西方石油 (OXY) 2011 Q2 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 second-quarter 2011 earnings release conference call.

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

After the speaker's remarks there will be a question and answer session.

(Operator Instructions).

Mr.

Stavros, you may begin your conference.

Thank you, Christy.

Good morning everyone, and welcome to Occidental Petroleum's second-quarter 2011 earnings conference call.

Joining us on the call this morning from Los Angeles are Steve Chazen, Oxy's President and Chief Executive Officer; Jim Lienert, Oxy's Chief Financial Officer; Dr.

Ray Irani, Oxy's Executive Chairman; and Bill Albrecht, President of our US Oil and Gas Operations.

In a moment I will turn the call over to our CFO, Jim Lienert, who will review our financial and operating results for the second quarter and first six months of 2011.

Steve Chazen will then follow with some guidance and an outlook for the second half of the year.

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

I will now turn the call over to Jim.

Jim, please go ahead.

Thank you, Chris.

I will discuss the second-quarter results for the Company, and Steve Chazen will follow with guidance for the second half of the year.

Core income was $1.8 billion or $2.23 per diluted share in the second quarter this year compared to $1.1 billion or $1.32 per diluted share in the second quarter of last year.

Net income was $1.8 billion or $2.23 per diluted share in the second quarter this year compared to $1.1 billion or $1.31 per diluted share in the second quarter of last year.

Here is the segment breakdown for the second quarter.

Oil and Gas segment earnings for the second quarter of 2011 were $2.6 billion compared with $1.9 billion in the same period of 2010.

The improvement in 2011 was driven mainly by higher commodity prices.

The second-quarter 2011 realized prices increased on a year-over-year basis by 39% for crude oil, 31% for NGLs, and 2% for domestic natural gas.

Sales volume for the second quarters of 2011 and 2010 were flat at 705,000 BOE per day.

Production volumes were 715,000 BOE per day in the second quarter of 2011 compared to 701,000 in the second quarter of 2010.

The production guidance assumptions we gave you on last quarter's conference call were at a $95 WTI average price assumption.

The actual average second-quarter oil price of $102.56 reduced our production volumes by about 5,000 BOE per day.

Domestic production volumes were 424,000 BOE per day compared to our guidance of 425,000 BOE per day.

The higher crude oil prices reduced Long Beach volumes by about 1,000 BOE per day.

Latin America volumes were 33,000 BOE per day.

In the Middle East region we recorded no production in Libya, consistent with our guidance.

In Iraq we produced 5,000 BOE per day.

The decline from first-quarter volume was due to the timing of development spending.

Yemen daily production was 23,000 BOE compared to 33,000 BOE in the first quarter.

Civil unrest and operational issues reduced our daily production by 3,000 BOE, and higher prices and lower development spending rates reduced daily volumes by 7,000 BOE.

The remainder of the Middle East had production of 230,000 BOE per day compared with 235,000 BOE per day in the first quarter.

Qatar's production was lower by 7,000 BOE per day, mainly due to planned maintenance and mechanical issues.

Our second-quarter sales volume guidance, which assumed a $95 WTI oil price, was 725,000 BOE per day, which translates to about 720,000 BOE per day at the higher actual prices for the quarter.

Our actual volumes were 705,000 BOE per day.

The lower volumes resulted mainly from the lower production in Yemen and Qatar and the timing of listings in Oman and Qatar.

Second-quarter 2011 realized prices improved for all our products over the first quarter of the year.

Our worldwide crude oil price was $103 .12 per barrel, an increase of 12%.

Worldwide NGLs were $57.67 per barrel, an improvement of 10%.

Domestic natural gas prices were $4.27 per Mcf, an increase of 1%.

The second-quarter of 2011 realized oil price represents 101% of the average WTI price for the quarter.

Oil and gas production costs were $11 -- cash production costs were $11.88 a barrel for the first six months of 2011 compared with last year's 12-month cost of $10.19 a barrel.

The cost increase reflects more workover and maintenance activity and higher support costs.

Taxes, other unearned income, which are directly related to product prices, were $2.36 per barrel for the first half of 2011 compared to $1.83 per barrel for all of 2010.

Total exploration expense was $62 million in the quarter.

Chemical segment earnings for the second quarter of 2011 were $253 million compared to $219 million in the first quarter of 2011.

The second-quarter results, one of the highest ever reported for the Chemical segment, reflected higher margins and volumes across most product lines.

Midstream segment earnings for the second quarter of 2011 were $187 million compared to $114 million in the first quarter of 2011 and $13 million in the second quarter of 2010.

The increase from first-quarter earnings was mainly due to higher marketing income and improved margins in the gas processing business.

The worldwide effective tax rate was 38% for the second quarter of 2011.

Our higher proportionate domestic income brought us closer to the US statutory rates.

Our second-quarter US and foreign tax rates are included in the Investor Relations supplemental schedule.

Let me now turn to Occidental's performance during the first six months.

Core income was $3.4 billion or $4.19 per diluted share compared with $2.2 billion or $2.67 per diluted share in 2010.

Net income was $3.4 billion or $4.13 per diluted share for the first six months of 2011 compared with $2.1 billion or $2.61 per diluted share in 2010.

Cash flow from operations for the first six months of 2011 was $5.6 billion.

We used $3 billion of the Company's total cash flow to fund capital expenditures, and $1.2 billion on net acquisitions and divestitures.

We used $685 million to pay dividends, and $1 billion to retire debt.

These and other net cash flows resulted in a $2 billion cash balance at June 30.

Free cash flow from continuing operations after capital spending and dividends, but before acquisition and debt activity, was about $1.8 billion.

Capital spending was $3 billion for the first six months, of which $1.6 billion was spent in the second quarter.

Year-to-date capital expenditures by segment where 85% in Oil and Gas, 13% in Midstream, and the remainder in Chemicals.

Our net acquisition expenditures in the first six months were $1.2 billion, which are net of proceeds from the sale of our Argentina operations.

The acquisitions included the South Texas purchase, a payment for the costs already incurred for the Shah Field Development Project, and properties in California and the Permian.

The weighted average basic shares outstanding for the first six months of 2011 were 812.5 million, and the weighted average diluted shares outstanding were 813.3 million.

Our debt to capitalization ratio declined to 11% compared with 14% at the end of last year.

Oxy's annualized return on equity for the first half of 2011 was 20%.

Copies of the press release announcing our second-quarter earnings and the Investor Relations supplemental schedules are available on our website at www.oxy.com or through the SEC's Edgar system.

I will now turn the call over to Steve Chazen to discuss the guidance for the third quarter.

Thank you, Jim.

As we look ahead to the back half of the year at average oil prices about $95 WTI, we expect the back half of the year in Oil and Gas production to be as follows.

Domestic volumes are expected to increase by 3,000 to 4,000 BOE per day per each month compared to the previous month.

This should result in average third-quarter production of about 430,000 to 432,000 BOE a day.

Latin America volumes should remain comparable to the second quarter.

The Middle East region production is expected as follows.

Consistent with the second quarter, we expect no production for Libya.

In Iraq we are still unable to reliably predict spending levels, which have a related impact in cost recovery barrels.

In Oman production is expected to grow from our current gross production of 210,000 BOE a day to a year-end exit rate of 230,000 BOE a day, which should result in about a net of 2,000 BOE per day per quarter growth.

In Qatar we expect to gradually regain the production rate loss due to planned maintenance and mechanical issues, resulting in about 3,000 BOE per day growth rate each quarter in the second half of the year compared to the second-quarter average.

In Dolphin and Bahrain production is expected to be similar to second-quarter levels.

In Yemen forecasting production volumes remains difficult, although currently Oxy-operated production has been partially restored.

We expect the range to be between 23,000 and 27,000 BOE a day.

We expect a lifting in Iraq in the third quarter of about 600,000 barrels of oil.

Including this lifting, we expect sales volume to be about 725,000 BOE a day at $95 West Texas Intermediate.

A $5 increase in West Texas Intermediate would reduce our production sharing contract daily volumes by about 3,500 BOE a day.

Our total-year capital expenditures remains at $6.8 billion, same as the guidance we gave you last quarter.

With regard to prices, at current market prices a $1 per barrel change in oil prices impacts quarterly earnings before income taxes by about $37 million.

The average second-quarter WTI oil prices is $102.56 per barrel.

A $1 per barrel change in NGL prices impacts quarterly earnings before income taxes by $7 million.

A swing of $0.50 per million BTUs in domestic gas prices is a $34 million impact on quarterly earnings before income taxes.

The current NYMEX gas price is around $4.40 per Mcf.

Additionally, we expect exploration expense to be about $80 million for seismic and drilling for our exploration programs in the third quarter.

The Chemical segment earnings is expected to moderate to about $225 million, mostly due to seasonal factors.

The third-quarter Chemical segment earnings is expected to reflect continued strong export demand and overall good supply and demand balances across most products, offset by some seasonal factors and turnarounds.

Historically the fourth quarter is typically the weakest quarter, and generally earnings are about half of that in the third quarter.

We expect our combined worldwide tax rate in the third quarter of 2011 to remain at at about 38%.

As far as our activity is concerned in California we expect our current drilling program to result in more predictable production growth going forward.

The status of permitting is generally unchanged from the prior quarter.

We have obtained enough permits to allow us to prosecute the program at the current pace until year-end.

However, there remains some uncertainty around future permits, particularly related to injection wells.

Our overall rig count in the United States has gone from 38 at the end of 2010 to our current rate of 59, and is expected to grow to 74 at the end of the year.

This represents a 25% growth in our total rig count from current levels.

The growth will be in the Permian, the Williston Basin and South Texas.

This program leads to continued growth of production into next year.

I think we are ready to take your questions now.

(Operator Instructions).

David Heikkinen, Tudor Pickering.

Just thinking about your production targets and the monthly sequential growth, can you give us where you were in June domestically by region, just so we can build from there?

You know, we don't report that way.

So what you have to do is use the average, because that is the way it will be reported.

So if you take the average, which is the 424,000 number, and so if you say, okay, that was the average, so it will be average to average when you do the -- when the numbers actually come out.

So it will be up 3,000, up 6,000, up 9,000 if it is 3, and then you average that out and you wind up with 6,000 of growth for the average for the quarter.

Because if you start at the end of the quarter -- you don't actually see the exit rate for the quarter.

Then kind of the regionalization of your domestic -- how you see that 3,000 to 4,000 barrels a day of growth, how much of that California, Permian, Williston, any idea of that would be helpful.

Well, we risk these numbers.

So the number that we use might be -- is a risk number as opposed to the maximum number that could come out or the worst number.

So it is probably misleading to say exactly where.

Clearer that there is going to be -- the bulk of it, the overwhelming majority will come out of California.

And there will be some growth in the Williston -- the Williston is small anyway -- and some in the Permian.

So I think if you look at the third quarter you will see the bulk of the growth out of California with smaller amounts out of the rest.

If you go into the fourth quarter, because of the ramp up in drilling in the Permian, you'll see a little more growth in the Permian, but continued pretty strong growth in California as the wells come on.

So that is sort of what it looks like, but to actually give you how we figured it out, I would have to start with unrisk numbers, and I don't want to give those kinds of numbers out.

Okay.

So then on the California permitting side, you talked about injection wells being some uncertainty.

Can you just walk us through any color around what that means?

Is that just water disposal availability?

And will you become limited as far as total oil volumes by that injection capacity?

Well, at some point we will.

I don't think we are up against it now.

Where it will affect more than anything is actually THUMS, more than at Elk Hills or the other places, as we probably have enough for a while.

But THUMS, they have got some -- that is really a water injection burner process.

So I think you're going to -- that is probably where you will see it.

But the numbers are real small for this year, certainly within the noise of the rest of the numbers.

How do you think about opportunities for additional acreage acquisition and where things are currently in the market?

Well, you know, I don't know how much more there is in California.

I probably don't want to buy the land underneath the building here to drill, so I think California will probably not be much.

The Permian, we continue to buy some small parcels of acreage for Wolfberry drilling primarily.

Then the Williston there is a lot of acreage for sale.

If you were open seven days a week there would be seven guys here to sell this acreage.

So there is a lot in the Williston.

And we're pretty picky about what we do, so there may be a small amount of acreage acquisition there.

I don't see a large deal flow in the back half of the year, although I think I said that last year at this time and was shown to be completely wrong.

Paul Sankey, Deutsche Bank.

Can we just go back to the new disclosure on the rig count?

What is the outlook beyond 2011 for those various counts, do you think?

The California one depends on the permitting.

If we had better -- more visibility in the permitting we would lay more rigs onto the back half, the fourth quarter.

Right now this is the visibility we have and that is why it is showing the way it is.

Once we get more visibility we would probably raise the count.

That would be a raised count just for 2011, you mean, exit rate?

Yes, but I mean, your exit rate and so it would -- you've got to get the rigs on before you get into 2012, so we would start contracting for the rigs.

So you would see a higher exit rate, but right now this is all the visibility we really have.

We are looking at the Permian and we're trying to figure out what the right level is, but more likely than not it will go up some more, and maybe even sizably more, depending on how we can figure it out.

I think South Texas is about the same, and there will be some growth in the Williston.

But I think a high probability of the Permian, and if we can get the permitting issues worked out in the next six months, you will see significantly higher rig counts in California.

Right now I can't -- I just don't have a basis to raise that rig count in California.

(multiple speakers).

But what we are doing now will generate a fair amount of production growth.

I'm not really concerned that this is going to be bad, but we could do some more, but right now I just can't -- I don't have enough confidence in the permitting process.

This level of rigs in California would generate growth through 2012?

Oh, yes.

At the kind of case that you're talking about?

Oh, yes.

Which seems to be about 2,000 barrels per month (multiple speakers).

Somewhere in that -- we give you the 3,000 to 4,000, so some of that will be California, maybe in some quarters all of it.

So it is just hard to say exactly what it is.

Again, I used risk numbers so --.

Understood.

If we looked at the year-over-year you are flat looking backwards, obviously, over 2010 to 2011, Q2 to Q2.

I know that (multiple speakers).

That is on sales, I think.

I understand.

Yes, it is on sales.

And I understand obviously the net, there has been a negative basically from Libya, but all the other movement, from here forward are we looking again back to the 5% to 8%?

If we ask you again in a year's time are we going to be in that 5% to 8% volume growth range that you have talked about in the past?

That -- at least that, because I think the domestic business is going to surprise, but I could be wrong.

But I think the 3,000 to 4,000 a month for the domestic business is pretty solid for a while.

And maybe we will do a little better, but I think that is a good risk number for us.

Thanks, Steve.

If I could, ask you about Phibro, the mid --- the trading midstream business (multiple speakers).

It was a good number and we would be expecting a headwind from Phibro (multiple speakers).

There was a small headwind.

Okay, so Phibro was a net negative, and what I am thinking about is whether the run rate of your Midstream business is just structurally higher now as a function of Permian activity and piping and whether we should think rolling forward of a higher through the cycle or even growing, I guess, Midstream profitability?

Well, it is -- we break it out because it is the most volatile.

We have a hard time predicting it.

I think the way to think about it is that volatility and price volatility -- oil price volatility, and wide differentials between, say, Cushing and world prices generates generally higher numbers.

Okay.

Yes, it might generate lower numbers too.

But it reduces the predictability a lot.

So if I were to look at it and I would say what is the average, I would average the first and second quarter to get sort of an average number.

And, again, just going back to Phibro, I seem to -- forgive me if I have garbled this number, but I think you said that the range historically would be a minus $0.08 to a plus $0.12, was it, range of Phibro profitability or loss?

I can't remember anymore, but the -- he didn't -- he was ahead for the year at midyear.

So he had -- depending on how you view modest -- a modest loss in the second quarter.

But he -- for the year he is ahead, and he is well ahead now.

But again, I think I have told you this before, no sense in watching it.

It is like an NBA game, you may as well tune in the last 30 seconds and forget the rest.

Fair enough.

And then forgive me if I misheard -- this is the last one for me -- I kind of missed the Iraq guidance.

I think 5,000 of production with no sales in Q2, is that correct?

Then did you say 7,000 a day of production (multiple speakers)?

I don't think we said for production in Iraq.

The field is doing fine.

Did we say that?

The field is doing fine.

The gross is really doing fine.

Our net may be 6,000-ish.

But it really depends on the investment, which is slowed up considerably.

So I don't really know.

We do have a sale we know of 600,000 barrels this month, so we will have some actual sales this month.

And I assume, given the spending slowing that the outlook for next year on Iraq volumes is difficult.

I don't know how to do it, because it reacts so quickly to the spending.

Because if we spent more it would -- production would go up immediately.

So I just don't know.

What is the spending constraint?

There is a lot of issues I think with operator and that sort of thing getting permits approved -- not permits, but contracts approved.

Ed Westlake, Credit Suisse.

Just on California, you have spoken in the past about trying to get these larger areas permitted, because then you can progress a little bit quicker once you actually get the permit through, and that means you get probably more effective capital.

Could you talk to us in terms of have you got one of these larger permit areas -- two, three?

When did you put those permits in, and when, given they might take 12 to 18 months, you might get a larger area permitted?

I don't really know.

We could go into that.

I don't know how helpful it is.

We put a number of them in for large areas, a fair -- a sizable number.

We just don't know what the process is.

It is not exactly transparent.

So at this stage you don't really have a feeling for how long it is going to take for one of those larger areas to actually (multiple speakers)?

I think it is a nontransparent process.

Right, okay.

Maybe then a switch to the increase in rig count.

A 3- to 4-montly sequential increase over the second half this year, but obviously your rig count is increasing as you go through the second half.

So as you look into 2012 would it be fair to think that would accelerate a little bit?

It should.

Let's say we spud a well today.

It doesn't make any difference where -- spud a well today.

It will have a small effect on the production in the fourth quarter, because it takes say 90 days or so, you hook it up and then you get a partial quarter.

So what you are seeing is a wedge of this stuff pushing into next year.

So our exit rate going into next year ought to be fairly attractive with a pretty high backlog of production.

So it just takes -- you just lose sight of how long it takes from today, which is what you spend to drill today to when you actually get a meaningful measurement of production.

So I think we are on good track now, and I think we will have an attractive exit rate in the United States as the year ends.

And, then, final question is around realizations.

Maybe any strategies to perhaps -- or any changes we should be aware of to try and get away from WTI Inland pricing towards more international pricing across the portfolio?

We are not trying to solve the industry's problems in this, we are just trying to solve ours.

So I would just as soon not comment on our strategies, but to point out that, for example, California basically gets world prices.

Yes, I am mainly thinking, perhaps, in the Permian.

In the Permian some of that could fall into the Midstream rather than into Oil and Gas.

Doug Leggate, Bank of America Merrill Lynch.

Steve, at the beginning of the year you suggested you may get 107 shale wells drilled this year.

What is the latest estimate?

Sorry, I missed you.

At the start of the year I believe you suggested that you would drill about 107 wells.

Shale wells.

Yes.

So what is the latest estimate?

Bill can answer that.

I think right now we are looking at somewhere between 150 and 175 shale wells to be drilled in California for the year.

How many did you complete, Bill, in the second quarter?

You gave us a first-quarter number.

I think it was 26.

How many did you complete in the second?

It was 55.

Completed?

Correct, yes.

But not necessarily hooked up.

That is what I was going to say.

So they weren't -- so your backlog is building basically?

Yes, it is.

Steve, at dinner about, I guess, a month or six weeks ago, you suggested that your first-base target was to get to drill around 300 wells a year.

To what extent -- what is it going to take to get there and how engaged are you with the state government in trying to achieve that objective?

We are engaged with the state.

I would just as soon not go into our state relations.

I think we are making some -- we are making physical progress where we can.

And I think the state -- eventually I think the state will come around.

It just takes longer that's all.

I guess a couple of other quick ones, if I may.

The production from the shale is obviously what we are all focused on in terms of how quickly that can ramp up.

Are you prepared to give us what the current production is from that particular part of the portfolio, and how you would expect, given your decline curves and the rate of drilling, how you would expect that to progress, let's say, over the next 18 months?

I don't think we are -- I am not willing to give you a forecast because, again, the forecast -- the overall forecast I would give you is a risk number and the bottoms-up numbers are essentially sort of unrisked.

But I think Bill can give you some numbers on where we are.

Right now in terms of current shale production in California, we are running about 45,000 barrels of oil equivalent per day.

Okay, and given the pace of the potential hiccups, Bill, where would you expect that to exit the year?

I think we are not into the forecasting of that, again, because I think it will be mixing risked and unrisked numbers on the totals.

Got it.

All right, the final couple for me are again related to the same thing.

Steve, the status of the gas plant, please, I believe after the maintenance in Q1, I guess we should have been expecting some recovery there.

Finally, the Rosetta acquisition, how much of that was included in Q2?

And I guess (multiple speakers).

Very little, because it didn't -- it closed in pieces during the quarter, so it was really a small number.

Okay, and the plant status?

The plant is ready -- April, is that what you are thinking about?

Yes, we are targeting April of 2012 and, actually, we are currently running a little bit ahead of schedule on that.

Sorry, Bill, I was talking about the existing plant.

The existing plant is an old plant that is not terribly reliable.

Jason Gammel, Macquarie.

A few more on California, if I could.

Of the 29 rigs that you have running in California, can you talk about how many of those are actually pursuing the unconventional objectives you have?

And then out of that number, how many are looking to derisk further acreage versus drilling in the, I believe it is 100,000 acres that you said you thought you had de-risked on the first quarter call?

Bill can answer that.

Right now of the 29 rigs we have running in California, fully 20 of those are drilling unconventional plays or horizons.

Of that 20, roughly 4 to 5 are in the process of derisking additional acreage.

Is the 200,000 acres still a reasonable number for us to be thinking about (multiple speakers)?

I think it is plenty for now.

Yes, agreed.

Then one more if I could.

It is probably too early to talk about this, but I'm going to try to anyway.

Anything on type curves -- initial production rates, what you expect ultimate recoveries to be, et cetera?

I think as we look at this, if we went back to what we said roughly a year ago, or a little more than a year ago, I think we are a little more optimistic on the verticals and a little more pessimistic on the horizontals.

Can you remind me what you were expecting on the verticals?

Is that 300 barrels a day IP rate, 400?

It is -- right now we are averaging about 370, and that is BOE -- that is equivalent per day.

Then just one more if I could.

Of that 370 -- or just on an overall mix of production out of the unconventionals how much would you expect to be gas versus black oil versus condensate?

It is about 60/40.

60% oil and about 40% gas.

Faisel Khan, Citigroup.

On the 3,000 to 4,000 barrels per month of domestic production growth at the end of the year, how much of that is gas and gas and oil?

Because of the way it was computed, there is no particular easy way to tell.

I would guess the bulk of it, 75%, 80% would be oil.

Okay, got you.

Then in terms of your --

Oil, meaning real oil.

NGLs isn't oil.

Just so we're clear what we are talking about.

NGLs are something between oil and gas.

Okay, fair enough.

Then if I'm looking at the overall domestic natural gas -- dry gas production portfolio -- is that production expected to remain flat through the end of this year or do you expect declines to take place?

No, I think it will probably grow.

Then last (multiple speakers).

Sometimes when you -- especially in California, you drill -- sometimes it is a little misleading, because if you drill a shale well you might take it down to the deeper zone -- slightly deeper zone.

And the slightly deeper zone tends to be gassy.

And you may not have drilled the well for that purpose, but all of a sudden you've got some gas.

So our ability -- so as we take what was designed as a shale well down a little bit further, you can wind up with a gas zone, and so you get a little more volatility in the number, which is not a bad thing, by the way.

So predicting this stuff you might get lucky and find a big gas zone and that -- so our gas might go up sort of by serendipity.

Is that gas able to be produced into the market or is there infrastructure required to bring (multiple speakers)?

It depends on where it is, but the answer is we -- so far we have been able to manage it.

okay.

Fair enough.

My last question is on the Permian Basin in terms of your rig count going up in that basin.

How much of that is between the Delaware and the Midland Basin?

Bill?

You know, I would say looking forward -- Faisel, is that what you are asking?

Yes, sir.

I would say probably 70% or so is going to be devoted to that delta -- that incremental rig count is going to be devoted to the Delaware Basin as opposed to the Midland Basin.

The delta depending where we are today versus where we will be at the end of the year?

Right.

Sven del Pozzo, IHS.

With that new disclosure on the rigs on the back page is gross operated rigs -- on a net basis are the increases similar?

Yes.

Okay.

There is a whole bunch of nonoperated activity also, especially in the Permian -- the Permian really, so we don't have any way of predicting that.

Okay.

The overall increase in rig count in the US is going from 38 to 59, does that -- are those conventional drilling rigs or are there workover rigs there included?

No, that is just strictly drilling rigs.

We've got a very large number of workover rigs, so it would just obscure the numbers if we included workover rigs.

Okay.

The IP rig you mentioned, the 370 for the California shale well, is the 24-hour rate?

It is actually longer than that.

It is generally -- what a stabilized rate would be over, say, a week's time -- because these wells have to clean up before they stabilize -- so it is really over a week or even longer period of time.

Okay.

How did your operations team deal with flooding in North Dakota?

You are farther away from the river, so I would assume there is less flooding were you guys are, but I'm not sure.

It really didn't affect us at all, given where we operate.

Okay.

I am seeing an increase in NGL production from the US in the second quarter over the first quarter, is that correct?

I mean, a substantial one?

NGL production?

Yes, I might be wrong.

Let me see.

I didn't think it went hardly at all.

No, then forget about that one.

In the Permian, Apache was mentioning the application of modern drilling and completion techniques -- horizontal application to their CO2 floods and also water floods.

I am assuming whether you guys see similar upside.

We don't have a basis to compare with what Apache is saying.

I don't know what that is about.

Duane Grubert, Susquehanna Financial.

On the CO2 theme, we have had others in the sector see CO2 supply as a constraint.

I think you guys have been pretty proactive in telling us why it is not a constraint.

Can you talk to us about how you think of allocating capital in the Permian to non-CO2 versus CO projects and if CO2 available is a factor in that allocation?

We supply about half of our own CO2, and we have ways to increase that.

So the fact that some smaller operator has a problem getting CO2 doesn't surprise us.

The market is fairly snug.

It's a very profitable business.

We allocate it in sort of a -- we have a five-year plan for putting CO2 in the ground, and we just go ahead and do it.

It is a very profitable business because we spent all of the capital really.

Then jumping over to one of your recent acquisitions, the heavy oil stuff in California, do you have any early read on your enthusiasm for your heavy oil project?

It is a one-off thing.

I don't think we are interested in more heavy oil.

This was a pretty good opportunity.

It was an undrilled field, and five years from now it will be pretty good results for us.

Okay, and then you have been buying a lot of -- what appear to be one-off things that could have legs domestically.

I'm sure people also pitched to you international assets.

Do you have any appetite to be shopping internationally?

We always look for opportunities internationally, but in places we understand, of course.

So I think it would be -- I don't think we will be drilling much in Antarctica or anything like that.

So we are looking for places we understand and where we can make substantial returns.

You don't want to go to international just to produce empty barrels.

Then to follow on to an earlier comment you guys made on California.

You said unconventional wells, you get about 20 out of 29 rigs more or less developing and 4 or 5 derisking.

Can we really think of that whole program as being in the development stage now or are there certain aspects of it, like infrastructure sizing or maybe where the footprint is that you're still in less of a development stage and more of a figuring out what you want to do stage?

We are always figured out what we want to do, I think.

I think we always are looking to expand it and figure out new opportunities.

There are different plays that are around that we haven't talked about publicly.

So we are always looking for different things to do.

We're trying to figure out where to build the next gas plant.

There are a lot of things we do, and so we are trying to figure out what the program will be over the next decade.

So that requires a certain amount of -- it is not high-risk exploration, but significant step-out activity just to figure out where we are going.

Then with the current sector environment, with the high oil prices and the ability to do a lot of work in domestic areas that didn't frankly exist 5 or 10 years ago, can you remind us of your philosophy of cash use and maybe how the current environment might be influencing or changing that, if at all?

Cash use has always been the same.

I think I have the same slide for the last 15 years.

The number one use is maintenance capital.

The second use is dividends.

Third use is growth capital.

The fourth is acquisitions, and the share repurchases are last.

John Herrlin, Societe Generale.

A bunch of quick ones for you, Steve.

Sure.

For your volume growth domestically in the second quarter was the bulk of that South Texas?

Now we will have to -- maybe somebody will look at the numbers.

I don't know whether it was the bulk of it or not.

Okay, next one.

California (multiple speakers).

No, I don't think so.

Okay.

With California you said that the lion's share of the rigs currently running are unconventional.

What would have been a year ago, just to give some perspective?

It was more conventional.

A year ago we were probably even, 50-50 on it and we have shifted, because we said we were going to do that.

Okay.

Year-end should we assume that there is no Yemeni volumes?

No.

I think in the case of Yemen we think that there is a reasonable chance that the government -- first of all, half the production isn't really covered by that.

It is other fields that have longer contracts.

It looks to us that there is at least a reasonable chance that the government will allow us -- allow Nexen to continue to operate the Masila Field while it figures out what is going to do.

So I think there's a reasonable chance the stuff in Yemen will continue for a while at the full rate.

No guarantees of that, obviously.

But about half their production is unrelated to that, and has been pretty much unaffected by this.

Okay, for the properties that Nexen is operating, would you expect them to pay a sizable upfront bonus of some sort?

We don't know.

I think right now there is really no one to negotiate with.

I assume that what will happen is they will just let it go for a while until there is priority in the government there.

Okay, all right.

That is fine.

In terms of the property acquisition marketplace, you are full on California.

You said there is a lot for sale in the Williston.

There is always drips and drabs in the Permian.

Are you considering any sort of new areas?

In the United States?

Yes, correct.

No, not really.

We tire kick a lot of stuff, so we understand what is going on.

But I don't see any, and certainly not this year.

Well, you are accruing a lot of cash, so would it be reasonable to assume that you would focus on more dividend growth or potentially a share buyback, which I know you don't particularly like, but is that a consideration?

We like dividends better than share repurchases.

Okay, that's fine.

Last one for me.

We are seeing a lot of gratuitous divorces these days in the public marketplace -- disintegrations, whatever.

Would the Board ever considered maybe doing a split of Oxy between domestic and international?

You just have to come to a conclusion that that actually creates value rather than just some sort of -- something to entertain investment bankers.

So I -- you never say never, but I think it is -- right now there is a lot of synergies between them.

It is very difficult for the international business to have anything less than a single A credit rating to get new contracts.

So it is just improbable that would create any value to split them off that way.

David Heikkinen, Tudor, Pickering, Holt.

Bill, I just had a follow-up question, thinking about the vertical well split, talking about 60% oil, 40% gas.

That is for all the wells drilled, including the Elk Hills primary wells, but your guidance is reflecting more oil growth.

Can you talk us through what are the current well splits for the wells you're drilling on the vertical unconventional?

David, most of them are vertical wells in terms of the unconventional wells.

Nearly all are drilling vertical wells as opposed to horizontal, just speaking to the unconventional.

I am trying to understand the 60% oil, 40% gas and the average of all the wells drilled versus the guidance that most of the growth is oil.

What I was referring to was the 60/40 split was just solely on unconventional shale wells.

That is an average rather than sort of the outcome.

That is -- if you looked at it, that is what they are sort of doing.

Because when you produce the oil you could get a fair amount of gas with it.

The wells are oil wells.

They just have associated gas.

It is just hard to -- it is hard -- most of the growth is on oil, but I think you asked about really -- he answered a very narrow range of wells.

Okay, so out of your total -- what is your conventional development program heading forward then and what do those wells look like?

Those wells are basically oil wells, and they are less gas.

Nothing wrong with the gas, I mean, you get $4 and they have high rates and so you get your money back pretty quick.

It is just -- but we think most of the growth for this year will be oil, because we are trying to bias it that way.

(multiple speakers) although occasionally you have this issue with -- you drill a little bit deeper and you wind up in a gas zone.

Just Rosetta, the properties was acquired, it was kind of 30 million to 35 million cubic feet equivalent a day, primarily --.

I think it was less.

I think it is less than that.

(multiple speakers).

We are the largest gas producer in the state.

And that is an old field, been around a long time.

It is in a different part of the state.

And I think we would probably market it a little different than maybe the predecessor, but --.

Katherine Minyard, JPMorgan.

A quick question on your comments on California and some of the permits.

You talked about there being some uncertainty around future permits, particularly related to the injector wells.

I was just curious as to whether there is something about the nature of the injection wells that is holding them up or is it their location?

No, it is an industry issue, not necessarily related to us.

Okay, and then just in light of that how much of your growth forecast in California depends on successfully permitting the injection wells, and then does that change over time?

It is a long-term problem for us rather than a short-term problem.

The only place that it would affect us in sort of intermediate terms a little bit under 1,000 barrels a day at THUMS.

But other than the rest of it -- ultimately you need to dispose of the water.

So it is hard to produce oil without producing salt water.

So we're going to have to ultimately have more injection wells, and so it is an issue.

But it is more an issue for people in the steam flood business, which there are some large players in that here in California that have, I think, a much bigger issue than we do.

Okay, all right.

Thanks.

Can I just switch quickly to Latin America?

It just looks like the production that is being reported from Colombia is kind of trending downward.

I'm just curious as to whether that is price-related impacts or whether it is project delays?

It is -- basically there is a kicker to the Colombian government on price.

Evan Calio, Morgan Stanley.

If (inaudible) keeps in a row here it is going to cannibalize the front of your conference call, at least for some folks.

I'll give you a break on the California questions and --.

Good, we thought we had run out of counties.

I thought so.

But on the Permian my question is are water differentials impacting the way you think about capital allocation?

And potentially a way from the Permian, at least on an operating level, at least until [PLIS] normalize and move into another part of your portfolio?

At $100 oil, which is the WTI price, you could drive a truck through the margins.

On a cash basis or reported basis or whatever, we historically viewed $100 as a pretty decent price.

And so the fact that somebody says, well, maybe it should be on some basis $106 -- yes, it is true, but this is still $100, given a very oily portfolio in the Permian.

I mean, this is enormously profitable.

You say, well, you should get some more.

Well, I don't know -- we should get some more now, but I don't know about a year from now.

So I think we will take the money and run.

That is, I guess, the second question.

And I think clearly respect that is very profitable, do you think of changing any kind of hedge position into 2012 if you (multiple speakers)?

We are not hedgers.

We don't know.

The Phibro guys are bullish on oil forever, so I guess we are not hedgers in that sense.

Okay, so nothing to protect any PLIS exposure?

We are -- the reason we keep a debt-free balance sheet is so we don't have to protect our downside.

So we don't have to buy basically insurance for downside.

We are not good speculators on product prices.

Okay, that is fair.

Just maybe a last question on Iraq.

I apologize if I missed it earlier, you mentioned it on your last call.

Do you begin liftings in the second half of (multiple speakers)?

Lifting will be -- is this month.

The first lifting is this month.

Okay, perfect.

Thank you, guys.

(Operator Instructions).

Doug Leggate, Bank of America Merrill Lynch.

Steve, sorry for the follow-up.

I just wanted to get clarification on a couple of things.

You have said in the past that your shale wells were predominantly oil, meaning north of 90%.

Has that changed?

No.

So what is the 60/40 then?

I am confused.

60/40 is related to whether it is called an oil well or a gas well.

So what is the majority of the wells you're drilling, are they 60% oil or 90% oil?

Closer to 90%.

Okay, thanks.

And (multiple speakers).

But we may occasionally -- you should understand that sometimes you drill a little deeper and you wind up with a pretty gassy well.

Sure, I understand that.

But predominantly if we are talking about completing 150 to 175 wells this year, what proportion of those would you say were in the 90% range than in the other range, because it makes a heck of a difference to the value, obviously?

Probably not as much as you think, because the gas wells will have a lot of liquids with them.

Right.

The IP rigs, again, going back to Bill's comments, previously you had said sort of 350 was a good run rate as an IP rate.

But you described that is longer than 30 days, which is a bit different from Bill saying 7 days.

So can we get some clarification on that also?

Maybe just reiterate how you see the decline curve as we -- compared to what you gave us a year ago.

Doug, just to clarify, really, when I was talking about seven days I was talking about time for the wells to clean up.

That 370 BOE a day number really is a 30-day stabilized IP number.

That is an average.

So how would I think about that in terms of, let's say a month down the line, 30 day average, is that a good number or (multiple speakers).

That is a good number, yes.

I think what he was trying to say is as opposed to just an IP rate like a Haynesville well, which is sort of one day or something.

What he is trying to say is it takes him a week or so to clean up the well.

It stays at this 370 for a month or so and then the decline would begin.

All right, great.

The final one is previously $3 million a well was kind of the number to drill complete and hook up, I guess, that you have given us.

Can you just talk a little bit about what is happening to service costs in the state?

And what about -- it is also still a good run rate that we should be thinking about in terms of CapEx?

And I will leave it at that.

I think 3.5 to 4 is really a good range, drill complete and hook up to sales.

We are seeing some inflation on pressure pumping, obviously, just as the whole industry is, but that is still a pretty good number, 3.5 to 4.

You are not fracing these wells, Bill?

No, there is a few that we do fracture stimulate, but the majority are just acidized.

Sven del Pozzo, IHS.

Sorry, just returning to the NGL question from earlier.

In fact, it did go up -- just wondering are you -- is that part of the South Texas acquisition?

Is that rich gas?

Is that why -- I am looking at the ends domestic NGL production.

It looks like (multiple speakers).

The additional NGLs from last year -- from a year ago come from South Texas and from the Permian.

So are we going to see in the future a similar ramp up in NGL production sequentially quarter-over-quarter?

No.

Okay, thank you.

There are no further questions.

Thank you.

Well, thanks very much for joining us today on the call.

If you have any questions, feel free to call us here in New York.

Thanks again and have a great day.

Thank you.

This does conclude today's conference call.

You may now disconnect.