西方石油 (OXY) 2009 Q4 法說會逐字稿

Good morning.

My name is Christi and I will be your conference operator today.

At this time I would like to welcome everyone to the Occidental Petroleum fourth quarter 2009 earnings release conference call.

(Operator Instructions) Thank you.

Mr.

Stavros, you may begin your conference.

Thank you, Christi, and good morning, everyone.

I would like to welcome you to Occidental Petroleum's fourth quarter 2009 earnings conference call.

With us this morning from Los Angeles are Dr.

Ray Irani, Oxy's Chairman and CEO, Steve Chazen, our president and CFO, Bill Albrecht, President of Oxy's US oil and gas operations, and Sandy Lowe, President of our international oil and gas business.

In just a moment I will pass the call over to Dr.

Irani who will discuss some of Oxy's achievements during 2009 and also highlight some of our key development projects going forward.

Steve Chazen will review our fourth quarter and full year 2009 financial results, discuss some reporting changes that will take effect during 2010, as well as provide some insight on our expected capital program for this year.

Our fourth quarter earnings press release Investor Relations supplemental schedules and the conference call presentation slides which refer to Steve's remarks can be downloaded off of our website at www.oxy.com.

I will now turn the call over to Dr.

Irani.

Dr.

Irani, please go ahead.

Thank you, Chris.

Good morning, ladies and gentlemen.

2009 was an interesting year that tested strategic and execution capabilities across the United States oil and gas industry.

We believe that Oxy passed last year's test with an A plus.

We achieved solid financial results in a very challenging environment.

In a few minutes Steve Chazen will provide details on our financial results for the fourth quarter and full year of 2009.

First, I wanted to mention some highlights and key developments of the past year that we believe are integral to Oxy's continued success in 2010 and beyond.

Notably, in 2009 we were able to grow our worldwide production 7% year-over-year while not increasing our net debt to capitalization.

This brought us to the highest annual production volume in our history, 645,000 BOE per day net to Oxy.

We expect that similar increase in oil and gas production both this year and next while continuing to focus on operational efficiency.

Also note worthy during the next two weeks will be announcing the financial official results but also more importantly our 2009 production replacements.

The results look very favorable.

We expect to announce that the 2009 reserve replacement ratio is about 200%.

In 2009 we maintained our A debt rating across all rating agencies.

We continue to build our pipeline of exciting opportunities which gives us confidence that our production increases from continuing operations of about 5 to 8% annually over the last five years will again be an achievable target for the next five years.

These results are attributable to consistent execution of our long-term financial strategy as well as successful company wide initiatives to reduce costs.

We aggressively managed our oil and gas production costs in 2009's very volatile commodity price environment, reducing our oil and gas production costs per BOE by 15% excluding production and property taxes.

We ended the year with cash on hand of $1.2 billion, very little debt, and one of the strongest balance sheets in the industry.

During the past twelve months we also capitalized on some key opportunities to strengthen our position and achieve further growth.

In the United States we announced a significant discovery of oil and gas reserves in Kern County, California, with initial estimated reserves of 150 to 250 million gross barrels of oil equivalent.

Steve will give you an update on its continued production growth in his upcoming comments.

We also made numerous acquisitions of properties adjacent to our key operations in Texas and California and expanded other areas of our core business.

In the chemical segment we acquired Dow Chemical Company's calcium chloride operations.

Calcium chloride is a premium salt with a variety of beneficial applications including ice control of roads and sidewalks.

Our product line has an approximate 65% market share of North American market.

There were also significant positive developments in our Middle East core operations.

In Bahrain we're partnering with Mubadala of Abu Dhabi on a project to redevelop the Bahrain oil and gas fields.

Field operations began on December 1, 2009, and we expect to increase oil production from the Bahrain field to about three times its current level of production to reach 100,000 barrels of oil per day within seven years.

The increase will be of course gradual over time.

An increase also gas production by more than 65% to approximately 2.5 billion cubic feet per day.

It was announced in the fourth quarter that Oxy partnering with a consortium lead by Eni was awarded a license for development of Zubair field in Iraq.

Last Friday we announced the signing of the contract with the government of Iraq and we expect Zubair to reach production of approximately 1.2 million-barrels a day within the next six years.

That is up from the current level of approximately 200,000 barrels a day.

Solid production growth also continued at the giant Mukhaizna oil field in South Central Oman where we had a major steam plug project for enhanced oil recovery.

As of year end 2009 gross daily production was over ten times higher than the production rate in December 2005 when we took over operations.

At that time Oxy assumed operations from another company.

Looking ahead to our 2010 capital expenditures, we plan to increase CapEx approximately 19% from a $3.6 billion spent in 2009 to about $4.3 billion for projects that will stimulate our continuous growth while maintaining our targeted financial returns.

Our 2009 results confirm that Oxy is very well-positioned to succeed in the volatile business climate that has presented significant challenges to our industry and to the global economy.

We plan to maintain a low risk, low leverage profile and a consistent focus on building stockholder value.

With our concentration of core areas, growth in production and reserves, very efficient operations, and a strong balance sheet, we are confident in our ability to continue achieving sustained growth and delivering solid profitability.

Now I would like to turn the call over to Steve Chazen.

Thank you, Ray.

Net income was $938 million in the fourth quarter of 2009 compared to $443 million the fourth quarter of last year.

2009 fourth quarter net income included after tax non-core charges mostly consisting of $115 million impairment of certain Argentine producing properties.

2008 fourth quarter including after tax charges of $514 million for impairments rig termination costs and plant closures.

Core results were $1.1 billion for the fourth quarter of 2009 compared to $957 million in the fourth quarter of 2008.

Here is a segment breakdown for the fourth quarter.

Oil and gas fourth quarter 2009 segment earnings were $1.6 billion compared to $339 million for the fourth quarter of last year.

Oil and gas core results for the fourth quarter of 2009 were $1.8 billion compared to $1 billion for the fourth quarter of 2008 after excluding asset impairments in both periods and rig termination costs last year.

Increase 2009 fourth quarter earnings was due to higher crude oil prices and sales volumes and lower operating expenses.

Occidental's average realized crude prices in 2009 fourth quarter were $69.39 a barrel an increase of 30% from the $53.52 a barrel last year Oxy's domestic realized gas price for the quarter is $4.37 per mcf compared to $4.67 mcf in the fourth quarter last year.

Worldwide oil and gas sales volumes fourth quarter of 2009 were 650,000 barrels of oil equivalent a day, an increase of nearly 5% compared to 620,000 BOE a day in the fourth quarter of last year.

Daily production volume increased 23,000 BOE a day from Oman and Bahrain, 6,000 BOE a day from Argentina, and 13,000 BOE from California operations excluding Long Beach.

Partially offsetting these increases were lower Middle East volumes of 7,000 BOE a day caused by higher oil prices affecting our production sharing contracts.

Fourth quarter of 2009 worldwide oil and gas volumes increased 3.5% or 22,000 barrels a day equivalent from the third quarter 2009 sales volumes of 628,000 BOE a day.

We began Bahrain production and development activities December 1, 2009.

Argentina volumes increased by 8,000 BOE a day.

The third quarter included a 9,000 BOE a day loss due to a strike in Santa Cruz province.

California volumes excluding Long Beach increased by 3,000 BOE a day.

Oman volumes increased by 4,000 BOE a day from the (inaudible) field.

Exploration expense was $99 million in the quarter.

Chemical segment earnings for the fourth quarter of 2009 were $33 million compared with $127 million in last year's fourth quarter.

After excluding plant closure and impairments the fourth quarter 2008 core results were $217 million.

The fourth quarter 2009 results reflect the continued weakness in most domestic markets but a particular US housing durable goods and agricultural sectors.

Midstream segment earnings for the fourth quarter of 2009 were $81 million compared to $171 million in the fourth quarter of 2008.

The decrease in earnings was due to lower margins in the marketing business in 2009 compared to 2008 partially offset by improved NGL margin resulting from lower maintenance expenses, energy costs, and property taxes in the gas processing business and higher income from Dolphin pipeline.

The worldwide effective tax rate was 41% for the fourth quarter of 2009 in line with our guidance.

Let me now turn it our performance during the twelve months.

Net income was $2.9 billion for the twelve months of 2009 compared with $6.9 billion same period last year.

Core results for the twelve months were $3.1 billion compared to the $7.3 billion for the full year of 2008.

Income for the twelve months of 2009 included $168 million of charges net of tax and 2008 included $491 million of charges net of tax for the items noted on the schedule reconciling net income to core results.

Oil and gas production costs excluding production and property taxes were $10.37 a barrel for the twelve months of 2009 of 15% decline from last year's twelve month costs of $12.13 a barrel.

Taxes other than on income were $1.77 a barrel for the twelve months of 2009 compared to $2.62 a barrel for all of 2008.

These costs which are sensitive to product prices reflect lower crude oil and gas prices this year.

Capital spending for 2009 was $3.6 billion.

Capital expenditures by segment were 79% in oil and gas, 6% in chemicals, and 15% in midstream.

Oil and gas expenditures were 56% in foreign operations and 44% domestically.

Cash flow from operations for the twelve months of 2009 was $5.8 billion.

We used $3.6 billion of the company's cash flow to fund capital expenditures and $1.8 billion in acquisitions and foreign bonuses.

These items amounted to a $5.4 billion cash usage.

We also used $1.1 billion to pay dividends.

These and other net cash flows decreased our $1.8 billion cash balance from the end of last year by $600 million to $1.2 billion at December 31st.

Fourth quarter free cash flow after capital spending dividends and taxes but before acquisition activity was about $850 million.

The weighted average basic shares outstanding for the twelve months were $811.3 million and the weighted average diluted shares outstanding were $813.8 million.

Our debt-to-cap ratio was 9%.

Our 2009 return on equity was 10.3% with return on capital employed of 9.6%.

We'll now discuss some factors affecting our 2010 program.

Beginning in 2010 we're making three reporting changes which will impact comparability between years.

Historically our production volumes had been reported as a mix of pretax and after tax volumes while revenues are reflected only pretax sales.

This difference is caused by production sharing contracts in the Middle East and North Africa where production is immediately taken and sold to pay the local income tax.

We have treated this additional revenue but not additional production.

To simplify our reporting and to conform with industry practice, our production and our revenues will now be tied.

Beginning this year we'll refer to production on this more accurate and consistent basis.

To assist you in making comparisons and historical charges present in the investor relations supplemental schedules which shows what the previous five years and the 2009 quarterly volumes would have been on this basis.

All references to growth and volume comparisons will be against these reformatted production volumes.

For example, production from last year will be referred to as 714,000 BOE a day rather than 645,000 BOE per day for the year.

This change will have no effect in the company's financial statements.

We have combined most of our gas production in the Mid-Continent regions of the United States into a single business unit called Mid-Continent Gas in order to take advantage of common development method and production optimization opportunities.

This business includes the Hugoton field, Piceance Basin as well as the bulk of the Permian Basin nonassociated gas assets which had been reported as part of the Permian business unit through the end of 2009.

Starting in 2010 these assets will reported in the Mid-Continent gas.

As a result of Mid-Continent gas production will be approximately 75% gas and 25% liquids.

Permian production will go from 84% liquids and 16% gas to 89% liquids and 11% mostly associated gas.

Including the investor relations supplemental schedules are charged showing with the previous five years and 2009 quarterly sales volumes would have been for these business units.

Those Permian gas properties had been reported as part of Mid-Continent gas.

Occidental's policy regard to tertiary recovery is to capitalize costs such as CO2 when they support development of proved reserves and general expense these costs when they support current production.

In 2009 we capitalized approximately 50% of the CO2 injected in the Permian basin.

Over the years the CO2 program matures a larger portion of injected gas supports current production.

Beginning in 2010 we will be expensing 100% of the CO2 injected in order to simplify the process of determining portion which should be capitalized versus expense.

In $2009 $69 million of CO2 costs were capitalized.

As we look ahead to the current quarter, we expect oil and gas sales volumes to increase from the reformatted fourth quarter 2009 amount of 722,000 BOE a day to about 730 to 740 BOE a day at current oil prices.

Increases will come from California, Bahrain and Oman.

There will be less liftings out of Libya which will not affect production but will affect sales.

With regard to prices, at current market prices the dollar change in oil prices impacts oil and gas quarterly earnings before income taxes by about $36 million.

Average fourth quarter WTI price is about $76.19 a barrel.

Swing of $0.50 per million BTUs in domestic gas prices has $24 million impact on quarterly earnings before income taxes.

The current NYMEX gas price is around $5.60 per mcf.

Additionally we expect exploration expense to be about $75 million for seismic and drilling for our exploration programs.

For the chemical segment the international markets remain solid.

In the United States we have a competitive advantage against foreign products.

However, the housing construction markets remain weak which will limit improvement in sales volumes and margins.

Chemical earnings for the first quarter expect to be in the range of 30 to $50 million.

We expect our combined worldwide tax rate in the first quarter of 2010 to be in the range of 42 to 43% depending on the split between domestic and foreign sourced income.

Our fourth quarter in US and foreign tax rates are included in our supplemental schedules.

For all of this year we expect capital spending to be about $4.3 billion.

Our capital program will continue to focus on ensuring that our returns remain well above our cost of capital.

The additional capital from 2009 $3.6 million level will be allocated to the oil and gas segment.

Of this increase about a quarter each will go to California and Iraq.

About 15% to Bahrain, and 10% to Mid-Continent gas.

As a result of capital allocation, will be approximately 82% in oil and gas with remainder being spent in midstream and chemicals.

Our oil and gas DD&A expense for 2010 should be approximately $10.75 per BOE.

Depreciation for the other two segments should be approximately $450 million.

Excluding the Kern county discovery over the course of a couple years we have drilled 39 exploration wells seeking nontraditional hydrocarbon zones in California.

Of these wells twelve are commercial and about 10 are currently being evaluated.

Occidental holds approximately 1.3 million acres of net fee and mineral leasehold in California which have been acquired in the last few years to exploit these opportunities.

At the Kern county discovery we are currently producing 145 million cubic feet of gas a day and 7500-barrels of liquids a day from 15 wells.

This is 5700 BOE a day higher than production of 26,000 barrels a day which we disclosed last quarter.

Cumulative gross production since the start of production through the end of December 2009 has been 19.4 BCF of gas, 1.5 million barrels of liquids.

We expect to drill eight wells in the first half of the year focusing on oil drilling and exploring the limits of the field.

We also expect to add skid mounted gas processing facilities by the second quarter.

This will add to our gas production once these facilities are installed.

Copies of the press release announcing our fourth quarter earnings and the supplemental schedules are available on our website or through the Edgar system.

We are now ready to take your questions.

(Operator Instructions) Your first question is from Doug Terreson of ISI.

Good morning, guys.

Good morning.

On Iraq, Ray, talk briefly on the country and on Iraq I wanted to see if you could expand on the next steps in that country to the best three possible meaning when do you expect investment activities to commence in earnest and number two, what is the role that gas plays in the consortium with this technical service arrangement that they have, so if you could comment on those two items, I would appreciate it it.

Sandy, would you carry on?

He is overseeing this.

Thank you, Dr.

Irani, good morning.

We have teams assembled with ENI in co-gas in Milan right now getting ready.

We believe that in the second quarter we will be commencing negotiations of development plans, and kicking off debottlenecking activities so that we can get initial production up.

Regarding the question of investment in earnest, this year we'll be mostly debottlenecking and gathering data, studying the data, developing the plans in preparation for much bigger expenditures coming in 2011, 2012.

Okay.

With regards to gas in it, we believe that in places like Iraq, it is good to have an international consortium.

It gives us an increased kind of political coverage.

We have a European, Far Eastern, and American company.

Okay.

Also, I think Steve mention that had cash costs and E&P declined by around 15% which is obviously a positive result so on this point I want to see if you can provide an update as to how you envision this trend unfolding during the next year meaning are there expectations expenses are going to decline further and if so, any order of magnitude on that capture rate is appreciated.

On the operating expenses, as you know, Doug, the US business is really driven by the gas producers, and not being critical of any one party, they really haven't put a lot of pressure on the suppliers, and so we don't see much change right now in operating costs because oil producers really can't change much, so until the gas producers are a little more disciplined than they've been, I think this is where we are.

Okay.

Great.

Thanks a lot, guys.

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

Thank you.

Good morning, everybody.

Good morning.

I am going to try a couple, Steve, on California.

I was expecting that.

I guess an update on the size of the resource.

I am not sure if you're ready to give us any update, but could you comment specifically on the type of play that you're actually working on right now?

In terms of pay zones, you have alluded backwards and forwards these can be quite thick so if you could give us numbers that that would be great and related to that maybe update on the development plan.

If it is 200 million barrels midpoint then obviously you have a whole raft of ways you can go ahead and speed up the drilling there.

What exactly do you have in terms of plans for expanding the gas plant beyond skid meant plants you're putting in place in the second quarter and I have a follow-up when your production targets, please.

The pay zones and the gas condensate zone run about 600 feet of net pay.

And, in the deeper oil zones around 400 feet of net pay.

It is fairly thick.

Especially in the gas condensate zones, pretty good permiability, so you're draining a fairly thick segment.

I think that's probably something.

The aerial extent doesn't compare with other things, but it is very similar as we said in the beginning to offshore discovery.

As far as the gas plant, we really don't know at this point.

The skid mounted thing which may be at 85 million a day is not going to be enough because that's maybe only two wells, so we're probably going to have to get some more and we just don't know how big to build the plant at this point.

Every quarter it looks like we need a bigger plant.

So we're doing the engineering work.

We're starting to build it out.

Every time we think we have a handle on it, something else happens which expands the size of the plant.

We'll be a little constrained in the next quarter or two on gas because we're within our ability to operate at that level give or take 15, 20 million a day.

Right.

Until we get it on.

Before I ask my follow-up, Steve, the production number at the end of the quarter, was that the maximum in the quarter or did you have any-- I am guessing you're playing around with this a bit.

Do you have peaking rates and can you give us insight what that looks like.

It wasn't the maximum in the quarter, no.

It was sort of what it was at the end of the quarter to provide some kind of consistency.

When you're running it over 100 gas plant at 100% or maybe more of stated capacity, especially older plants, it is a stretch to keep it running over 100%, so what you're looking at is sort of what it happened to be the day we measured it.

Got it.

My follow-up is really you have given us an indication of 5 to 8% off the higher base, I guess, for this year for production, but I have to confess, Steve, I am struggling here because Bahrain is a big sluck, California is a big sluck then have you the ramp up in Oman and various other things obviously century gas plant.

This help why is 5 to 8% right number?

Just looks like you might be sandbagging a little bit here.

We would never sandbag.

I would remind you at your request, I think, we'll have an update in May.

Okay.

Thanks.

Your next question comes from Robert Kessler of Simmons and Company.

Good morning, guys.

I may be extrapolating a little bit on Doug's questions on Kern County, California.

Like to see if you could give us a bit more of update outside of Kern County.

Looks like you added three more wells or drilled three more wells in the fourth quarter there I think going back to the last quarter's presentation you had expected seven.

Just curious if there is sort of a permitting delay involved there, any significant change in your ex Kern County exploration plans.

No.

Some little permitting.

It is just a matter of getting around to it.

It may be that a well was in process or something and didn't get counted.

Sure.

Fair enough.

At the end of the quarter.

And with respect to the Monterey shale, something you haven't talked too much about, I don't believe, and I guess you're not testing that directly so much but correct me if I'm wrong in these sort of 39 wells you have drilled so far but is that fair or have you actually put some let's say multi-stage frac lateral wells into the Monterey shell and gotten any kind of production response?

We're doing simpler drilling than that, and we are drilling shale wells, and the pace of that is picking up nicely as we move through the year.

Whether it is the Monterey shale or the other shale don't want to get into, but so far we haven't done much many in the way of high costs opportunities, but the low cost ones work just fine.

So we'll have more update of that in May also, but the pace of that is picking up nicely and will pick up all year.

I imagine you prefer all else equal a nice easily produced conventional low cost conventional well.

Anything you can say about kind of average well productivity out of the shale wells you've drilled so far?

Our average is probably more misleading than informative, so the wells have F&D costs currently with the simple things we're doing of maybe $5 a barrel.

On the conventional side?

No.

Those are the shale.

Those are the nonconventional.

Right.

Okay.

And then --

The shale wells if you will.

Okay.

Got it Looks like you picked up around 200,000 net acres in California over the course of the quarter.

Any specifics on where that acreage is located?

It is located in the heart of the producing area around the Buena Vista field, Elk Hills and that general area, so it is not way out in the middle of nowhere.

It is basically right around where the sweet production is.

Great.

Thank you very much.

Your next question is from Arjun Murti of Goldman Sachs.

Thank you.

Follow-up question on California.

I believe most of the production you highlight in your slides comes from the gas condensate zones and you were going to drilling in the oil zones and I believe you mentioned 400 feet of net pay.

Can you comment on the drilling results you have seen in the oil zones and when will start-- we might start seeing production contribution from those?

I am talking about the Kern County area.

I understand.

The oil zone is the gas condensate zone is a fairly straight forward zone.

The oil zone is I think we have indicated is more complicated.

The other problem is that when you drill the oil well is also produces gas and we don't -- we're a little tight on the capacity.

So we ought to be able to see production out of that in the next couple of quarters.

We still need gas plant capacity because even though you might produce 800 or 1,000 barrels a day out of the oil zone, you are still producing 2 or 3 million a day of gas.

That's 800,000 barrels a day per well from the oil zone is what you might think about.

Yes, initially, and then you also produce gas, so I think you got -- we're a little constrained and also the area we're trying to outline the field so we know how big to build the plant.

That's really what's controlling sizable increases in production.

How many wells have you drilled oil zone thus far?

Bill?

I don't have the exact number, but I would say it is probably on the order of ten.

Terrific.

In terms of gas plant expansions, is there kind of a rough CapEx and maybe relative to size of expansion that we should think about?

It won't be material to the total.

We won't notice it?

It is 100, $150 million sort of number.

If you look at the production numbers we gave you for the since the thing began, you will see that we clearly basically the program is paying for itself as it goes.

Let me assure you we're not going to keep studying the construction of a gas plant.

We're doing our engineering and we're making decisions shortly.

That's fantastic.

Just a final unrelated one in terms of Iraq.

Could you provide any comment on how much CapEx it would take to get to the 1.2 million-barrel a day target I believe Dr.

Irani you mentioned and how much your capital spending might be this year in the next few years?

Thank you.

Well, if you want to get to the end, bear in mind we like to look at net cash flow, and we have said clearly in our remarks earlier that the exposure to the company in total during the 20 year contract will be less than a billion dollars.

Taking into account the fact that this is a very quick recovery of spending, the press mentions all kinds of numbers that seem to cap spending over 30 years, $20 billion over five years, it is this and that.

The advantage of this contract is high early cost recovery, so Oxy's total capital spending in the project will be less than a billion dollars.

That might be your max exposure at one time, is that the way to think about it.

That's it.

It builds over the first two years but that's it.

[ multiple speakers ] Becomes positive, starts getting year-over-year.

I got it.

Thank you very much for your comments.

Your next question comes from Michael Jacobs of Tudor Pickering Holt.

Thank you.

Good morning, everyone.

Thinking about the chemical acquisition from Dow and as you think about your company wide portfolio, should we expect chemical business and perhaps midstream business as well to continue to grow in pace with your upstream business so that your kind of 80% upstream CapEx and then associated free cash from the other business remains constant as your upstream business grows?

No.

There is no strategy of balancing growth in the chemical business in the upstream business.

The chemical business as we have said repeatedly is a solid net cash generator to the company to invest in the upstream, and from time to time we are opportunistically look at both on acquisitions to our business calcium chloride business became available, but attractive returns to us and frankly this year with the bad weather it is even performed better than we expected.

So we look at things which fit into our marketing and manufacturing capabilities and I think over time one would expect the upstream business will continue to be the major part of the company and maybe growing as a percentage.

The midstream which I think is a bigger number, the midstream business is really influenced just this year, last year and this year by the plant-- the century plant.

Once that plant is done with, the midstream capital will plummet so the percentage in the oil -- you're talking instead of going from 400, $500 million in the midstream business, probably going to wind up in the $100 million range, so your percentages will shift even more heavily to the midstream business really supporting the oil and gas.

That's helpful.

When we think about on the upstream side the conventional or unconventional opportunities in your portfolio and clearly $5 a barrel finding and development costs in California is extremely attractive, are there other unconventional oil opportunities outside of your current portfolio that could be interesting?

We look at lots of things, and so I think we would be study everything.

It would be fairly hard for us to duplicate the economics in California, but we continue to look.

Okay.

And just a last follow-up on Doug's question.

As we're working through the restated volumes, can you give us an idea of what growth guidance would have been in percentage terms under the old reporting methods?

I don't know.

Same order of magnitude.

It is just a range that we -- that's used that we try to be in the high-end of the range, but it is not really that precise.

Great.

Thank you.

If oil prices go through the roof, as an example, we can't be on the upper range, so the 5 to 8% we feel is a solid range.

We can achieve on a sustained basis over the next five years.

To speculate it could be on the upper end would be misleading frankly.

We think 5 to 8% is a very solid rate of growth maintaining high returns remember.

We continue to say we expect high returns.

Not just growth.

We could grow faster, but we believe that continued emphasis on efficiency, cost control, CapEx, et cetera, solid discipline across the board, is more important than just uncontrolled high volume growth.

Thank you.

Quite frankly, I don't see any company our size and larger growing at this rate.

I agree.

Okay.

Your next question comes from David Nuhauser of Livermore Partners.

Thank you.

Good morning, gentlemen.

Could you ask me-- looking forward at some of the other companies out there are looking to right size and optimized their current portfolios, are there opportunities that exist out there today that fit within your understanding as where you want to grow that are attractive to Oxy at this point?

There are opportunities.

We continue to look at a large portfolio even during time when is people weren't wanting to sell.

It always takes two to tango.

It also depends on the price that people want, but most important as Steve has continually said and I have repeated, any acquisition must add value.

We're not going to buy assets to have a play on the price of oil or gas, so only we will buy assets when we believe we can increase production, cut costs, and get higher value out of those properties.

So we continue to be extremely attentive to those opportunities and during the fourth quarter we had a number of opportunities that came along and we took advantage of it.

Steve, do you want to add to that?

I think we don't have any interest expanding our footprint to refining or anything like that and a lot of what is on offer is well returned negative asset businesses.

Is there further opportunities you see going forward?

We have seen a number of acquisitions obviously on the unconventional side with some of the super majors.

Do you look at that as the opportunity going forward or are you still more focused on the growth opportunities, organic on the conventional side?

We're always focused on our own stuff first.

If we see an opportunity to grow the business that we can add value as Ray said, we will do that, but at this point we have a decent portfolio for the next five years, at least, but again we look at everything, so you shouldn't be -- if we can find something that adds value that we can do that's reasonable size, we would consider doing that.

But we don't feel pressed to do anything.

Okay.

All right.

Thank you very much.

Appreciate it.

Your next question comes from Richard Glasebrook of Nuberger Berman.

Good morning.

I had a question on Kern County and a follow-up.

You said the aerial extent of the field was perhaps more modest compared to others, as you put it.

I wonder how significantly you define the aerial extent to this state and give us some sense of the size of what you have and secondly, you commented in the past that you have seen no depletion from the reservoirs to date.

Has that still been true with an additional quarter?

On the first question we haven't seen the limits of the field yet.

We're not really in a position to say to continue the aerial extent continues to grow.

We haven't seen the limits of the field.

We may have seen it on one side of the field but not the other three sides.

We don't know.

On the depletion, the wells generally don't deplete very much, and we're also not necessarily pushing the wells as hard as they might at this point, so right now they are holding out pretty well.

Second question is on capital spending or rather on acquisitions.

You spent about a billion one or a billion two in the quarter.

Some of that of course included Phibro.

Did you say how much the Dow acquisition was?

Dow acquisition was earlier in the year, 210.

We spent about half the total on oil and gas and the other half in the midstream business.

What kind of volumes were attributable to the oil and gas that you bought?

We haven't said.

Obviously if we added 200,000 acres in California last quarter we obviously spent some money to do that.

Sure.

Thank you.

Thanks.

Your next question comes from Pavel Molchanov of Raymond James.

Thanks for taking my question.

Two questions regarding the 200% reserve replacement you referenced.

First could you tell us what the main areas for reserve bookings were and secondly how much higher would bookings have been without year-over-year pricing effects under your PSEs?

Thanks.

As I said, if you allow me, you're going to be get all the details over next two weeks.

It is 200% approximately and we're proud of that.

I think let's just wait until you see the announcement and it won't be long.

Understood.

Thanks.

Your next question comes from Vedula Murti of CDP US.

Good morning.

Good morning.

A couple things.

One, can you comment at all about how Phibro has been doing and what any expectations you have based on purchase price, what kind -- what type of results you're kind of hoping for them?

We hope for a lot, but we have only owned it three weeks, so we always hope.

They're doing fine, but we only owned them three weeks, and they mark-to-market every day, so every day they have a different result, so I don't I don't think we to want speculate on that because we don't know anything.

Would you be expecting to greatly expand their potential value at risk or decide --

No, no.

Okay.

And last question.

Can you update us on Argentina and anything that's going on down there?

Do you want to talk about Argentina Sandy?

Yes.

Good morning.

In Argentina we have a robust drilling program again this year, and we're working 25 different fields and production is running just under 50,000 gross barrels a day so there is nothing unusual to report there.

As Steve point out there have been some labor relations problems last year, Provincial basis wasn't isolated to us but things are looking fine right now and we hope they stay that way.

Do you have costs and price cap or something like that that will be lifting here in hopefully the not too distant future?

There is -- there are constraints to the sale and it is complicated as to how we sell on the internal market versus the export market, and there is a number of allowances we have been able to earn by increasing production in certain provinces, so it is improving, but it is always subject to local political considerations.

Thank you.

(Operator Instructions) Your next question comes from Doug Leggate of Bank of America Merrill Lynch.

Sorry for the follow-up, folks.

I wanted to circle back on one thing you said in your prepared remarks, Steve, about free cash flow of $850 million in the quarter I guess after dividends, CapEx, and so on.

Obviously if that's the run rate, we're looking at north of $3 billion of cash in a given year.

I am just curious as to what your latest thoughts are about how you're going to manage that now that you have given us a fairly modest CapEx budget for the year?

Well, we almost never build cash.

I mean, our cash I don't think has ever hit $2 billion.

I think we'll keep the cash.

One way or another we'll find opportunities.

I think this is probably a pretty decent year for opportunities for us outside of the capital program.

We see a little more activity in some of our areas we didn't spend a lot in the Permian last year we still did 21 deals, so I think it is fairly attractive especially for private people who are worried about their tax rates, so I think we'll have a pretty decent year for acquisitions this year and if there is excess cash, we'll be responsible and returning it to shareholders one way or another.

Is there a visible pipeline, Steve, that you could speak to?

I don't want to speak to it but there is clearly stuff out there.

All right.

Thanks very much.

It is more -- it is clearly more active than it was say six months ago.

Terrific.

Thanks.

Your next question comes from David Wheeler of Alliance Bernstein.

My question has been answered.

Thanks.

Thanks, David.

There appear to be no further questions.

Are there any closing remarks?

No.

That's all we have from Los Angeles and New York.

Thank you very much for joining us today, and if you have any follow-up questions, feel free to call us in New York.

Thank you again.

Thank you.

This does conclude today's conference call.

You may now disconnect.