西方石油 (OXY) 2010 Q3 法說會逐字稿

Good morning.

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

At this time, I would like to welcome everyone to the Occidental Petroleum third quarter 2010 earnings release conference call.

All lines have been placed on mute to prevent any background noise.

After the speakers' remarks, there will be a Q&A session.

(Operator Instructions) Thank you.

Mr.

Stavros, you may begin your conference.

Thank you, Christy.

And good morning, everyone.

Welcome to Occidental Petroleum's third quarter 2010 earnings conference call.

Joining us on the call this morning from Los Angeles are Dr.

Ray Irani, Oxy's Chairman and Chief Executive Officer, Steve Chazen, our President and Chief Operating Officer, Bill Albrecht, President of Occidental's US Oil and Gas Operations, and Sandy Lowe, President of our International Oil and Gas business.

In a moment, I'll turn the call over to Dr.

Irani for some opening remarks and comments regarding the new management structure we've announced recently.

Steve Chazen will then review our third quarter and year-to-date 2010 financial and operating results.

Our third 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'll now turn the call over to Dr.

Irani.

Dr.

Irani, please go ahead.

Thank you, Chris, and good morning, ladies and gentlemen.

I'm very enthusiastic about the new management structure we announced last week, both for myself and for Oxy.

The new structure would assure Oxy of continuity of a winning team both in terms of our experience and effective management, in terms of emphasis on a highly successful business strategy.

To recap the new structure, I informed our Board of Directors of my desire to relinquish the position of Chief Executive Officer, effective at the May 2011 Annual Meeting of Stockholders, and to continue as full-time Executive Chairman.

I recommended to the Board that Steve Chazen replace me as CEO.

The Board agreed with this new structure.

Steve is a proven leader.

He has been an integral member to our senior management team for many years.

Steve joined Oxy in 1994 as Executive VP, Corporate Development, became Chief Financial Officer in 1999, President in 2007, and Chief Operating Officer earlier this year.

He was also elected to the Board of Directors in 2010.

He has made and will continue to make significant contribution to Occidental's ongoing success and development.

This is a carefully developed and long anticipated senior management transition.

Steve and I have had an extraordinary productive partnership to many years.

Clearly, maintaining this partnership is in the best interest of Oxy and its stockholders.

And I look forward to continuing this partnership in future years.

During the 20 years I have been CEO, our management team has transformed Oxy from a conglomerate of unrelated business entities for the market capitalization of $5 billion, into the fourth largest oil and gas Company in the United States, with a market capitalization today of $67 billion.

Oxy has led its proxy peer group in total stockholder return, with cumulative returns of 76% over the past three years, 204% over the past five years, and 870% over the past ten years.

I'm very proud of these accomplishments.

Our management team is strong and cohesive and would be ready, willing, and able under this new structure to take Oxy to new heights and performance and excellence.

I'll now turn the call over to Steve Chazen for the details on our third quarter performance.

Thank you, Ray.

Net income was $1.2 billion, or $1.46 per diluted share in the third quarter of 2010, compared to $927 million, or $1.14 per diluted share in the third quarter of 2009.

Income from continuing operations was $1.47 per diluted share in the third quarter of this year compared to $1.14 per diluted share in the third quarter of last year.

Here is the segment breakdown for the third quarter.

Oil and gas third quarter 2010 segment earnings were $1.7 billion compared to $1.5 billion for third quarter of last year.

Improvement in 2010 was driven mostly by higher commodity prices, additional contributions from higher volumes.

Realized crude oil prices increased 13% in 2010.

Domestic natural gas prices improved 38% from the third quarter of 2009.

Partially offsetting these gains were higher DD&A rates and higher operating expenses, partly resulting from fully expensing CO2 costs in 2010.

Production for the third quarter of 2010 were 751,000 BOE a day, 6.5% increase compared to 705,000 BOE a day for the third quarter of 2009.

Most of the year-over-year production increases came from the Middle East, North Africa, with smaller increases in Argentina and United States.

The worldwide oil and gas sales volumes for the third quarter of 2010 were 749,000 barrels of oil equivalent per day, an increase of over 6.5% compared with the 702,000 BOE a day in the third quarter of last year.

Sales volume differs from production volumes, due mainly to timing of a lifting in Argentina.

Exploration expense was $83 million in the quarter.

Oil and gas cash production costs excluding production and property taxes were $10.25 a barrel for the first nine months of 2010.

Last year's 12 months costs were $9.37 a barrel.

The nine-month increase reflects a $0.35 a barrel higher CO2 costs, due to our decision to expense 100% of injected CO2 beginning in 2010, and higher field support operations, workovers and maintenance costs.

Higher domestic workover activities mostly in the Permian.

Taxes other than on income were $1.76 per barrel for the nine months of 2010 compared to $1.60 per barrel for all of 2009.

These costs, which are sensitive to product prices reflect the effect of higher crude oil and natural gas prices in 2010.

Chemical segment earnings for third quarter of 2010 were $189 million compared with $108 million for the second quarter of 2010.

Third quarter results reflect improvement from the second quarter of 2010 in both volumes and margins across most product lines.

Export markets have improved more rapidly than domestic markets, due in part to favorable feedstock costs in North America versus Europe and Asia.

Midstream segment earnings for third quarter of 2010 were $163 million compared to $77 million in the third quarter of 2009.

The increase in earnings was mainly due to trading and marketing income and higher margins in the pipeline business.

The worldwide effective tax rate was 41% for third quarter of 2010.

Let's now turn to our performance for the first nine months of this year.

The net income was $3.3 billion, or $4.07 per diluted share for the first nine months of 2010, compared with $2 billion, or $2.43 per diluted share the first nine months of 2009.

Core income was $3.3 billion, or $4.09 per diluted share for the first nine months of this year, compared with $2 billion, or $2.48 per diluted share for the year-to-date 2009 period.

The weighted average basic shares outstanding for the nine months of 2009 were $812.4 million.

The weighted average diluted shares outstanding are $813.8 million.

Our debt -to-cap ratio was 7% at the end of the third quarter.

Capital spending for the third quarter of 2010 was about $1 billion and $2.8 billion for the first nine months.

Year-to-date capital expenditures by segment were 82% in Oil and Gas, 13% in Midstream, with the remainder in Chemicals.

Cash flow from operations for the first nine months of 2010 was $6.6 billion.

We used $2.8 billion of the Company's cash flow to fund capital expenditures, $1.6 billion on acquisitions, and $340 million on foreign contracts.

These investing cash flow uses amounted to $4.7 billion.

We also used $850 million to pay dividends, and $310 million to retire debt.

These and other net cash flows increased our $1.2 billion cash balance at the end of last year by $900 million, to $2.1 billion at September 30.

The first nine months' free cash flow after capital spending and dividends before acquisition activity and debt retirements was about $3.1 billion.

Our acquisition costs in the third quarter were $1.1 billion, and we expect to spend about $300 million in the first part of the fourth quarter.

For these acquisition, we expect to add about 10,000 BOE a day in average production in the fourth quarter.

These acquisitions have a run rate of about 12,000 BOE a day.

Of this production, about one-third will be liquids and the balance will be natural gas.

Over the medium term, we expect these acquisitions to add at least 25,000 BOE a day of production.

This increase will come largely from oil production.

In addition to these acquisitions, we expect to add an additional 300,000 to 380,000 acres to our California acreage position, and interests in 100,000 acres in other producing areas.

Our California acreage will now reach approximately 1.6 million acres, an overwhelming portion of which consists of mineral interests.

We currently don't contemplate any more sizable acquisitions of acreage in California.

Our total year capital spending is expected to be about $4.4 billion.

The capital spending rate will increase in the fourth quarter of the year, largely in our domestic operations and in Iraq.

At the beginning of the year, we were running 11 development rigs in California and five rigs in the Permian.

We are currently running 16 rigs in California, and nine rigs in the Permian and expect our year end exit rate rig count to reach 19 rigs in California and 14 rigs in the Permian.

Next year, we anticipate working 21 rigs in California and 15 rigs in the Permian.

In the current environment, we are cautious about natural gas drilling and may reevaluate our 2011 US natural gas drilling program.

In the Permian, we are currently running 94 workover rigs compared with the 57 rigs we had at the beginning of the year.

We currently expect to be operating 110 rigs by the end of this year.

A portion of workover expenditures are expensed as opposed to being capitalized depending on their nature.

Our operating costs have recently increased due to higher workover activity to $10.94 per barrel in the third quarter of 2010 and further increases are expected in the fourth quarter.

As we look ahead in the current quarter, we expect oil and gas production and sales volumes to be in the range of 760,000 BOE to 770,000 BOE a day, at third quarter average oil prices.

Volume increases in the fourth quarter are expected to come from California, Oman's Mukhaizna field and the acquisitions.

Increase in oil prices of $5 a barrel from the third quarter 2010 levels would result in about 4,000 BOE a day of lower production due to the impact of higher prices affecting our production sharing and similar contracts.

Based on the development plan at the Zubair field in Iraq, we believe that we should have a small amount of production in the fourth quarter.

We do not expect to report any sales from Iraq until the first quarter of 2011.

Field development plan is on target for us to meet next year's production targets.

With regard to prices, at current market prices, $1 per barrel change in oil prices impacts quarterly earnings before income taxes by about $39 million.

Average third quarter WTI oil price was $76.20 per barrel.

For gas, a swing of $0.50 per million BTUs and domestic gas prices has a $27 million impact on quarterly earnings before income taxes.

Approximately the current NYMEX gas price is under $3.90 per Mcf.

Additionally, we expect exploration expense to be about $110 million for seismic and drilling for our exploration programs.

Chemical segment is expected to provide earnings for the quarter of about $100 million to $120 million.

Fourth quarter is usually the weakest for the business.

We expect that our continued margin improvement to be offset by the typical seasonal slowdown in housing, construction, bleach and fertilizer markets.

We expect our combined worldwide tax rate in the fourth quarter to be about 41%.

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

The Century Plant in the Permian has just started operations and will be providing additional CO2 to support growth in our Permian operations.

We expect that the plant will yield about 180 million cubic feet a day of CO2 next year to support our Permian EOR operations.

We are in the process of contracting additional CO2 from other sources and we'll use penalty payments due from the operator for under production to support these activities.

We expect to have sufficient CO2 to meet the needs of our previously disclosed expansion of flooding activities.

Turning now to California, in the first nine months of the year, we drilled seven conventional exploration and extension wells in California.

Of these, five were outside of the Kern County Discovery area.

Two of these wells are currently being tested.

We also drilled 12 unconventional exploration wells in the first nine months of this year, of which three are successful and five are being tested.

In the fourth quarter, we expect to drill ten exploration wells, at which two will be conventional, the remaining eight wells will be non-conventional.

In the fourth quarter, the exploration program will target smaller prospects, until permits are obtained for the larger ones.

We have also drilled 13 conventional exploitation wells in the Kern County Discovery area and 15 unconventional exploitation wells in California in the first nine months.

Due to delays in permitting, we've reduced our exploitation plans for the second half of the year by about ten wells.

We are continuing to have problems with our gas processing and gathering infrastructure at Elk Hills.

As a result, we expect our gas-related NGL production to be about flat in the fourth quarter.

We have ordered and commenced construction of the first new processing plant and will order the second plant shortly.

Once complete, the new processing plants will increase productive capacity, improve yields, enhance netbacks and lower operating costs.

We are also working actively to optimize and debottleneck our existing facility to improve performance.

Additionally, we are shifting our drilling to oil wells, which we expect will result in higher oil production in the fourth quarter.

Copies of the press release announcing our third quarter earnings and Investor Relations supplemental schedules are available at our website, or through the SEC's EDGAR system.

We're now ready to take your questions.

(Operator Instructions) And your first question comes from David Heikkinen of Tudor Pickering.

Good morning Steve.

Good morning.

Quick question.

As you think about the acquisitions in the quarter and the medium term run rate of adding 25,000 barrels of oil a day, can you talk about what the medium term is and how that incorporates into your multi-year production target that you detailed at your Analyst Day?

Sure.

Medium term is three years or less.

So it will fall clearly within the plan.

As we look at where we are right this minute, it's likely we'll slow up our gas drilling in the Rockies next year and so we view this as an offset for that, if that's what turns out, if gas prices are higher, we'll spend more money.

But if you -- I think that's the way I think about it, is that we're shifting to an oilier base on the intermediate term as long as we have these not very attractive natural gas prices.

And then as you think about -- you mentioned that you'll be buying CO2 and using I guess the penalty payments for that.

Can you give us an idea of what the purchase price of CO2 is on a per Mcf basis per day just so I can start thinking about how you fill those volumes and what that --

Bill can answer it better than I can.

Yes, David, normally we're contracting for CO2 anywhere between $1 and $1.15 per Mcf.

Of course we also have the option to throttle up our drilling Oxy owned Bravo Dome field which is up in northeast New Mexico.

As I think about that, CO2 volumes are still on track, so the acceleration in rig activity is more primary production in the Permian.

Any particular regions that you're increasing rig count would be helpful.

David, one of the regions is in the Wolfberry trend, where we currently have a couple of rigs working and you could probably see, some throttle up there in particular.

Any horizontal drilling there yet?

No, we are not drilling horizontal wells there yet.

Okay.

Thanks, guys.

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

Good morning, gentlemen.

Good morning.

Can I ask you to put a range around your 2011 CapEx at this point?

It seems like you've got a number of offsetting factors.

You mentioned your prudent cost with respect to natural gas prices, the ramp-up in activity in California, and the Permian and that offsetting the conservatism on gas.

Your pie charts from the Analyst Meeting would seemingly imply pretty good uptick next year, somewhere on the order of $5.5 billion to $6 billion CapEx versus this year's $4.5 billion.

But qualitatively seems like you might be on the lower end of that range.

Is that the right way to think about it, or can you put something around next year's capital program at this point?

We're still developing it, to be fair.

But the estimate we made in the -- in May wasn't that far -- wasn't that long ago.

So if you subtract the $4.4 billion from the five year total and divide by four, it would give you at least a feel for it.

We don't have any way to microanalyze whether it's going to be $200 million less or $200 million more.

We're obviously not that accurate anyway, so --

How do you think about your exploitation CapEx for 2011 in California, as you continue to have problems with the gas processing plant?

What's the risk that you have incrementally more CapEx since it's stranded temporarily while you wait on the additional processing capacity.

And why not taper back a bit, since you're not really at risk of losing this acreage next year, if you don't drill it up more aggressively?

We're shifting more oil production and so we think we'll be okay, but we're certainly not going to drill wells to shut them in -- so we'll just see where we are as the year progresses.

But we are being cautious, not just the capacity, but the -- not very exciting natural gas prices.

Got you.

And then a quick point of clarification for me.

I think Bill responded to David's question on CO2, incremental acquisition costs of $1 or $1.15 per Mcf.

I'm assuming that's a gross cost.

Can you remind us what the net would be after subtracting the fee for nondelivery of gas?

It depends on how much they non-deliver.

But to the extent that it's making up for shortfalls, it's $0.25.

Got you.

Thanks very much.

Our next question comes from Paul Sankey of Deutsche Bank.

Hi, Steve.

Good morning, or good afternoon, whatever it is.

If we could -- if I could have a specific one on acquisitions, then a more general one, could you talk a little bit more about the location of the acquisitions you made in the quarter?

Because I guess the gas/oil split would indicate that they are slightly off your usual beaten track.

The bulk of the acquisitions are in the Permian.

And they may show up partially in the mid-continent gas unit, because they are in the New Mexico-type part of the Permian, which is gassier.

So when we actually break them out, since a part of the Permian is carried in the mid-continent gas unit, so when we actually show the numbers, you'll see Permian maybe a little oilier than natural gas and mid-continent gas up a little bit.

So the split may be off.

But the overwhelming majority is in the Permian.

I've got you.

And by extension, there's no step-out acquisitions you might be doing, I don't know if it's the Marcellus --

No, we did a small acquisition in -- I think I've told the story about, we had a small interest in the Bakken, 25% interest.

The sellers wanted to monetize it so we looked at the numbers and bought them out.

And that will show up also in the mid-continent unit.

But that's pretty small in the total.

Great, and then if I could extend that into the wider question.

If I'm not wrong, the volume targets that you set at the Analyst Meeting were ex disposals, ex acquisitions?

I know there's been a lot of moving parts here obviously with California and other stuff, but do we need to reset the target outlook, allowing for the fact I guess that we didn't meet the full year target here without acquisitions?

Or can you reiterate the numbers that we had at the Analyst Meeting for future growth, ex acquisitions?

I think the big change is that the gas price hasn't met so far in what we would hope where we would be at this point.

So I would view the acquisitions as a replacement for the gas production, but we're probably not going to get next year from the Rockies.

So I think we'll -- I think next year's guidance is probably pretty good.

Right.

Without the acquisitions, we can still assume that you'll need that 6.2% base that you talked about within --

That's what we're looking for, and right now we don't have any reason to change that.

But I would caution you about the gas in the Rockies is the only place where I'm feeling a little seasick right now.

Yes, how much of a step-down could you envision seeing there?

How much is at risk, if you like?

I don't know.

But we have two rigs running currently and we have planned to go to double that next year, and I don't think we'll do that.

So it's whatever growth we've shown there I think that's probably at least some risk.

So I think from my perspective, acquisitions are just like drilling money.

You move the money around and I think the acquisitions will cover that.

Right, and then finally --

A different way.

I've got you.

Finally, California performance, is that simple math we can do in terms of the number of rigs running relative to the production and spin that forward?

Is there any pitfalls that you would want to (inaudible) in terms of making the math --

I don't think -- there's no simple math.

I've been unsuccessful in doing the simple math, so even complicated math is difficult.

It just depends on how fast they get the wells down and where they drill them and how they get their permits.

So -- and where they get them.

So I would -- I wouldn't -- right now I'm being fairly cautious about it in our outlooking process.

Is the prospect -- sorry?

Pardon me?

Excuse me.

Go ahead.

I'm just being cautious about our outlooking process right now.

I'm always hopeful that they will do better, but right now, we'll stay with the fairly cautious view from the short-term.

But we could expect an acceleration in permitting?

Oh, yes, eventually the permits come through.

It's just a matter of when.

I think we were probably a little optimistic, or maybe a lot optimistic about how fast we would get them.

Right, okay, thanks.

And let me congratulate Ray and yourself for the management changes and the success of the past.

Thank you, I hope so, too.

And your next question comes from Arjun Murti of Goldman Sachs.

Thanks.

Sorry if I missed it in all the previous CO2 questions, but how does the penalty compare to your purchase price of CO2 if it's outside the --

I think we said for the purchased gas, we're running the $1.10, $1.15 area.

And the penalty payment is $0.25.

Got it.

You mentioned the new processing capacity in California.

Where do you see that, assuming you would want to sell into it, taking your volume, your ability to produce volumes out there, too?

Basically it's out to bring us back onto track to where we said we would be in California.

Got it.

Thanks.

And then just on the Bakken comments, should we take this as your entry into the play and you'll look to expand, or it's a test case and we'll see where you go with it?

It started as an experiment and the experiment worked by chance.

Usually experiments fail.

And the price we got, we paid for the other three quarters was attractive so we'll drill less out.

If we can enter cheaply, we will.

Certainly not an area where we're heavily focused.

Got it.

Thank you very much.

Thanks.

Your next question comes from Jason Gammel of Macquarie.

Thanks very much.

I would also send my congratulations to Dr.

Irani and to Steve.

I had a couple of questions on California.

First of all, the acreage that's being added, pretty big swath of acreage.

I was wondering if you could comment on how such a large amount of acreage is still being pulled together.

Is this private companies, public companies that are selling, or is this actually organic leasing with landholders?

Not leasing.

Okay.

And then also, just on some of the comments you made about volumes, increase in overall California volumes, but flat natural gas and NGL volumes.

Just trying to reconcile how you could be increasing the oil volumes without associated gas.

Does this mean you're able to actually reinject at Elk Hills or something along those ones?

No, some of the wells are oil wells, legitimate oil wells.

So the amount of gas that's produced is relatively small in the total, and so I said flattish.

So I -- that's what I would look for, given the outlook right now, is that the -- we're actually are drilling real oil wells, not condensate wells.

Okay, thanks.

I was probably trying to read too much into the semantics there.

Yes, right.

Sounds like you're trying to be too clever.

I'm rarely accused of being too clever.

Final question if I could.

You've mentioned the seven conventional exploration wells that you drilled in California.

Would you be able -- and two obviously testing.

Would you be able to comment on how many of the wells you've drilled so far would be -- you would be able to classify as either successful or unsuccessful?

About one-third of the wells are successful -- of exploration.

That's terrific.

Thanks very much, Steve.

Thanks.

Your next question comes from Doug Leggate of Merrill Lynch.

Thanks, fellas.

Good morning, I think, and congratulations to both of you guys.

Look forward to working more with you in the future.

Couple of questions, Steve, please.

On the increase in the rigs, can you help us understand a little bit, what exactly you're going after on these incremental rigs, particularly in California?

Are these the shale play getting some attention now?

And if so, can you give us a little bit more color, please, on reverting back to what you said in your conference about what the IP rates were, indicatively what the down spacing all that good stuff?

Basically what are we looking at in terms of shale drilling activity as we look forward?

There's currently a step-up in shale drilling numbers, pretty sizable increase.

The rest of it is stuff we had planned.

The shale drilling has picked up and the wells are still running 300, 400 a day on average, some a lot higher.

So I would go 300 to 400 barrels a day for a well.

And that's a look at a 30-day type indicator?

It's a 30-day or maybe a little longer.

Right.

It's not an IP number, IP number's a little misleading.

Okay.

Okay.

Forgive me to pulling a little bit on this.

Because clearly if you were drilling these, and I'm guessing 20, 25 days, because they are verticals if I'm not mistaken.

Is that right?

Yes, about that amount.

Okay, so basically you're a drilling campaign on this, should I assume maybe ten of these rigs are drilled on the shales, looking to step up?

A little less than that probably.

Okay.

So net-net, we're looking at a fairly substantial acceleration in that program.

So basically what did you have baked into your guidance when you gave your strategy presentation in May by way of rig programs compared to what you're now telling us?

Maybe a little more in what we're now telling you than we told you in May.

Maybe a couple more rigs.

And the shift is over to oil rather than gas, as you said?

That's right.

Okay, got it.

Thank you.

Just jumping to exploration very quickly, you said one in three was your success rate -- but again, at your strategy presentation, you said you were going to drill 30 exploration wells starting next year.

I guess it was one-third, one-third, one-third between the different types of play.

You know the big plays and the bread-and-butters, as you call them.

How many of the wells you've drilled this year are in that big category versus the bread-and-butter as you see it?

No big ones.

So that's about $1 million to $10 million in targets?

They are small targets, smaller targets.

Okay, and I guess my final offering would be -- just as a way on the Elk Hills gas plant, can you be a little more specific on the new plans are a 2012 start-up, but as I understand it, the gas gathering system has been the problem.

Can you be a little bit more specific as to what the issues have been, what you're doing about it, and what the current status is in other part of Q4?

I'll leave it there.

Thanks.

We don't really -- our ability to predict this has been -- not been all that exciting.

So our goal is to get everything working.

As we try to run the plant, there's some problems on the gathering system at the traditional Elk Hills and we're working on trying to see if we could make that better.

So I've taken a cautious view right now to -- for improvements.

Okay, all right.

Thanks, Steve.

Thank you.

Your next question comes from Doug Terreson of ISI.

Congratulations to both of you guys on your success, first of all.

Thank you, Doug.

You're welcome.

And then second, my question's on corporate governance and specifically the press release that Board put out last week related to the incentive compensation plan.

And on this point, Steve, I wanted to see if you could provide a little clarity on what the new total shareholder incentives are, which I think you guys call TSRIs and whether they are different from the previous plan and if so, in what way are they similar?

Well, total shareholder return is rather simple.

You take the stock price at the time.

These awards are put in place and three years later, you see how you compared with the 12 companies that are in the peer group.

You include dividends and those calculations.

Okay.

And that's how you get at the end, looking at were you number one, two, et cetera.

Sure.

There's a table in the disclosures which will show you how it works.

But it's basically more -- the old plan had -- was not a quartile essentially.

This plan is done incrementally, so if you're in the -- if you're the top one in this plan is the only way to get up for three years on the 12.

It's the only way to get two times.

So the plan is a lot steeper, the more difficult to achieve than the old one.

Okay, okay.

Just wanted to double-check.

Thanks a lot.

Thank you.

Your next question comes from Kate Minyard of JPMorgan.

Hi, good morning, gentlemen.

Good morning.

Just a question regarding your decision not to pursue additional sizable acquisitions in California.

Is this just an issue of portfolio balance or have you exhausted the more lucrative acreage options, or are prices too lofty, or is this a combination of multiple factors?

It's -- what we said was no more acreage acquisitions, not production acquisitions just make the distinction clear.

There really isn't any sizable acreage to acquire.

Okay.

We're pretty much done.

Okay, great.

And then just in terms of your CapEx for the fourth quarter, looks like you'll be spending about $1.6 billion.

How much of that is related to activity in your newly acquired acreage?

Or your newly acquired -- your asset acquisitions?

Very small number.

Okay, all right.

Great.

Thanks very much.

Your next question comes from Philip Dodge of Tuohy Brothers.

Yes, thank you.

If I've done the arithmetic correctly.

Your recent acquisitions, sounds like about 50 million feet a day is natural gas, and my question is, were you intentionally buying natural gas, or did you have to accept some natural gas to get the oil that you wanted?

We view all of these things as money, not whether it's natural gas or oil, and if we could buy natural, in our view, if you could buy natural gas at essentially a discount -- the present word based on the current prices, we wouldn't view that as an unattractive thing to do.

You got to pay $6 an mcf baked into it.

We view that as unattractive.

So about buying gas with the current market discounted, we're basically $4 discounted for present worth.

We don't view as an unattractive thing to do.

We produce a fair amount of gas.

While we're oily, and not a pure oil Company and especially in the permian.

Lot of opportunities we think in the Permian for gas.

We're a big processor of gas in the basin.

So we prefer to buy oil cheap, but if we can buy gas cheap, we'll do that too, in our operating areas.

Does that answer your question?

Other question unrelated, I want to understand the permitting in California.

I believe you said that there's more of a delay in permitting on the large prospects than on the small prospects.

Is that just chance, or is there --

No, it's not chance.

Process --

It's where the large ones are located.

Which makes it a more complicated process.

Is that correct?

Which makes it longer.

It's an area that maybe hasn't been drilled before.

And so it takes longer to get the permits.

Okay, thank you.

Sure.

(Operator Instructions) And your next question comes from John Herrlin of Societe Generale.

Hi, Steve, three questions for you.

Hi, John.

Were the shales that you're producing for your wildcat program in California, are you fracking them, or is that natural flow?

No, John, they are all fracture stimulated.

Okay.

Or acidized, one or the other.

Okay.

That's fine.

Not -- don't get confused.

It's not -- we're talking about small frack jobs, not multi-phase fracks.

They are traditional emulations.

You commented that you didn't want to transfer all the cash flow to the services company --

And I think with this fracking, we're not transferring the cash to the services company.

Okay, that's fine.

Regarding the acquisitions market, you guys are generating a lot of free cash.

What are you seeing -- obviously you passed on some integrated packages.

Is it still small privates you're targeting, or are you pretty much open for anything?

We're always open for anything if the price is appropriate.

Okay.

Anything within our --

That's fair.

Last one for me, you're carrying about 50% to 100% less puds than your peers.

Do you think you get penalized for being too conservative with regards to reserve booking?

I don't know.

We booked the reserves deliberately conservatively because that's what the rules require.

And in the end, it all works out and we don't see we're -- whatever the right politically correct phrase for book cooking would be, is a sensible procedure for us.

Okay, thank you.

Thanks.

Your next question is from David Heikkinen of Tudor Pickering.

A follow-up on your unconventional drilling in some of the Monterey shale in California.

I heard comments and understanding that there's a decent amount of water production, how do you handle water disposal and have a permitting process for that as you think about ramping activity?

And are there any bottlenecks in that system that we ought to think about heading into next year and the year after?

Bill will answer that.

Yes, David, I mean, you're right.

We dispose of our water from this production via disposal wells and we have a good many of those on the books to be drilled here in 2011.

Traditionally, permitting has not been a problem, although I think it's fair to say that it has slowed down some.

So if you think about a 300 to 400 barrel a day well, what type of water rates are you actually seeing?

Generally a 1,00 to 1,500 barrels a day, once the load is recovered and production is stabilized.

Okay.

Thanks.

That's what I needed.

Your next question comes from Monroe Helm of Barrow Hanley.

Congratulations on the new management structuring.

Just had a quick question.

Can you give us a sense for how the cost of the barrels and the acreage acquired relates to what your traditional finding cost would be in those similar areas?

Well, future finding costs could be a lot less than our historic numbers, because we paid for the production upfront.

So I think it will be very comparable when we're done, maybe a little less than we've been doing.

Okay, thanks.

Thanks.

At this time, there are no further questions.

Are there any closing remarks?

Thank you.

Thank you very much for joining us today.

If you have any further questions, feel free to please call us.

Thanks again for joining us.

Thank you.

This does conclude today's conference call.

You may now disconnect.