June, we completed a bond offering, issuing senior notes at 3-1/2% and 4.625% and received net proceeds of approximately $1.5 billion.

The proceeds were used to build liquidity and partially pre-fund some of our debt maturing in the first half of 2016.

Oxy's credit ratings remain unchanged at A by Moody's and S&P.

We paid cash dividends of $1.1 billion in the first six months of 2015 and purchased 7.4 million shares of our stock for $571 million.

This amounts to an annualized cash return of 6.2% for our shareholders.

The share repurchase activity for the first six months also has the benefit of reducing our annualized dividend outlays by approximately $22 million.

Our cash balance at the end of the second quarter was $5.1 billion.

Our long-term debt to capitalization ratio was 17% at the end of the second quarter.

The worldwide effective tax rate on our core income was 65% for the second quarter of 2015.

Looking ahead to the third quarter domestically, we expect production from Permian resources to grow by roughly 5% sequentially on a BOE basis, including 5,000 barrels a day of oil growth.

Growth in the Permian should be roughly offset by declines in our Mid-Continent production, leaving our overall third-quarter domestic production about flat with the second quarter.

We expect our international production volumes to increase by about 10,000 BOE per day in the third quarter.

Production rates at Al Hosn should continue to improve, increasing to about 35,000 BOE per day, on average, in the third quarter.

The increase from Al Hosn should be partially offset by approximately 8,000 barrels per day of lower volumes in Colombia, due to pipeline disruptions experienced during July.

Assuming no meaningful disruptions during the second half of the year, we are raising the lower end of our full-year 2015 production guidance range from 650,000 to 660,000 BOE per day.

Our current estimate of full-year 2015 volumes of 660,000 to 670,000 BOE per day will provide year-over-year growth of 12% to 13%.

Price changes at current global prices affect our quarterly earnings before income taxes by $30 million for a $1 per barrel change in oil prices and $7 million for a $1 per barrel change in NGL prices.

A swing of $0.50 per million BTUs in domestic gas prices affects quarterly pretax earnings by about $15 million.

Our third-quarter 2015 exploration expense is anticipated to be about $20 million pretax.

We expect our third-quarter 2015 pretax chemicals earnings to be about $140 million.

Our third-quarter midstream earnings will be principally impacted by Midland to Gulf Coast oil price differentials.

We expect our interest expense to increase to about $50 million in the third quarter from $7 million in the second quarter.

The sequential increase is due to expensing of previously capitalized interest on the Al Hosn project and the $1.5 billion senior notes we issued in June.

Using current strip prices for oil and gas, we expect our full-year 2015 domestic tax rate to be 36% and our international tax rates to remain about 65%.

To summarize, we demonstrated strong year-over-year production growth of nearly 13% in the second quarter, bolstered by continued growth in Permian resources and from the Al Hosn project.

We also continued to grow our operating cash flow, which is being used to organically reinvest in the business, while providing a balanced return of cash to our shareholders.

I will now turn the call over to Vicki Hollub, who will provide an update on our operations in the Permian basin.

Thank you, Chris.

Today, I will review the highlights of our Permian resources and Permian EOR activities in the second quarter, and then I will provide guidance on our program for the remainder of 2015.

I would like to highlight a few key messages.

First, Permian resources is continuing to drive capital costs down through improved execution efficiency in drilling and well completions.

Second, production again exceeded expectations, due to reduced time to market and better-than-planned well performance.

Finally, the positive returns of our Permian unconventional programs in this environment, along with the large volume, low decline production from our EOR operations, provides us flexibility in a wide range of product prices.

The advantages this portfolio provides can't be duplicated in the Permian Basin.

In the second quarter, Permian resources achieved daily production of 109,000 BOE per day, a 12% increase from the first quarter and a 51% increase versus the prior year.

Oil production increased to 71,000 barrels per day, a 15% increase from the previous quarter and a 78% increase from a year ago.

We drilled 47 wells, including 42 horizontals.

We placed 71 wells on production, including 53 horizontals.

In the second half of this year, we will operate about 12 rigs and drill and complete at least 100 horizontal wells.

We continue to work on four key activities that are adding more wells to our inventory and reducing the economic hurdles of our inventory.

First, we have used our vast database to update our basin hydrocarbon richness maps and to build the petrophysical and geochemical models necessary to improve well performance and to add more locations to our inventory.

Second, our teams have further reduced our drilling and completion costs and optimized the value of a manufacturing approach in our key areas.

Third, although we have achieved significant cost savings from our vendors, we continue to look for creative ways to reduce service and materials costs further.

Lastly, we are enhancing base management and maintenance operations to maximize production at minimal incremental cost.

These activities have generated higher-than-expected production and have lowered our finding and development costs, thereby increasing our inventory of drilling locations that deliver returns which exceed our cost of capital.

We will provide an update of our inventory by play and breakeven prices later this year.

In the fourth quarter of last year, we began transitioning from appraisal mode to a targeted development program, utilizing a manufacturing approach combined with integrated planning and engineering.

This has reduced nonproductive time; maximized the efficiencies of pad drilling, including the use of zipper fracs; and has reduced infrastructure cost.

As a result of these efforts, we have achieved significantly improved well delivery and lower well costs.

As the example on slide 27 illustrates, we have reduced our drilling time by about 50% and our costs by about 40% in a recent Wolfcamp A well in the Delaware Basin.

Our improvements were driven by adopting and adapting oilfield technology, including an advanced mud system to eliminate casing across the salt interval in the wellbore.

Oxy Drilling Dynamics is a proprietary system we have developed by expanding upon mechanical-specific energy concepts to improve rates of penetration.

This improvement in drilling efficiency is a structural change to our business that will sharply lower our cost, irrespective of pricing concessions from our suppliers.

In the Delaware Basin, our Wolfcamp A 4,500-foot well cost decreased by about 40% from 2014's cost of $10.9 million to a current cost of $6.8 million.

We have reduced our drilling time by 23 days from 2014's average of 43 days to 20 days.

I would note that even as we had lowered our completion costs per well, we have optimized the density of our completions and proppant loads and have been drilling longer laterals.

As I will highlight later, our productivity has continued to improve while we have lowered our costs.

In the Delaware Basin, we have identified 900 additional horizontal development locations for a total of 5,700.

We have 2,000 horizontal well locations ready for development, including 800 sites in the Wolfcamp A bench.

The majority of these locations are in our operated areas in Reeves County.

In New Mexico, our Bone Spring potential is equally as significant with 2,300 locations.

Our well performance in the Delaware Basin continues to be strong.

We placed 13 horizontal wells on production in the Wolfcamp A benches in the second quarter.

These wells achieved an average peak rate of 1,359 BOE per day and a 30-day rate of 988 BOE per day.

The Moore Hooper 3H well achieved a 2,389 BOE per day peak rate and a 1,769 BOE per day 30-day rate.

Additionally, our Lenox 2 5H well achieved a 2,425 BOE per day peak rate and a 1,506 BOE per day 30-day rate.

Both of these wells produced around 70% oil and we believe that they are among the most prolific drilled to date in the Permian Basin.

Now I would like to shift to the Midland Basin.

We have made similar improvements in well costs and drilling days in our Wolfcamp A wells in the eastern part of the Midland Basin.

We reduced the cost of the 7,500-foot horizontal wells by 30% from 2014's cost of $9.2 million to a current cost of $6.5 million.

We reduced our drilling days by more than 50%, from 46 days in 2014 to 20 in the second quarter.

Through our program this year and in evaluating the acreage from the acquisition in December, we have added 600 horizontal locations in the Midland Basin, for a total now of 3,100.

Most of the additions were in the Wolfcamp A and Spraberry formations and we now have 2,000 identified locations ready for horizontal development.

A new area for us is in the Midland Basin.

It is called Big Spring, which was part of the December acquisition.

We launched into development early this year, and in the second quarter, we brought on line the May 1102 Wolfcamp A well at a peak rate of 1,846 BOE per day and a 30-day rate of 1,262.

The well is producing at over 85% oil.

These Wolfcamp A well results have been outperforming our initial type curves for this emerging play in Howard County.

Now shifting to Permian EOR, where year to date we are ahead of plan in meeting our aggressive cost-improvement target.

We've reduced the cost of drilling San Andres wells by about 30% through optimized drilling parameters and crew efficiency.

Additionally, we have reduced our downhole maintenance hours per job by 20% since the fourth quarter by applying the learnings gained from a manufacturing approach to well maintenance.

We have 15,000 wells in the Permian EOR business and expect to reduce our 2015 downhole maintenance and enhancement cost by $60 million versus 2014.

These cost reductions will further increase the free cash flow generated by our Permian EOR business in the current oil price environment.

Despite the low price environment, we're continued to commit to developing our technical talent and recently finished construction of a new training center in Midland that will open in September.

In previous industry down cycles, we have seen the industry overreact through widespread layoffs.

We are taking a different approach with our response to low oil prices and have deployed many of our engineers in the early stages of their careers out into the field, where they have replaced contractors.

They are successfully helping to optimize our base production, improve drilling times, and gain on-the-ground experience.

In closing, we will continue to execute a focused development strategy in 2015 and we will pursue additional step changes in well productivity and cost structure.

For the remainder of 2015, we plan to operate an average of about 12 drilling rigs to drill around 100 horizontal wells in Permian resources.

This is a higher activity level than planned, but we believe investing efficiency gains back into Permian resources is a prudent action to take.

We expect to produce an average of 117,000 BOE per day in the second half of 2015 and for the business to drive continued growth in operating cash flows.

Strong production growth from our Permian resources business, along with the high volume, low capital-intensive Permian EOR business, keeps us well positioned to not only meet the challenges of this lower price environment, but also to profitably grow our combined Permian business.

Now I will turn the call back to Chris Degner.

Thank you, Vicki.

We will now open it up for questions.

Emily?

(Operator Instructions).

Evan Calio, Morgan Stanley.

My first question, Permian resources production beats again, very impressive cost and efficiency improvements here.

Really two questions, does your performance lower your existing targets?

And, secondly, how would you benchmark your Permian operating performance versus peers where there is a pure scope to see some continued improvement for a group that is improving at a pretty fast pace?

Currently, we feel like in the Delaware Basin we are definitely upper quartile in terms of drilling performance, and actually we have recently compared our performance to some of our competitors and we feel like there is maybe one or two operators that have had a couple of wells, a few wells better than ours, but with the direction that we are headed, we expect to be first in performance in drilling in the Delaware Basin due to the activities and initiatives that I just discussed.

And with respect to well performance, we looked recently at what some offset operators are doing, and compared to offset operators in the Delaware Basin, as I said in my discussion here, we believe that we have just completed some of the best wells in the basin in the Delaware.

In the Midland Basin, this new area that we are developing now in Big Spring is certainly showing some of the best production that we have seen yet in the Midland Basin, as well.

So in some areas in the Midland Basin, we are about par, and in some cases slightly lower than some of our competition, but certainly this Big Spring area is competing very well, as is Merchant.

Right, and does that reset your targets, in terms of the targets you put forth in the slides?

For now, what we're trying to do is for -- we feel comfortable with what we have stated for the second half of this year, so that's the target we expect to be able to hit, which equates to about 109,000 average for 2015.

With respect to 2016, our targets on a per-well basis, on the average, are going to increase, but what we haven't determined yet is what level of activity we will have for 2016.

So we feel very comfortable that we're going to have a stronger program going into 2016, but the level of capital spend will depend on market conditions.

Yes, fair.

My second question relates to locations [I'm assuming] also a large uptick in locations in Delaware and Midland and particularly in development-ready locations.

It sounds like a model change there that you discussed, but can you give us maybe any sort of color on that change and how is that change continuing to evolve throughout the year?

Are there drivers for additional scope change, given the pretty significant jump there?

Yes, what is happening is our teams have become so efficient in a number of areas.

So we are not just getting good with drilling, and the drilling has been the part of our performance that we have highlighted a lot.

So drilling performance is significantly improving, and it is improving because of the modeling work that our teams are doing, in addition to the execution in the field, so it's a combination of our planning, our design, and our guys in the field executing it very well.

In addition to that, though, we have an efficiency team that is driving how we do our business from the time that we go out, we decide to spud a well, to the time that we get it to sales.

Every segment of that we have worked on to try to improve our efficiency.

And that's gone really well, which has been a big part of the acceleration, in addition to the improvement in a per-well basis in terms of initial rates and performance.

The other thing that is helping us significantly is the business unit is working with our exploitation team to enhance what we understand about the reservoir now.

So our modeling work, especially our petrophysical, geomodeling, and our mapping, has enabled us to do a better job of selecting where to place the lateral part of the well, not only where to spot the well, but where to put the lateral section of the well, and also how to complete it.

And while we have seen significant improvements in our wells with the design changes we have made, we feel like there is still more improvements to be made and we are continuing to work it.

I think you mentioned that you are going to provide price sensitivity later in the year, but are these locations condition on a strip or any particular price level currently?

Well, in the slides you'll see that we have an inventory of our current well locations identified, and what it shows is the inventory that we can drill by price range.

But I want to point out here that this inventory -- it is on slide 25, I think -- but the inventory that is shown on that slide really is not updated for not only well performance, but it hasn't been updated for our current cost structure, so we will be updating that at the end of the year and you can use that as a guide to see the level of inventory that we have, based on what the oil price is.

And this is based on delivering returns that are greater than our cost of capital.

Very good, great.

I will leave it there.

Thanks.

Doug Leggate, Bank of America Merrill Lynch.

Vicki, I can't help but notice the absence of any meaningful commentary around the Middle East in the slide deck this quarter.

I guess following on from Evan's question, substantially greater opportunity perhaps in the Permian Basin.

As you think about the transition of the CEO role over the next year or so, how does your view of the Middle East as -- like in an area generally; obviously, there is a lot of large core assets, but there is also a lot of smaller non-core assets.

How do you think about your preparedness to invest in those kind of areas, the type of returns, the risk profile and so on, compared to the short-cycle, fairly well-known entity that you have right in your backyard?

In other words, is the Middle East back on the table as a potential rationalization story?

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

Well, we are looking at the Middle East basically as a group of what we consider core assets versus non-core assets.

And the assets that we consider to be really core to our business over there are the assets in Oman, the Al Hosn project, the Dolphin project.

Those are our cash flow generators.

So the steamflood in Mukhaizna is certainly one of the projects that is very important to us.

Some of the other assets in the Middle East, we are currently in Qatar.

That's been a good project for us.

That still has five years left on the contract there.

Some of the other assets are assets that, as we've mentioned before, are assets that are non-core to us, and given the opportunity, we would work to try to monetize or exit those.

I don't want to risk wasting my follow-up on this, but the Omani contract, obviously, is something that when you mentioned Oman, you mentioned the steamflood, but you have got other -- on your 35,000 miles or so a day of production there today in a contract.

Is that asset competitive?

Is it delivering free cash flow at this point?

Yes, this is Steve.

In other words -- go ahead, Steve.

She is new to the Middle East, so -- but she will answer next quarter.

The answer is yes, it is a free cash flow generator at this point.

Whether it is competitive or not is hard to measure, and so, as you know, what happens is you invest the capital and you get it back within the year, typically.

So while you show a lot of investment, you get back fairly quickly, and then some profit oil to go with it.

So it's an okay contract at this point.

But that's the same kind of financial characteristic that the Permian resources has, frankly.

Just look at it financially.

And so, the issue that Vicki will wrestle with over the next few months is whether it is competitive with -- continue to invest -- basically shifting that capital to resource business, which basically has the same kind of payout, time frame maybe a little longer in resources, but not much.

So, that's really what we are having to wrestle with, and we will look for a contract extension that is at least as good as what we could get a lot closer to home.

Okay, thanks for elaborating, Steve.

My follow-up is -- I guess it is one of the things that we periodically revisit and it's the dividend.

And obviously, you have got a big dividend commitment.

The stability of the underlying cash flow is a big, I guess, funding mechanism, CO2, chemicals, and so on, but if you shift your capital allocation, let's say, to the Permian, away from those long-life assets that you have in the Middle East, one could argue that the visibility on long-life cash flow to sustain that dividend growth starts to deteriorate a little bit.

So what I am really coming around to is how do you reset the dividend level such that you're able to maintain one of the anchors of Oxy legacy investment case, which is dividend growth?

And, of course, what I'm really getting at is, where is your head at, on the buyback?

Are you going to scale down the shares in order to reset that dividend commitment?

And I will leave it there, Steve, thanks.

Yes, I will answer that for now.

And we talk about this a lot.

It is not some new topic.

If we concentrate the Middle East on the few -- on the long-life projects, that will generate relatively more free cash flow.

In fact, if we stopped investing in the so-called non-core group, we would have more cash flow than we have now, so they are basically users of cash for either overhead or whatever.

And so, we think we can improve the cash flow out of the Middle East with that.

The CO2 businesses and the chemical business, the chemical business will finish the cracker here in a year or so.

The cash flow will improve there.

We think the dividend will be fairly easy to maintain.

However, it will require some shrinkage of the shares.

There is no question about that.

And so, one of our objectives over the next time frame would be to shrink the shares and therefore reduce the dividend, especially at the current prices where -- prices of the stock where the dividend yield is exceptionally high.

I appreciate the answer, Steve.

Thank you.

Ed Westlake, Credit Suisse.

Vicki, back onto the Permian, if I may.

So you have got this $6.2 million target for well costs.

I think that's what Evan was trying to get to, to see where that could get down to, what the limit you think is on that, and that I have got a follow-on about recoveries.

The $6.2 million is the target, but we feel like that we still have opportunities to lower beyond that.

We actually have achieved that with some of our wells, but we are just not achieving that on the average yet.

We're still seeing opportunities.

The teams are working on new ideas.

I think that there is a good possibility we could get below the $6.2 million, not only that target in the Delaware Basin, but our targets in the Midland Basin as well.

They are making some really good progress, doing some very good work modeling.

The other experiments that you spoke about on the last call, obviously making progress on landing zones, proppant intensity, and cluster spacing, all of these things the industry is using, and we are seeing some individual well results that you flagged out, for example in the Delaware on slide 30.

And the average is static, so I am wondering if there is a help you can give us in terms of where you think you could get to from these spot wells.

They could be sweet spots versus the average that you are delivering across the play.

Yes, what we are trying to do in the Delaware Basin, I think I mentioned before, is that the 3D seismic that we are acquiring, that would be something that could help us identify -- or, actually, it is the next step to high grade the locations that we drill.

So it's not -- as we have said before, it's not only about where you place the well within the interval, but where you drill the well, too.

And our basin modeling, which has recently been updated, that's another tool that we think is going to help us continue to move the average up a bit.

So we think that those two tools, the basin modeling where we have done a lot of geochem work and we have done -- upgraded our petrophysical models; the 3D seismic now, we're in the process of acquiring that.

We should be able to have that processed and begin interpretation by the end of the year, so that should help to impact the 2016 program.

Okay, thanks very much.

Leo Mariani, RBC.

Just a question around Al Hosn here.

I think you guys previously had a target of 60,000 barrels a day to eventually hit.

Do you think that target is still realistic and is that something we might get to in 2016?

The answer is yes; it's realistic.

They could, in theory, do better than that.

It is running, if you look at the numbers, more liquids rich than we had originally forecasted and we see that continuing, so you're going to wind up with probably more liquids, I think.

I think you'll -- with a little luck, we will get to it by year-end, but if not, certainly by the first quarter.

Okay, that's helpful.

And I guess just with respect to your comments around CapEx, obviously guys are seeing CapEx move lower here in the second half of 2015.

I know you guys previously had said that you might underspend the 2015 budget of the $5.8 billion.

Is that still possible here, because I know it sounds like you guys maybe have slightly higher Permian drilling activity?

Just trying to get a sense of where that spend may go and (multiple speakers)

I think the driver isn't the Permian.

The Permian is well managed.

The question is the part that is not really in our control, which is some of the Middle East stuff.

And again, I think if we -- effectively, if you put -- it is not totally in our control because you have the issue with the foreign governments, so if we spend a little more or a little less, that really just reflect -- effect the number of barrels we will get back within six months.

So, that's about the only thing about the capital that I think is -- what's within our control would be lower effectively than that, but there is a part of it that is really not in our control.

Okay, that's helpful.

And I guess just to be clear on your intentions for next year, if prices stay low at $50.

You guys have these 12 rigs in the Permian.

Is that likely to stay at 12 or potentially could you cut it back further next year?

Well, it just depends on what the price is.

12 is, I think, a reasonable guess for now, but we would -- even in a more stable price environment, we would have a hard time at this point of the year in making a sensible outlook for next year.

We could make one up, but I think it is hard to make a sensible outlook for next year.

Even now with the volatility of the prices, we are loath to say exactly what we are going to do.

The intention is that we would like to be -- I think we can make fairly straightforwardly make cash flow neutrality in a $60 environment.

The question is can we make it in a $55 environment and I just don't know that yet, but we are certainly going to try.

Okay, so it sounds like cash flow neutrality would be the overarching theme for next year?

You can't just run for the rest of your life outspending your cash flow.

You can do it for a year or maybe two years, but that can't be a business model for any ongoing enterprise, although, obviously, there are companies that have been doing it for decades.

Okay, thanks, Steve.

Ryan Todd, Deutsche Bank.

Good morning.

Maybe if I could start in the Permian as well.

The addition to the well inventory was great to see, and I realize some of that is on the modeling side, but can you talk maybe a little bit of -- it looked like there were additions across a variety of zones.

With the new models and as you continue to drill, is there any zone in particular where you're seeing particularly strong improvements or where your view may be changing at all in the basin?

I would say that our view changed a little bit in the Midland Basin where we thought at the beginning of the year that the Spraberry would be the best interval for us in the Midland, but now we are seeing the Wolfcamp A in both the Merchant area and the Big Spring area is looking very, very good.

So that was a positive sign for us.

So we have now three intervals -- the Wolfcamp A, Wolfcamp B, and Spraberry -- that are economical to develop in the Midland Basin, and in the Delaware, what we are doing there is we're trying to stay very focused this year on developing what we plan to develop so that we have the infrastructure in place and that we maximize the use of that infrastructure as quickly as we can before we move onto other intervals in other areas.

But one of the things -- two of the things that we are seeing is that the third Bone Spring and the Avalon are actually starting to look very good for us around our acreage, and so we are modeling that now, and actually we will certainly, we think, unless we just have significant improvements in some other intervals, both of those intervals will be a part of our 2016 development program.

That's great.

Are you still increasing lateral lengths in either basin or where are you on that front at this point?

Yes, actually in the Midland Basin, what we are doing there is we have drilled anywhere from 4,500 feet up to 10,000 in the Delaware Basin and our current average there is about 6,800.

But we are trying to, where we can, target drilling 7,000 to 7,500 in the Midland Basin.

In the Delaware, we have drilled up to about 7,850, and actually our average in the Delaware Basin probably is around 4,500 there.

We're expecting to, in that basin, have a minimum of 4,500 going forward in the future and would like to drill maybe in the 5,000 to 5,500 range.

Okay, great.

And maybe if I could ask one on the overall US portfolio.

You discussed a little bit your views on the Middle East up to this point, but where do you stand at this point on portfolio, on the state of the US portfolio?

The dust has settled a bit on some of your 2014 activity.

Are there still assets that you would view as non-core at this point that you could potentially look to market?

The assets that we consider non-core in the US are still Williston and Piceance.

We have a South Texas asset that when liquids prices are good, it is a great project, and actually, we have a lot of work that we could do at South Texas.

The team down there has worked up a lot of potential workovers.

We have a lot of drilling prospects on our South Texas acreage.

So I am going to use this opportunity to say that even though we're not investing growth capital dollars in any of those three assets, those teams have done an incredible job to manage their base production and optimize it.

And they are optimizing it with minimal expense of any kind.

They're doing a tremendous job.

So we still consider there to be a lot of potential in South Texas.

Williston, we simply want to monetize because of the fact that we don't have a lot of running room there.

We started some larger completions at the end of last year in the Williston Basin that really showed significant improvement in our well productivity there, but because of our running room, because of the differential in the Williston, it just can't compete with our Permian Basin assets and we don't think it ever will, so we do want to monetize it, along with the Piceance.

Thank you.

I will leave it there.

Paul Sankey, Wolfe Research.

Could I just jump back to the cash flow neutrality debate?

What would the volume outlook be in that situation, Steve?

Are we just talking about staying flat or some sort of growth?

There would be growth in the volumes.

I mean, the reason we are investing is to grow the cash flow, so, yes, the volume -- it isn't going to be a flat volume situation.

We have our own outlooks for the end of the year on what the fourth-quarter production will look like, volumes, and the same thing with some view into the first quarter of next year.

So I think, generally speaking, it isn't just what we have, but also what we see.

But I think also, I think the capital -- the cracker expenditures will fall next year.

Some of the midstream expenditures will fall, so the amount of capital which doesn't add to volumes will decline next year.

So I think by the time we get through, I think we're fairly close to where we need to be.

We generated cash from operations in this past quarter, about $1.5 billion before working capital changes, so you're talking about a $6 billion sort of run rate.

Our capital spending will be well -- next year would be well below the current $5.8 billion number, so it is pretty much in sight if we get a little improvement in chemicals and a few more dollars, really, an oil price.

What has really held us back more than anything is probably NGL pricing.

We weren't as negative as it turned out to be, so that's another area where I think we have been -- we have been more disappointed, frankly, in NGL pricing than we have the oil pricing, which is very similar to our outlook.

Sure.

You said that you're struggling to think about cash flow neutrality at $55.

I am not clear why that would be so much more difficult than thinking about it at $60.

It is another $500 million.

Yes, okay.

So you just got to -- and I guess, ultimately, you've said many times that you're going to -- you need to grow production if you're going to grow the dividend, basically, right?

I need to grow production if I want to grow the dividend and I need to grow production if I am going to attract or Vicki is going to attract the kind of employees she would like to have.

I think a stagnant business generates a stagnant workforce.

The alternate would be, I guess, just to sell Oxy if you can't make it, right?

I think that you can ask her about that next quarter.

(laughter)

All right.

Thanks a lot.

John Herrlin, Societe Generale.

Given all the efficiency savings you are getting in the US in the Permian on drilling and completion and all that, do you have a sense of where you think your DD&A rates will go to on a normalized basis?

I think our DD&A rates are -- you're talking about for the Permian resources business in particular?

Yes.

We're certainly headed toward DD&A of less than 15 and that's with -- that depends -- in terms of where it eventually lands, it depends on our infrastructure and how we can optimize that.

Thus far, we have done a really good job of building water handling infrastructure and gas processing, gas to sales gathering systems, so as we continue to optimize that, part of the reason that we are developing the way we are is to ensure that over time we can develop our reserves and minimize the facilities costs.

So we are trying to spend the bulk of our dollars on getting the reserves out of the ground.

Ultimately, we are putting together these life-of-field depletion plans, which help us to do that, and our target is to always make sure that our development of any particular area is with less than 10% of the capital spent on facilities and infrastructure.

Yes, as we look at DD&A, just to give you an accounting sort of answer, as you look to DD&A you have got the historical cost when oil was $100 that are built up in there.

We're adding it basically well below $15 currently.

And so the finding cost currently, the incremental finding cost, is quite low.

And so, it just will take a while to roll through the old stuff, so it's probably going to take a couple of years or something to get the bulk of it at -- the bulk of the adds at the low F&D.

So I think what you will -- putting aside product price changes, you will see a decline in the real finding costs over time.

Great, yes, I was just wondering about the timing of it (multiple speakers)

It just depends on how fast you DD&A the historic cost, because that is what is holding it back.

Okay, great.

Next one for me is on Howard County.

You said you had some very good performers there, and it's newly acquired properties.

Is that something that you would accelerate or it is just part of the program?

Actually, we're trying to stay disciplined in terms of how much we accelerate, so we will do more drilling there.

We do have drilling planned there.

It will be at a moderate pace through this year, because we have other areas that are pretty good as well.

If we see over time that on a consistent basis that is tremendously higher than anything else we have in the Permian Basin -- in the Midland Basin, we will certainly go over and try to accelerate that, but with minimal incremental cost.

Great, thank you.

[Scott Portillo], TPH.

Just a quick question on the Permian.

I wanted to follow up in regards to the inventory update.

I was curious as we think about both the Wolfcamp A and the Wolfcamp B, what are some of the underlying assumptions from a downspacing perspective, and if you were testing any further down spacing in regards to stacked/staggered development in the play?

In the Wolfcamp A and the Wolfcamp B, we are being very careful not to downspace too much, so we have some pilots in place and we have some reservoir modeling ongoing to ensure that we are spacing those wells appropriately.

We are not going to drill wells where we have interference issues, so we are trying to maximize the reserves we get on a per-well basis.

So, downspacing is not something that we built into our program.

However, the staggered completions between the Wolfcamp A and B is something that certainly we're going to do to ensure that we are -- there is no risk of communication between a Wolfcamp A and a Wolfcamp B well.

Great, and just a follow-up to both the inventory update in the Wolfcamp B and then just potentially some color around well performance.

You have provided a lot of detail in the past on the Wolfcamp A 30-day rates and I think you had mentioned a type curve of up to 900,000 MBOE for your short laterals.

I was curious how the Wolfcamp B wells look in comparison to that.

And as we think about the inventory added from 650 to 800, was that based on delineation of additional wells on your acreage in the basin?

Yes, the incremental wells was additional delineation.

And the Wolfcamp B with respect to the Wolfcamp A, while it is -- the Wolfcamp B is prospective and delivers some better than cost of capital returns, it is not as prolific as the Wolfcamp A in either the Midland Basin or the Delaware.

However, we think there are opportunities to continue to improve the recovery from the Wolfcamp A, where we are doing, as I said, on each of our target intervals more modeling to try to get to the point where we can optimize the Wolfcamp B.

Thank you very much.

Brian Singer, Goldman Sachs.

If we look at -- on slides 29 and 32, you highlight your focused acreage in the context of your broader large Permian position.

Can you update us on strategically your plan for the acreage within the Delaware and Midland that are not in the focused acreage, either to delineate, to sell, or to hold, whether those priorities change in a low oil environment, and then also your level of interest and realistic opportunity to expand your acreage positions in the Permian proximate to your focused acreage?

So we have no intention not to -- we have no intention to sell any of our acreage that is designated non-focused right now.

The difference between our focused areas and not is the fact that our focused areas are those that we feel like we could put in development mode today or are in development mode today.

The ones that are not considered focused right now are the ones that are still in appraisal mode and we consider those areas to be prospective, but in the interest of trying to ensure that the infrastructure dollars that we spend are used and we get the benefit of that quicker, we are being pretty disciplined about where we spend and how we develop.

So, the non-focused areas are ones that we are preparing for development in the future.

We, at this point today, don't have any acreage that we would consider for sale today.

We have some acreage that falls way down to the priority list and are things that we would get to years and years from now, so that at some point we might take a look at do we try to trade that to move into areas where it better fits where we are currently operating?

And in terms of continuing to appraise, we still have the Central Basin Platform where we haven't been drilling as of yet any -- or many unconventionals.

I think we have a couple drilled, but we still have that to assess.

So the good thing is that we have a tremendous inventory.

The challenge for that is we are at -- we're always looking at ways to try to accelerate, but to do it in a way that is not value destructive.

And so, we are trying to moderate our pace and trying to ensure that we have things fully evaluated before we move to development.

Great, thanks.

And my follow-up is on the midstream marketing business.

Can you just talk to what you all see as the ongoing cash generation potential there, and then how you are thinking about that business strategically?

Yes, I think that it is somewhat heavy and basically it is supportive of the Permian business.

That is really what it does.

And they're still really spending more money than they are taking in because they continue to build out to support the production business.

It doesn't make any sense to us, given our financial position, to do anything to increase the fixed charges against the midstream -- against the rest of the business by selling debt-like instruments called MLP units that go against it and increase our fixed charges.

A lot of fixed charges are okay at $100 well, but not so much fun in a $50 environment, and I think that people miss that, just like interest.

So I think on the cash flow generation, right now it basically is neutral to maybe slightly negative as they continue to build out either gas plants or pipelines.

At some point, I think it will probably generate $400 million or $500 million a year in cash flow, free cash flow, but I think we are probably a year or two from that.

Great, thank you very much.

This concludes today's question-and-answer session.

I would like to turn the conference back over to Mr. Degner for any closing remarks.

Thank you, everyone, for joining our call today and I know it's a busy season.

Thanks.

The conference is now concluded.

Thank you for attending today's presentation.

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