西方石油 (OXY) 2015 Q3 法說會逐字稿

Good morning and welcome to the Occidental Petroleum Corporation third-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 third-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; Sandy Lowe, Executive Vice President and President of OXY Oil & 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 third-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 our website at www.OXY.com.

I will now turn the call over to Vicki Hollub.

Vick, please go ahead.

Thank you, Chris.

Good morning, everyone.

Despite the current environment of low and volatile product prices, our oil and gas segment has been operating well in all of our core assets.

Our third-quarter average daily production increased to 689,000 BOE per day from last year's 595,000 BOE per day, an increase of 16%.

Our core assets continue to drive production growth with an increase of 39,000 BOE per day from Permian Resources and 50,000 BOE per day from Al Hosn, which reached full capacity in September.

We expect Al Hosn to produce 60,000 BOE per day in the fourth quarter.

Our capital and operating costs have continued to decline as we've focused our development program and curtailed activity where current product prices did not support further investment.

We continue to make progress to optimize our portfolio as a part of the Company's strategic review to focus on our core assets in the Permian Basin and the Middle East.

We're selling our asset to the Williston Basin and continue to evaluate our positions in non-core assets in the Middle East with the objective of minimizing our activity and exposure.

Construction of the ethylene cracker has progressed well and is on schedule to start up in early 2017.

Our principal goal this year is to adjust our business to the current environment of low commodity prices.

We are targeting our operating cash flow to cover our dividend and capital investment at realized oil prices of $60 per barrel, while continuing to grow our production.

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

While we don't believe current price levels are sustainable over the long term, we've taken aggressive actions to manage the business for a downturn that may last longer than market participants expect.

During the boom period from 2010 to 2014, the industry experienced substantial cost inflation.

Royalties and government takes on new projects increased.

Service prices, labor cost, and overhead all increased as well.

There is ample room for us to continue to lower our costs, which will enable us to return the business to profitability at lower prices.

These adjustments may be difficult the short term, but our discipline on reducing costs will lead to a healthier business over the long term.

Through our separation of California Resources in 2014, we reduced our annual G&A budget from $1.8 billion to $1.5 billion as we moved the corporate headquarters to Houston.

Over the course of this year and into 2016, we expect to see continued reductions in our corporate overhead with a more focused company that will reduce our total G&A spending to about $1.2 billion in 2016.

Two years ago we began working on strategic initiatives to focus our company and improve its profitability.

We have continued to make progress on those initiatives.

We reached an agreement to divest our Williston Basin assets and expect the transaction to close in the fourth quarter.

Due to our curtailed spending in the basin and the nature of unconventional assets, our production declined about 25% quarter over quarter when annualized.

We expected the production to continue to decline given our limited capital investments in the basin.

Over the past several years, our efforts at appraising and delineating our acreage in the Permian have provided a large inventory of future development locations that are economic at oil prices under $60 a barrel.

With ample take-away capacity and an extensive midstream business of gathering lines, storage and gas processing, our economies of scale and deep inventory in the Permian Basin make it our top priority for capital allocation for the foreseeable future.

Simply put, acreage in North Dakota, whether it's Tier 1, 2, or 3, cannot compete with our position in the Permian.

We continue to pursue strategies to minimize our activities and exposure in our non-core operations in the Middle East and North Africa, which include Bahrain, Iraq, Libya, and Yemen.

As a result of these actions, we took impairment charges in the third quarter for our positions in Iraq and Libya.

We will comply with our contract terms as we reduce our exposure through negotiations with our partners and host governments, and expect capital investments to decline in 2016.

These actions will improve the profitability and cash flow of our Middle East business as we focus on our core assets in Abu Dhabi, Qatar, and Oman.

Our capital spending in the third quarter declined by about $300 million and will continue to decline.

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

We expect to exit this year at a quarterly spending rate of $1.1 billion to $1.2 billion.

If product prices remain at current levels, our 2016 capital program will be less than the current rate.

We're in the midst of our annual budgeting process and will provide more detailed guidance on our 2016 program in January.

Over the last few years we've undertaken multiple long-term investments to drive cash flow and earnings growth.

These projects include the Al Hosn gas project, the ethylene cracker joint venture, our export facilities in Ingleside, and gas processing infrastructure in the Permian Basin.

Capital spending on these investments declined by about $500 million in 2015.

We expect these investments to decline by about $300 million in 2016 and $400 million in 2017 as the project are completed.

This decline in capital spending on committed projects gives us a lot of flexibility in setting our capital budget for 2016.

Our Permian business continues to execute a focused development program on low-cost wells with high oil content.

Permian Resources continues to drive down capital cost through improved execution drilling and well completions.

Our production exceeded expectations due to reduce time to market and better-than-planned well performance.

In the third quarter, Permian Resources achieved daily production of 116,000 BOE per day, a 6% increase from the second quarter and a 51% increase versus the prior year.

Oil production increased to 74,000 barrels per day, a 4% increase from the previous quarter and a 72% increase from a year ago.

In the fourth quarter, we will drill and complete about 50 horizontal wells.

We are currently operating 12 rigs in the basin and evaluating our needs for our 2016 program.

In the Delaware Basin, our Wolfcamp A 4,500-foot well costs decreased by about 45% from the 2014 cost of $10.9 million to a current cost of $6.3 million.

We reduced our drilling time by 24 days from the 2014 average of 43 days to 19 days.

We've lowered our completion cost per well and optimized the density of our clusters and profit loads.

We've used some of our cost savings to upsize our frac treatments to drive higher productivity.

Our well performance continues to be strong.

We placed 21 wells -- horizontal wells on production in the Wolfcamp A benches in the third quarter.

The leased [840-11H] well achieved a peak rate of 1,790 BOE per day and a 30-day rate of 1,528 BOE per day.

Additionally, our Betty Lou 1013H well achieved a peak rate of 1,711 BOE per day and a 30-day rate of 1,310 BOE per day.

We drilled the Betty Lou horizontal well in only 15 days.

Both of these wells produce around 80% oil.

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

We reduced the cost of these 7,500-foot horizontal wells by 30% from the 2014 cost of $9.2 million to a current cost of $6.6 million.

We reduced our drilling days by more than 60% from 46 days in 2014 to 18 in the third quarter.

In Big Spring, which is our new area of the Midland Basin, we brought the Young A 2124 well online in the third quarter at a peak rate of 1,611 BOE per day and 30-day rate of 1,237 BOE per day.

We also brought online the Adams 4201 well at a peak of 1,698 BOE per day and 30-day rate of 1,495 BOE per day.

Both wells are producing at about 90% oil.

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

We're continuing to lower our cost structure.

Since the fourth quarter of 2014 we have reduced our operating cost per barrel by 18% and expect to make further progress in lowering our costs through the end of this year and into 2016.

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

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

In the third quarter we started Phase 1 of the CO2 injection at South Hobbs, where we expect to develop low-cost oil production at about $10.60 per BOE.

In closing, we delivered strong production growth from our core assets in the third quarter.

We continued to execute on our strategic initiatives to focus our oil and gas business around our core assets in the Permian basin and the Middle East.

We'll continue to execute a focused development strategy in 2015 and we will pursue additional step changes in well productivity and cost structure.

Strong production growth from our Permian Resources business, along with a 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 businesses.

Now I will turn the call over to Chris Stavros.

Thanks, Vicki, and good morning, everyone.

Today I will cover our third-quarter results, discuss the actions we've taken related to the non-core charges we took in the quarter, and close by providing some guidance on the remainder of the year while highlighting key initiatives that will improve the Company's financial strength going forward.

We generated core income of $24 million for the third quarter of 2015, resulting in diluted earnings per share of $0.03, a decrease from $0.21 a share in the second quarter of 2015 and compares to earnings of $1.34 per share in the third quarter of last year.

Our net GAAP reported results for the third quarter were a loss of $2.6 billion, or $3.42 per diluted share.

Our third-quarter reported results includes non-cash after-tax net charges of approximately $2.6 billion.

Our quarterly core results were negatively impacted by lower worldwide oil and NGL prices, which fell by nearly $7 and $3.50 a barrel, respectively, in the third quarter of 2015 compared to the second quarter of this year.

US natural gas prices improved slightly, up about $0.15 per MCF from the second quarter.

Our third-quarter capital spending was about $1.2 billion, down 18% from the $1.5 billion in the second quarter and down 30% from first-quarter levels.

We continued to ramp down our capital program focusing our development activity primarily in the core areas of the Permian Basin with the intent of curtailing or eliminating spending which is less competitive and imprudent in the current product price environment.

Our heightened focus around capital spending is centered on growing our oil production volumes and, more importantly, our operating cash flow.

Despite the reduction in this year's capital program, efficiency gains and our increased focus around our inventory of drilling opportunities continues to drive growth in oil volumes and cash flow at our Permian Resources operations.

Permian Resources grew its oil production 72% in the third quarter, adding 31,000 barrels per day compared to a year-ago period, with total production of 116,000 BOE per day representing growth of 51%.

Production from Permian Resources improved by 7,000 BOE per day sequentially above our previous guidance.

As I mentioned earlier, we took after-tax impairment and other non-cash charges of approximately $2.6 billion in the third quarter.

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 price curve.

As of September 30, the futures curve for product prices had declined sharply yet again and we recorded an after-tax impairment of $1.3 billion related to our domestic gas properties at our oil and gas assets in Libya.

As Vicki mentioned, we continued to make progress in our efforts to optimize our portfolio.

In the third quarter of 2015, we entered into an agreement to sell our Williston operations, which have been classified as held-for-sale, and resulted in an after-tax impairment charge of approximately $500 million.

The sale is expected to close later this quarter and we expect to receive net proceeds equivalent to approximately 8 times free cash flow after required capital for facilities and safety.

Additionally, and as part of our effort to focus our capital on opportunities that generate higher financial returns, we intend to minimize our capital allocated to non-core areas.

As a result, we recorded an after-tax non-cash charge of $760 million for our operations in Iraq.

We expect to continue oil liftings out of country in the fourth quarter.

Our exit from these non-core areas will create a more focused domestic oil and gas organization and mitigate our exposure to areas we deem as having higher political risk.

In addition, we expect our capital spending levels to decline and our financial returns to improve as we generate savings from associated overhead reductions that have yet to be captured.

As slide 21 shows, for the first nine months of 2015, our operations in combined Williston, Iraq, and Libya had total production of 45,000 BOE per day and generated an aggregate cash flow, after capital deficit, of approximately $260 million with Brent oil prices of about $56 a barrel.

For the full year of 2014, when Brett prices averaged about $100 a barrel, these assets had an even greater cash flow after capital deficit of $340 million.

Some of this free cash flow savings could be redirected to our higher-return core operations in the Permian Basin.

Turning to specific business segments.

Oil and gas after-tax earnings for the third quarter 2015 were $17 million, about $90 million lower than the second quarter of 2015 and $880 million lower than last year's third quarter.

Almost all of the impact of the change in year-over-year earnings is due to lower product prices.

For the third quarter, total company oil and gas production volumes averaged 689,000 BOE per day, an increase of 31,000 BOE in daily production from the second quarter and 94,000 BOE per day from last year's third quarter.

Total company oil volumes were 436,000 barrels per day in the third quarter, 54,000 barrels per day higher than the year-ago period for an increase of 14%.

Total domestic oil and gas production averaged 332,000 BOE per day during the third quarter of 2015, about flat sequentially and 17,000 BOE higher on a year-over-year basis with all of the increase coming from Permian Resources.

The increase from Permian Resources was partially offset by lower production from our Mid-Continent natural gas assets where we have cease drilling activity.

Domestic oil production was 204,000 barrels per day during the third quarter of 2015, about flat with the second quarter and up 22,000 barrels per day, or 12%, from the year-ago period.

We captured approximately 4,000 BOE per day of incremental NGLs and natural gas volumes in the third quarter due to the installation of compressors and gathering lines in the Delaware Basin.

International oil and gas production volumes averaged 357,000 BOE per day during the third quarter, up 32,000 BOE per day sequentially and 77,000 BOE per day on a year-over-year basis.

Production from Al Hosn was 50,000 BOE per day in the third quarter, an increase of 32,000 BOE per day from the second quarter and about 15,000 BOE per day above our guidance for the period.

Al Hosn is currently running at full capacity, which is approximately 60,000 BOE per day.

Our third-quarter oil and gas cash operating costs of $11.15 per BOE declined 8% from the second-quarter level of $12.10 per BOE due to higher production volumes, lower surface and down-hole maintenance costs, and lower energy costs.

DD&A for the third quarter was $15.39 per BOE compared to $16.06 per BOE during the second quarter.

Taxes other than on income, which are directly related to product prices, were $1.20 per BOE for the third quarter compared $1.85 for the second quarter and $2.45 per BOE for the full year of 2014.

Chemicals generated pretax core earnings of $174 million in the third quarter of 2015 versus $136 million in the second quarter and $140 million during the year-ago period.

The most recent quarter results were above our previous guidance and benefited from higher chlorovinyl production volumes, lower ethylene costs partially offset by lower vinyl sales prices.

Midstream pretax core earnings were $31 million in the third quarter compared to $84 million in the second quarter of 2015 and $115 million for last year's third quarter.

The most recent quarter results reflected lower marketing margins due to the narrowing of Midland and Gulf Coast differentials and an increase in crude oil supply lowered premiums in the Gulf coast.

The lower marketing margins were partially offset by higher pipeline income from both domestic and foreign pipelines and higher seasonal margins from power generation operations.

Turning to our cash flow, operating cash flow for the third quarter of 2015 was approximately $1 billion, which was about $200 million higher than the second quarter.

Higher oil and gas production volumes combined with better realized oil prices relative to benchmark prices positively impacted our operating cash flows during the third quarter.

Working capital changes were minor during the third quarter as our drilling activity and capital spending stabilized from higher levels at the end of last year.

We continue to ramp down our capital spending with total compete expenditures for the third quarter of 2015 of $1.2 billion, a sequential decline of $300 million from the second quarter.

Total company capital expenditures for the first nine months of 2015 were $4.4 billion, which is running a little lower than our full-year 2015 capital budget of $5.8 billion.

Oil and gas spent $3.6 billion during the first nine months of 2015 with Permian Resources expenditures comprising roughly half of the total oil and gas outlays and the remaining $800 million of capital split nearly evenly between Chemicals and Midstream.

We paid cash dividends of $1.7 billion during the first nine months of 2015.

Continued growth in our operating cash flow, combined with capital reductions and other cast cost savings, should allow us to achieve our goal of being cash flow neutral after capital spending and dividends at oil prices of roughly $60 a barrel.

Our cash balance at the end of the third quarter was $4.3 billion and our long-term debt-to-capitalization ratio was 19% at the end of the period.

The worldwide effective tax rate on our core income was 90% for the third quarter of 2015.

Beyond the efficiency improvements that have lowered our capital spending, we've also started to recognize the benefit of a reduction in our SG&A costs.

Reducing our SG&A is an initiative we began working on ahead the spinoff of our California assets and operations.

Prior to the spin, our SG&A was approximately $1.8 billion per year.

Upon completion of the spinoff late last year, we had reduced our SG&A costs by about $300 million or roughly 17%.

While our workforce has come together and made a huge effort to reduce costs, we are still in the early stages of recognizing these benefits.

During 2015 we expect to reduce our SG&A by another 10%, or roughly $150 million.

We have taken a number of actions and will continue to pursue other initiatives that will serve to reduce our SG&A costs, both this year and next, and is highlighted on slide 30.

We expect these initiatives to reduce our SG&A by at least another 10% and expect our total SG&A costs to decline to roughly $1.2 billion in 2016.

This represents a one-third reduction in our total SG&A costs compared to levels before the California spend.

Looking ahead to the fourth quarter, domestically we expect production from Permian Resources to be about 118,000 BOE per day.

Production has been a bit lumpier as we have increasingly moved to pad drilling and we expect total Permian Resources production to exit the year in excess of 120,000 BOE per day.

Continued growth in the Permian, combined with declines in our Mid-Continent natural gas production and adjusting for the sale of the Williston assets, should result in total US production between 310,000 and 320,000 BOE per day.

We expect our international production to be between 365,000 and 375,000 BOE per day, depending on volumes from Iraq, and assume 60,000 BOE per day of production from Al Hosn.

Price changes at current global prices affect our quarterly earnings before income taxes by $30 million for $1 per barrel change in oil prices and $7 million per $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 fourth-quarter 2015 exploration expense is anticipated to be about $20 million pretax.

We expect our fourth-quarter 2015 pretax chemical earnings to be about $130 million.

Our third-quarter midstream earnings will continue to be principally impacted by Midland to Gulf Coast oil price differentials, which have narrowed since the third quarter, as well as weak NGL prices.

We expect net cash proceeds from asset sales in the fourth quarter, which includes our assets in the Williston Basin, to be approximately $650 million.

The worldwide effective tax rate on our core income was 90% for the third quarter of 2015.

This rate reflects a mix of domestic-sourced book losses and foreign-sourced income, which is taxed at much higher relative rates.

Simply put, it cannot utilize US tax losses to offset the higher foreign taxes.

Based on continued volatility in the mix of pretax income sources, we expect our full-year 2015 domestic tax rate to be 36% and our international tax rates to remain at about 65%.

To summarize, as we wind down the year, we remain financially strong and well positioned to weather the current low product price environment with $4.3 billion of cash on hand, roughly equal to our annualized capital outlays.

We continue to grow our production volumes cost efficiently and despite the decline in capital spending.

We will continue our disciplined approach towards cost control and improving our capital efficiency, focusing and allocating our capital on only the highest-return opportunities.

Our capital spending run rate has been cut by more than half compared to year-ago levels and we expect to save at least $300 million as a result of initiatives to lower our SG&A costs.

I'll now hand the call back over to Chris Degner.

Thank you, Chris.

Emily, can you please open up the line for questions?

(Operator Instructions) Evan Calio, Morgan Stanley.

Good morning, guys.

Your Permian Resources production, again beat guidance.

You're making progress on cost efficiencies and you highlighted it as your top priority in your slides, but it's also one of the pieces in your portfolio where you can dial activity up and down.

Can you talk about how you balance those factors when you are considering your 2016 Permian activity levels in the current environment?

Yes, Evan.

As Chris said, our committed capital is coming down, but we still do have some committed capital in 2016.

So what we will do is balance our Permian Resources business with the capital requirements elsewhere.

As you know, we are trying to reduce our capital requirements in the Middle East.

And the reason for that is we would prefer to divert -- to move capital to Permian Resources, but we do have the ability to swing it up and down.

We are working on several scenarios that we could be ready to implement, depending on what market prices are in 2016.

Maybe a follow-up there.

When you mention the potential mean and encore asset sales, does that imply that the larger interest sell down remains backburnered?

And on your G&A guidance, does that -- that these announced assets are sold as well?

You're talking about the Middle East?

Yes, and MENA, sorry.

Currently, we're looking at certainly exiting some of the non-core properties in the Middle East and ramping down activities in some of those areas that we are not going to exit.

So that will certainly impact some of our SG&A cost.

We expect those to go down, as well as some of our operating cost.

So that will be a benefit to us.

Getting back to the Resources question that you had previously, we do expect to, in all of the scenarios that we are looking at, to continue to grow production from our Permian Resources business.

This is Steve.

The answer to your question is no, we really haven't baked in the Middle East situation with the decline.

So basically what we see now is this is what we have said for next year's run rate or cost.

We expect to continue to work on this as the portfolio changes.

Right, and the non-core -- but by focusing on the non-core sales in MENA, I guess I was saying does that also imply that the larger interest sell down in that piece of the portfolio remains backburnered, given the current environment?

Is that fair?

The countries have gone from being flush with cash to being cash users, just to fund their own situation.

So it's not likely that they are in the mood to -- basically they are selling things; they're not buying things right now.

Right.

And then I guess one more question, Steve.

Can you discuss what drove the Bakken asset sales given your ample liquidity position?

Is there a general comment there on your view of prices in the asset market that you see better opportunities to sell versus buy, where you've highlighted the two?

Do (multiple speakers) potentially be a buyer in the Permian?

We sold the Bakken assets for about $600 million, as opposed to the reported number, which I don't know where that came from.

Anyway, we sold for about $600 million.

We just can't see a situation where we would invest in it, given what we have in the Permian.

And so it's really a statement that says, okay, we just don't see how it competes for capital inside the Company in any reasonable price scenario that we can come up with.

We could generate -- it has always generated negative cash flow or at best neutral.

It's declining about 1,000 barrels a day a quarter, so a year from now it would be 13,000 or so a day, just doing the arithmetic.

So we don't see how the value increases over time.

For us, this $600 million, we could run four rigs in the Permian Basin for a year with this money, or five, somewhere in that range, and generate more production than we would get out of the Bakken with the $600 million box.

So a pretty easy decision to say, well, you can hold on till it goes up in price.

By the time it goes up in price you might be making 8,000 barrels a day, so I just don't know when it's going to go up.

We believe we received a fair price given the prospects for the -- for it under our management.

Great, I will leave it for somebody else.

Thanks.

Doug Leggate, Bank of America Merrill Lynch.

Thanks.

Good morning, everybody.

On the Middle East folks, the non-core areas that you're talking about, I'm trying to reconcile the $60 breakeven number with exiting some of these non-core areas.

I guess my question is: are these areas currently negative free cash flow?

And if so, could you quantify what you think the delta would be in the event of an exit and if that is already assumed in your $60 breakeven assumption?

$60 is just a cartoon.

This is basically based on our current situation.

The businesses are not cash flow positive.

Doug, we showed you on the slide that I pointed out, slide 21, that under various oil price scenarios, a higher oil price scenario of last year or lower prices this year, it was still running -- the combination of those assets are still running a sizable cash deficit after capital.

So you were -- you sort of had higher capital in a higher price environment, but still you weren't generating enough money to really see a free cash flow positive event.

We haven't gone back and recomputed what exactly the breakeven would be, so we don't really know whether it's $55 or $60.

Okay.

Maybe I could just slip in a macro question there.

What -- can you update us on what you are doing in Iraq currently?

Because obviously your partner -- our understanding is the Iraqis are asking folks to slow down investment, so what are you actually seeing on your asset?

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

Sandy can answer that, I think.

The Iraqis have asked us to slow down investment.

And the infrastructure investment that we need to really take advantage of these fields, that is the responsibility of the government, has not taken place, so the production is just trucking along at a fairly stable amount but not anything that would excite us.

Thanks.

My final one, if I may, again I want to go back to this $60 breakeven, Steve.

Because if you look at this current quarter, obviously you are still burning through a fair amount of cash and the oil price clearly is not $60.

It's substantially below that.

Although that's not our base case, what would you do in the event that you have another year of sub $50 oil?

Because that would imply you basically burned through all your cash at this rate.

I don't think we burn through all the cash.

We must -- maybe we have a different model.

But anyway, if you run through all the numbers, I think we would look at it at the time, but as we cut back on the non-core assets more cash will be generated, so you could have -- you could drill fewer wells in the Permian if that were necessary.

We're not counting on (multiple speakers).

You'd basically slow things down, right?

We would bring the capital down lower.

There's more savings as we go in this and so we're not exactly sure where we are in this process, so I think -- as we go through this next year the large -- the cracker basically ends at the end of this next year, the spending on that ends.

Some of the stuff in the midstream ends at the end of next year.

Al Hosn will be -- basically all the capital will be spent.

There is a little bit of capital in the beginning of the year for crew quarters, as I recall.

And so when all that ends the capital will naturally decline and the production goes up.

Whether it's $60 or $55, we don't really know right now, but we would expect as we going to 2017 clearly that the capital program would be significantly less than -- could be significantly less than next year even.

Got it.

I'll let someone else jump on.

Thanks, everybody.

Phil Gresh, JPMorgan.

Good morning.

First question just on the CapEx side.

How would you think about what sustaining capital requirements there are today given all the productivity that you have been seeing in the Permian?

How would that relate to the $60 breakeven for dividend coverage as you move forward?

I would assume that that's generally -- underlying you are seeing some improvement there, but any color you could provide would be helpful.

Phil, we are continuing to see improvements in the Permian Resources business, and as we have just said and said previously, our Resources business is our swing business with respect to capital.

We have the ability to ramp up and ramp down.

But we do see a scenario, if oil prices improve a little bit, for us to be able to continue to grow Resources and to manage some of the capital spend in international down so that we can be cash flow neutral and grow Resources slightly in 2016.

Part of that is due to the fact that we are continuing to see improvements in our drilling and completion operations.

If you look at the targets that -- if you go back and look at our Q1 targets for our drilling and completion activity in Permian Resources, we have actually adjusted our targets a couple of times because our teams keep outperforming and beating our previous targets and setting new best rates.

So currently two of the things that we are dealing with in terms of uncertainties is how much better can we get and also what will prices be.

So we're running both of those scenarios and we think we have opportunity to continue to improve.

Okay.

Follow-up question just on the Midstream business.

In this lower-for-longer type of environment, how would you think about the earnings power of that business?

I know it's volatile quarter to quarter, but if you think maybe on an annualized basis, and you obviously have a couple of different cell businesses within that.

But any thoughts you have there would be helpful.

It's a difficult business to estimate.

It's a hodgepodge of different businesses.

It's got a power business.

It's a standard transmission business.

It also has holds the capacity to ship oil out of the Permian and right now there's more excess capacity in the basin to ship oil because people assume that oil would -- the production would go up, and it's clearly not for the industry.

So we are paying demand charges essentially for that and that's what it eating into the profitability.

It's really a difficult number to quantify because you have to really have an idea about these demand charges and what's going to happen with that.

It has a probably underlying earning power in the $300 million or so area, but there's a lot of volatility on these demand charges.

Sure.

And is that $300 million including the benefits we will get from sulfur at Al Hosn?

Probably not.

Probably doesn't include it.

Okay.

Last question (multiple speakers).

Sulfur mill at Al Hosn is also -- makes predicting oil prices easy.

The price of sulfur can move $50 a ton overnight.

Sure, understood.

(multiple speakers)

It increases a lot of tons.

On the Middle East, you had a significant reduction in the cash operating cost in the third quarter.

Any color on the big drivers and the sustainability of that?

We've had a cost improvement program going for a long time and we have recently been able to make some breakthroughs on that with various vendors.

It's just focusing on it and same as in the Permian.

We, everybody in the Company, is focused on more profit per barrel, less cost per barrel.

But I think to be -- the way the accounting works in the Middle East on a production sharing contract, the Company always bears all of the cost, all of the operating cost.

So when oil prices are high, you get fewer barrels to cover that operating cost.

And lower oil prices you got a lot more barrels to cover the exact same operating costs, even if they don't change.

So that's -- it's a little (multiple speakers) different than comparing to the US or something like that, because you always have all of the -- 100% of the operating costs essentially there.

And so whether you produce 10,000 barrels a day or 20,000 net, operating cost is the same.

Great.

Okay, all right.

Thanks a lot.

Tim Rezvan, Sterne Agee CRT.

Good morning, folks.

First question I guess was on the US cash OpEx numbers that you reported in the third quarter, kind of flattish from 2Q.

I know that you have had some big improvements early in the year.

I guess you've talked qualitatively about bringing that down more, but maybe can you talk about what happened in the third quarter and kind of how we should think about the trajectory of that into 2016?

Yes, we've continued to improve our operating cost.

Basically we are focusing on the OpEx in Permian Resources and Permian EOR, because in Williston we had some high OpEx there just because of the fact that our production was lower.

But in the Permian what we are doing is we see the biggest opportunities in our Resources business where initially we had difficulty pumping from the deeper unconventional wells.

We were trying to use either ESPs or Bean pumps.

With both of those there were issues because the depth of those wells and the initial very high volumes that then becomes lower volume pretty quickly in the life of the well.

So now we've gotten to a point where we understand that better.

We're addressing that better.

We are actually ensuring that we installed a lift that's the right kind of lift for the full lifecycle of the well so that we don't have high initial repair costs.

So that's part of what's driving down our OpEx in the US.

And Permian EOR, those guys are continuing to optimize what they do with respect to well maintenance.

They have a lot more wells over there, so they have been able to reduce quarter over quarter the cost per barrel in the Permian -- in the EOR business by improving the well service rig performance and improving how they deal with replacement of pumps and things like that, the materials they use and what they are doing there to extend the life of the wells.

So we do expect continued improvements in both of those business units.

I think the short answer is that the Williston operating costs went up and it dragged the average up.

Okay, okay, appreciate that comprehensive answer.

Next question I guess on the repurchase program.

Your average shares outstanding were down $3.3 million.

You only spent $50 million in the third quarter, so I guess that is a factor the timing of your 2Q activities.

Should we expect in a $50 or sub $50 oil environment that you will run at a much lower pace on the repurchases?

Or I guess what's your philosophy on that?

If I had more confidence in the oil price, we would be more aggressive in the share repurchase.

At this point it depends on two things: it's a sort of calculation of what's in the stock, which is favorable to repurchase, and how fearful we are about the volatility in the oil price.

I think the fear overcame the calculation this past quarter.

We keep on reading those analyst reports so that generates enormous fear.

I appreciate that commentary.

Edward Westlake, Credit Suisse.

You clearly shouldn't read analyst reports.

Just read the headlines.

Okay, no worries.

Question on the Middle East.

You talk about ramping down activities, maybe in non-core asset sales.

Of the countries that you list there, Bahrain looks like one which might have a buyer in the sense of the production as opposed to those other countries.

Is that what you are talking about?

No.

Selling assets or just reducing activity?

Just reducing activity I think this is the way to say it.

There's a significant amount of -- what do you call them?

Receivables or whatever you want to call, where we produce the oil or gas but haven't been paid in some of these places.

And basically you are effectively building up a liability over time and basically we can't afford to do that currently and so we will reduce the activity till we can catch up with that accrual, if you will.

It doesn't show up on the balance sheet.

It's simply a difference between production and listings.

Then on Block 9 you said on the last call we will look for contract extension that is at least as good as we could get back in the Permian.

Any progress on how the other side of the table view that?

It's a difficult negotiation, I think is best way to describe it.

And ongoing?

And ongoing.

I think it will go on until -- all these things go on until there is no more time left.

And as reminder, just in terms of -- as we get down to end 2015, what the actual drop-dead date is or --?

It's in December.

Then just moving to the Midstream, the Ingleside cracker and the export facility for LPGs should be fairly profitable in terms of EBITDA and free cash flow when they're on stream.

So just an update as to when you'd sort of (multiple speakers).

Towards the end of next year.

Mid to -- second to third quarter as I recall.

Okay, good.

So CapEx comes down, cash flow goes up, and that helps balance.

And same thing when -- the cracker is the end of -- be done in the end of next year and the cash flow really in 2017.

Same sort of dynamic, except probably larger.

Okay, thanks very much.

Jason Gammel, Jefferies.

Thanks very much.

I was hoping to just get a little more understanding on that led to the write down in Iraq, because my understanding was that it was an acceptable place to invest because you never really had a lot of capital exposed.

And if you are reducing investment activity even more and you are still lifting oil, does that imply that you got into a situation of a big arrears with the government that you don't think you'll actually ever be able to get paid back?

There's clearly -- I really don't want to get into a discussion about the contract terms there, except to say that, in theory, you got your money back on a small profit pretty much as you spent the money, maybe a quarter or two off.

And that really -- that hasn't exactly happened.

Okay, I think that's a fair enough explanation.

I think I get what's going on there.

Now, at the risk of picking nits here, the Permian Resource production overall in the quarter obviously very good, but it did seem to be a little more swung towards NGLs in gas and away from oil than what I would have normally expected.

Vicki talked about moving to pad drilling and making it a more manufacturing process, which makes it more lumpy.

Is that the explanation for that or is there something else going on?

In addition to the pad drilling, we were able to capture some stranded gas in the last quarter and we were able to put that online and through processing.

And that's what drove some of that.

So should we still think about this as 5,000 barrels a day of oil growth out of Permian Resources on a move-forward basis, recognizing there could be variation from quarter to quarter?

There is going to be lumpy production so it could vary from quarter to quarter.

But in terms of the differential with the gas with respect to oil, this time -- again it was due to a one-time event to get some gas production on that we didn't previously have on.

As you reduce the capital, fewer rigs, the effect of this lumpiness is more obvious, because you got these rigs working in one place and if you have -- if you are in five places, well, it sort of averages out.

But as you reduce the number of rigs at work, the effect of the lumpiness from a quarter-to-quarter basis is a lot more obvious.

So you might expect some more -- you will be able to see it in a normal environment.

With a somewhat higher rig count, you wouldn't see it really; it would just smooth out.

Okay, that makes sense to me.

Okay, thanks very much, folks.

John Herrlin, Societe Generale.

Thanks.

With respect to the Permian Resources unit, are you doing --?

Can you describe what you are doing in terms of the well completions that are different, or are you doing anything materially different than your peer group?

On the well completions, we continue to try to find the exact mix of when to use slick water, when to use hybrid fluid systems, and also what the cluster spacing should be, what the volume of the profit should be.

So what we have done is we've experimented a little bit trying to ensure that we get all that optimized.

And some of that we have enough data that we can optimize it and we know what to do.

For example, in cluster spacing, we can take the pressures that we see during the frac jobs and kind of get to a point where we know what that should be for a given area.

So it's still really the proppant size and the fluid volumes and fluid types that we are experimenting with.

We did some experimentation with using some of the sleeves and things like that versus plug and perf.

And we found that while the sleeves are somewhat effective in being able to isolate and frac, they are not as good when we try to flow the wells back because the sleeves actually cause variations in the flow back which drops out proppant and causes cleanup issues later.

So we're moving more toward now ensuring that what we do is -- will have an optimal impact on not just recovery, but the life of the well.

I think it's just still experimenting with those things that others do.

We are waiting for our seismic.

We should be done acquiring that in the Barilla Draw area soon.

We will be pricing that and we hope that will lead to actual more improvements next year.

Great, thanks.

With your EOR operations at the Permian, at current prices how much free cash flow are you generating?

At current prices I can tell you -- I can give you what we were generating.

We were generating a couple billion dollars when prices were in the $90 environment.

Probably about --.

Probably cash margins of about $20 a barrel or so.

Okay, that's great.

Last one for me.

You took a big impairment on gas; did you really kitchen sink it in terms of pricing?

We hope so.

Okay.

Thanks, Steve.

Jeffrey Campbell, Tuohy Brothers.

Good morning.

My first question is kind of a quick macro question.

Steve, as you are doing your business in the Middle East, are you seeing any tangible signs of stress or second thoughts regarding OPEC's current production strategy by any of the countries in the region?

If they had stress, they wouldn't share with us.

I think that's fair to say.

What you do see, of course, is a lot of talk about raising money and that sort of thing, so if you want to view that as stress you can.

But they all say that they are aligned, whatever that means.

Okay, thank you.

You provided helpful color on non-core asset sales in MENA.

As you continue to high-grade your portfolio, how do you think about Colombia?

Vicki can answer that.

In Colombia we recently signed an agreement with the government to do -- to implement a couple more water floods in Colombia.

We see that as -- our asset there is the opportunity to continue to maintain our production.

We would like at some point to be able to grow the production a little bit, but currently we have a great relationship with the government and with Ecopetrol.

We have a team down there that is incredibly efficient, knows the area very well.

And our operating teams are very good there.

So we see it as a place that -- we've been there for over 30 years, would like to be there -- continue to be there another 30 years.

The country itself has some opportunities outside of what we currently have and certainly any opportunity that comes up in Colombia is something we would want to take a look at.

Okay, great.

My last question is: thinking about Permian capital allocation, with the results that you showed in East Midland, is it possible that capital in the Midland Basin can increase relative to the Delaware in 2016?

Currently we were thinking that we would move more activity to the Delaware Basin, but you're right, our Midland Basin team has been performing so well, especially with this Big Spring area in Howard County.

The performance there and in merchant is getting to the point where those wells are really becoming very competitive with what we are doing in the Delaware.

Okay, great.

Thank you.

Brian Singer, Goldman Sachs.

Thank you, good morning.

Wanted to dig in a little bit on the broader Delaware and Midland Basin well performance to understand whether the strong wells you highlight here on slides 13 and 15 are trending relative to your broader acreage and drilling program and whether they're reflective of what we should expect going forward.

Not sure if it's apples to apples, but if we look at the BOE per day of per thousand feet of lateral you have for the 2015 averages, they both on slides 13 and 15 appear to be below what was reported for the first half in the second-quarter presentation.

And so what I'm trying to get to is whether the specific wells you are highlighting here with much better rates are reflective of the wells we should expect going forward for specific portions of your acreage, whether they are good averages we should assume for your broader acreage or they are highlights of your best wells.

I think the 2015 average is not exactly representative of what we will see going forward, but it is indicative of the trend that we will see.

What you are talking about, the trend downward, was certainly impacted by the Peck state and the Buzzard state, because initially we had incredible rates from the Peck state.

It was about 2,400 BOE per day 24-hour rate for the Peck state, about over 2,000 barrels a day for the Buzzard state.

Those wells were two of our best wells in the Delaware Basin.

What we're trying to do and the reason we are still -- and in answer to John's question -- the reason I said we are still trying to tweak things and work things is that we feel like we should have the ability to continue to increase our performance per well.

And we're still -- we think that with the seismic we will be able to figure out what made the Peck state and the Buzzard state so good, and then we will target trying to hit either the interval that was so good in there or the area or types of areas like that.

And so that's exactly the reason for the seismic is to try to determine whether the reservoir -- whether there are areas that are driven by reservoir quality or characteristics that we can move toward in our development program toward the end of 2016.

Because by the time we have the seismic process evaluated, it would start -- not start impacting the program till the end of next year.

But that's exactly what it's designed to do is look for whether or not those were -- those wells were in a particular area that is limited or whether it's broader and we just aren't getting the chemistry of the frac jobs right or the location within the interval.

That's not to say we are not having great wells.

We are having great wells, but we do want to continue to improve them.

We would love to see more of those types.

That's very helpful.

And my follow-up is also on slide 13, where you have the nice map of your focused acreage.

Can you just refresh us on how many acres that focus area represents and what it would take and any plans to turn some of the other acreage we see there of OXY into focused acreage?

We have, as you know, 1.5 million net acres in the unconventional business and our inventory of wells really -- the appraisal wells that we've shown you, that 8,300 well inventory, is really based on an appraisal of about half of that.

And then our development areas we're trying to keep at an even lower acreage percentage than that, because what we're trying to do is ensure that we completely build out as we build our infrastructure.

So probably the Barilla Draw area represents an acreage, at least what we are really concentrating on developing, probably two or three pods that would total up to be about 40,000 or 50,000 in the Delaware Basin.

Great, thank you very much.

our last question comes from Guy Baber, Simmons.

Thank you all for fitting me in here.

Had a follow-up question on some of the earlier questions around capital spending flexibility into 2016.

And I apologize if I missed this earlier, but can you just help us understand the amount of capital spending currently being dedicated to the portion of your MENA program that you deem as non-core?

Just trying to understand the opportunity set for the potential spending reductions there that you might be pursuing.

$400 million.

I think it's $400 million.

Okay, thanks.

And then Al Hosn, ramping up faster than expected on the production front.

Can you discuss that outperformance?

Then also, can you address the contributions during the quarter from a cash flow perspective?

And really trying to understand the timing of the cash flow contribution there and what the peak cash flow contributions are in this environment.

Obviously it's difficult to predict given the sulfur exposure and the less transparency on some of the pricing.

I think the cash has normal settlement with it, so production is actually doing pretty much the way it's set.

The 60,000 is what we've talked about.

Cash flow before capital settles like others, and so it was a little backend loaded in the third quarter, so there was less of it in the third quarter than we will see in the fourth quarter.

There's some capital that needs to be spent in the fourth quarter and into the first quarter for some things which will use some of the money.

The business just depends on really oil prices, the volatility in the business.

I think we are talking about $300 million of free cash and then it could be as much as $1 billion depending on the -- on oil prices sort of the $70s.

Okay, great.

That's helpful, Steve.

The last one for me.

You mentioned exiting 2015 with Permian Resource production of around 120,000 barrels a day.

So on over $2 billion of CapEx this year you are obviously growing that business very significantly.

Do you have an estimate of the level of spending that could hold that 120 flat through next year?

Just trying to understand how that compares to the $2 billion plus you're spending this year that is driving considerable growth.

We are now discussing among ourselves as to what that number might be, so -- under $1 billion I think.

(technical difficulty)

Thank you, Emily, and thanks to everyone for participating.

Have a great day.

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