Christopher Stavros - Vice President of Investor Relations Stephen Chazen - Chief Executive Officer, President and Director James Lienert - Chief Financial Officer and Executive Vice President

Edward Westlake - Crédit Suisse AG Katherine Minyard Evan Calio - Morgan Stanley David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

John Herrlin - Societe Generale Cross Asset Research Faisel Khan - Citigroup Inc Doug Terreson - ISI Group Inc. Douglas Leggate - BofA Merrill Lynch Duane Grubert - Susquehanna Financial Group, LLLP Paul Sankey - Deutsche Bank AG Jason Gammel - Macquarie Research

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 U.S.

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 6 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, relations 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'll now turn the call over to Jim. Jim, please go ahead.

Thank you, Chris. I'll 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 of this year compared to $1.1 billion or $1.31 per diluted share in the second quarter of last year.

Here's 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 BOE per day 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 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 liftings 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% and 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 6 months of 2011 compared with last year's 12-month cost of $10.19 a barrel. The cost increase reflects more work over and maintenance activity and higher support costs.

Taxes, other than our 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 U.S.

statutory rates. Our second quarter U.S.

and foreign tax rates are included in the Investor Relations supplemental schedule. Let me now turn to Occidental's performance during the first 6 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 6 months of 2011 compared with $2.1 billion or $2.61 per diluted share in 2010.

Cash flow from operations for the first 6 months of 2011 was $5.6 billion. We used $3 billion of 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 6 months, of which $1.6 billion was spent in the second quarter.

Year-to-date capital expenditures by segment were 85% in Oil and Gas, 13% in Midstream and the remainder in Chemicals. Our net acquisition expenditures in the first 6 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 cost already incurred for the Shah Field development project and properties in California and the Permian. The weighted average basic shares outstanding for the first 6 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'll 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, our average oil price is about $95 WTI.

We expect the back half of the year in Oil and Gas production to be as follows: Domestic volumes are expect to increase by 3,000 to 4,000 BOE per day for 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 volume 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 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 for quarter growth; in Qatar, we expect to gradually regain the production rate lost 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 the 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. Second, the average second quarter WTI oil price 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 has 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 segment -- Chemical segment earnings are 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 in about 38%.

As far as our activity is concerned, in California we expect our current drilling programs to result in more predictable production growth going forward. The status of permitting is generally unchanged from the prior quarter.

We've 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. This is expected to grow to 74 at the end of the year.

This will represent a 25% growth in our total rig count's 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're ready to take your questions now.

Steve, 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 kind of build from there?

We don't report that way. And so what you have to do is use the average because that's the way it will be reported.

So if you take the average, which is the 424 number, and so if you say, okay, that was the average so it will be average to average when you do the -- numbers actually come out. So if it's -- it will be up 3,000, up 6,000, up 9,000.

If it's 3, then you average that out, 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.

And then kind of the regionalization of your domestic, kind of how you see that 3,000 to 4,000 barrels a day of growth? How much of that is the 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 probably misleading to say exactly where. Clear that there is going to be, the bulk of it, the overwhelming majority will come out of California.

And there'll 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'll see the bulk of the growth out of California with smaller amounts out of the rest as 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. And that's sort of what it looks like.

But to actually give you how we figured it out, I'd have to start with our risk numbers and I don't want to give those kinds of numbers out.

Okay. And 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 we become limited as far as total oil volumes by that injection capacity?

At some point, we will. I don't think we're up against it now.

Where it will affect more than anything is actually THUMS. More than it will kill [ph] of the other places is probably enough for a while.

But THUMS, they've got some -- that's really water injection for their process. So I think you're going to -- that's probably where you'll see it, but the numbers are real small for this year.

Certainly within the noise of the rest of the numbers.

And how do you think about opportunities for additional acreage acquisition and kind of where things are currently in the market?

Well, I don't know how much more there is in California. I probably don't want to buy land underneath the building here with the drill.

So I think California will probably -- probably not much. Permian, we continue to buy some small partials of acreage for Wolfberry drilling primarily.

And then the Williston, there's a lot of acreage for sale. If we were open 7 days a week, there'd be 7 guys here that sell us acreage.

So 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, was shown to be completely wrong.

Steve, can we just go back to the new disclosure on the rig count? What's the outlook beyond 2011 for those various counts?

Do you think...

The California one depends on the permitting. I mean, if we had better -- more visibility in the permitting, we'd lay more rigs on to the back half, the fourth quarter.

Right now, this is the visibility we have and that's why it's showing the way it is. Once we get more visibility, we'd probably raise the count.

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

Yes. But I mean, yes, your exit rate and so it would -- you got to get the rigs on before you get the end of 2012.

So we'd start contracting for the rigs. So you'd see a higher exit rate.

But right now, this is all the visibility we really have. We're looking at the Permian and I'm trying to figure out what the right level is.

But more likely, than not it [ph] will go up so more, and maybe even sizably more depending on how we can figure it out. I think South Texas is about the same and there'll 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 6 months, you'll 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.

What we're doing now will generate a fare amount of production growth. So 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? Or is it the kind of pace that you're talking about?

Oh, yes.

Which seems to me about 2,000 barrels per month.

Somewhere in that. We gave you the 3,000 to 4,000, so some of that will be California and maybe in some quarters all of it.

So it's just hard to say exactly what it is again, I use risk the numbers so...

Understood. If we look at the year-over-year, you're flat looking backwards, obviously over 2010 to 2011 for Q2-to-Q2.

That's on, yes, sales, I think.

I understand, yes, it's on sales and I understand obviously that net there's been a negative, basically from Libya, but all the other movement. But 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've talked about in the past?

At least back because I think the domestic businesses, you're going to be surprised 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 could do a little better, but I think that's a good risk number for us.

Thanks, Steve. If I could ask you about Phibro, the training administering business, this looked like a good number and we've been expecting a headwind from Phibro.

There was a small headwind.

Okay, so Phibro wasn't that negative and what I'm 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, we break it out because that's the most volatile and we have a hard time predicting it. I think the way to think about it is that the volatility and price volatility, oil price volatility, and wide differentials between, say, pushing and world prices generates generally higher numbers.

It might generate lower numbers too, but it reduces the predictability a lot. So if I were to look at it and I'd say what's the average, I'd average the first and second quarter to get sort of an average number.

Yes, and again, just going back to Phibro and I seem -- forgive me if I garble this number, but I think you said that the range historically would be a minus $0.08 to a plus $0.12. Was that range of Phibro profitability or loss?

I can't remember any more, but that the -- he was ahead for the year at midyear. So he had a spinoff depending on how you view modest, a modest loss in the second quarter.

But for the year, he's ahead and he's well ahead now. But again, I think I've told you this before, no sense in watching it.

It's like an NBA game. You may as well turn in the -- 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 the correct?

And then did you say 7,000 a day of production?

I don't think we said for production in Iraq. The field is doing fine.

The field is doing fine. The gross is really doing fine.

Our nets may be 6,000-ish, but it really depends on the investment which has slowed up considerably. So I don't really know.

We do have a sale, we know of 600,000 barrels this month. So we'll have some actual sales this month.

And I assume given the spending slowing that you will -- the outlooks and mix here 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, production would go up immediately.

So I just don't know.

What is the spending constraint?

There's a lot of issues, I think, with the operator and that sort of thing, getting permits approved, or not permits, but contracts approved.

Steve, just on California, you've spoken in the past about trying to get these large areas permitted because then you can progress it 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 2, 3?

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. And we just don't know what the process is.

It's not exactly transparent.

So at this stage, you don't really have a feeling for how long it's going to take for one of those larger areas to actually...

I think it's a nontransparent process.

Right, okay. Maybe then switch to the increase in rig count, 3 to 4 monthly sequential increase over the second half of this year, but also 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, that would accelerate a little bit?

Yes, let's say we just spud a well today, doesn't make a difference where. We 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're seeing is a wedge or the 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 has been the drill today to when you actually get a meaningful measurement of production. So I think we're on good track now and I think we'll 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 sort of get away from WTI inland pricing towards more international pricing across the portfolio?

We're not trying to solve the industry's problems in this. We're just trying to solve ours.

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

I'm mainly thinking perhaps in the Permian.

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

Steve, at the beginning of the year, you suggest that you may get 107 shale wells drilled this year, what's the way to...

Sorry I missed you.

At the start of the year, I believe you suggested that you would drill about 107 wells, so what's the latest estimate?

Bill can answer that.

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

And how many did you complete, Bill, in the second quarter? You gave us the first quarter number, I think it was 26.

How many did you complete in the second?

It was 55.

Completed?

Correct.

But not necessarily hooked up.

That's what I was going to say. So they were -- so your backlog is building basically?

Yes, it is.

Steve, at dinner about, I guess, a month or 6 weeks ago you suggested that your kind of first base target was to get to drill around 300 wells a year. To what extent -- I mean 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're engaged with the state, I just as soon not go into our state relations. I think we're making some -- we're making physical progress where we can and I think the state -- eventually, I think the state will come around.

It just, it 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're 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 declined curves and the rate of drilling, how you'd expect that to progress, let's say, within the next 18 months?

I don't think we're -- I'm not willing to give you a forecast because, again, the forecast, the overall forecast I give you is a risk number and the bottoms up numbers are essentially sort of unrisk. But I think Bill can give you some numbers on where we are.

Doug, right now in terms of current shale production in California, we're running about 45,000 barrels of oil equivalent per day.

Okay, and given the pace of the potential pick-up spill, where would you expect that to exit the year?

I think we're not into the forecasting of that again because I think you'll be mixing a risk and unrisk numbers on the totals.

Got it. All right, the final couple for me, 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. And finally the Rosetta acquisition, how much of that was included in Q2?

And I guess...

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

Okay, and the plant status?

The plant is ready in April, is that what you're thinking?

Yes, that we're targeting April of 2012 and actually we're 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's not fairly reliable.

A few more on California, if I could. Of the 29 rigs that you have running in California, and Steve 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 de-risk further acreage versus drilling in the, I believe, 200,000 acreage that you said you thought you had de-risked on the first quarter call?

Bill, can answer that.

Jason, right now of the 29 rigs we have running in California, fully 20 of those are drilling unconventional plays or horizons. And of that 20, roughly 4 to 5 are in the process of de-risking additional acreage.

Is the 200,000 acres still a reasonable number for us to be thinking about in terms of de-risking?

I think that's not plenty for now.

Yes, agreed. Then one more, if I could.

It's probably too early to talk about this, but I'm going to try it anyway. Anything on Khuff [ph] curves, initial production rates, what you expect ultimate risk 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, I think we're a little more optimistic on the verticals and a little more pessimistic on the horizontals.

Steve, can you remind me what you're expecting on the verticals, of that 300 barrels a day, accurate, 400?

Jason, right now we're averaging about 370 and that's BOE, that's equivalent per day.

And then just one more, if I could. Of that 370 or just on an overall mix of production of the unconventionals, how much would you expect to be gas versus black oil versus condensate?

It's about 60-40, 60% oil and about 40% gas.

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

Because of the way it was computed, there are no particular easy way to tell. I would guess the bulk of it 75%, 80% would be oil.

Okay, got you. And in terms of...

Oil, meaning real oil. NGLs is an oil just so we're clear what we're talking about.

NGLs are something between Oil and Gas.

Okay, fair enough. And then looking at the overall domestic natural gas, dry gas production portfolio, is that production kind of 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. Sometimes when you -- especially in California, you drill it -- sometimes, it's 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 got some gas.

And so our ability, and 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. But so you're predicting the stuff.

You might get lucky and find the big gas zone, so our gas might go up sort of by serendipity.

Okay. Is that gas able to be produced into the market or is there infrastructure required to bring?

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

Okay, fair enough. My last question is on the Permian Basin.

In terms of your rig count kind of going up in that basin, how much of that is split between the Delaware and the Midland Basin?

Bill?

I would say looking forward, Faisel, is that what you're asking?

Yes, sir.

I'd 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 kind of where we are today versus where we'll be at the end of the year.

Right.

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

Yes, there's a whole bunch of non-operated activity also, especially in the Permian, the Permian really. So we don't have any way of sort of predicting that.

Okay, and the overall increase in the rig count in the U.S. going from 38 to 59, does that -- are those conventional drilling rigs or are there workover rigs there included?

No, that's just strictly drilling rigs.

We got a very large number of workover rigs, so they would just obscure the numbers if we include the workover rigs.

Okay. The IP rig you mentioned, the 370 for the California shale well, that's the 24-hour rate?

It's actually longer than that. It's generally -- what a stabilize rate would be over, say, a week's time because these wells have to clean up before they stabilize.

So it's really over a week or even longer period of time.

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

I mean, you're farther away from the river. So I'd assume there is less flooding where you guys are, but I'm not sure.

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

Okay. I'm seeing an increase in NGL production from the U.S.

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.

Forget about that one. In the Permian, Apache was mentioning the application to modern drilling and completion techniques, horizontal application to their CO2 flood and also water floods.

I'm assuming whether you guys see a similar upside.

We don't have a basis compared with what Apache is saying, I don't know what that's about.

On the CO2 team, we've had others in the sector see CO2 supply as a constraint. I think you guys have been pretty proactive in telling us why it's not a constraint.

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

We have [indiscernible] with supplier 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 allocated and sort of we have a 5-year plan for putting CO2 in the ground and we just go ahead and do it.

It's a very profitable business to see. We spend all the capital, really.

And 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's a one-off thing. I don't think we're interested in more heavy oil.

This was a pretty good opportunity. It was an undrilled field and 5 years from now it will be a pretty good result for us.

Okay. And then you have been buying a lot of what appeared to be one-off things that pretty have legs [ph] 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 don't think we'll be drilling much in the Arctic or anything like that.

So we're 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.

And then to follow on to an earlier comment you guys made on California. You said, I think, unconventional wells, you got about 20 out of 29 rigs more or less developing and 4 or 5 de-risking.

Can we really think of that whole program as being in a 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're always figuring out what we want to do, I think. I think we always are looking to expand and figure out new opportunities.

There's different plays that are around that we haven't talked about publicly. So we're always looking for different things to do, trying to figure out where to build the next gas plant.

There are a lot of things we do and so we're trying to figure out what the program will be over the next decade. So that requires a certain amount of, it's not high-risk exploration but significant step-out activity just to figure out where we're going.

And then with the current sector environment, with the higher 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.

Number one use is maintenance capital, second use is dividends, third use is growth capital, the fourth is acquisitions and the share repurchases are last.

A bunch of quick ones for you, Steve. For your volume growth domestically in the second quarter, was the bulk of that South Texas?

Maybe somebody will look at the numbers. I don't know whether there was a bulk of it or not.

Okay, next one, California...

No, I don't think so.

Okay. Okay, with California you said that the lion's share of the rigs currently running are unconventional, what would have been it a year ago just to give some perspective?

It was more conventional. A year ago, we were probably even 50-50 and then we shifted because we said we were going to do that.

Okay. Year end, should we assume that there's no Yemeni volumes?

No. I think a good case at Yemen.

We think that there's a reasonable chance that the -- first of all, half the production isn't really covered by that. It's other fields that have longer contracts.

And it looks to us that there's at least a reasonable chance that the government will always allow Nexen to continue to operate in Masila field while it figures out what it's 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 of the production is unrelated to that and has been pretty much unaffected by this.

Okay. For the properties the Nexen is operating, would you expect then to pay a sizable upfront bonus?

We don't know. I think right now there's really nobody to negotiate with.

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

Okay. All right.

That's fine. In terms of the property acquisition marketplace, you're full in California, you said there's a lot of for sale in the Williston, there's always dribs and drabs in the Permian.

Are you considering any sort of new areas?

In the United States?

Yes, correct.

No, not really. I mean, we tire kick a lot of stuff so we understand what's going on.

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

But you're accruing a lot of cash, and 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're seeing a lot of gratuitous, divorces these days in the public marketplace, disintegrations, whatever. Would the board ever consider maybe doing a split of Oxy between domestic and international?

You just have to come to conclusion that, that actually creates value rather than just some sort of something to entertain investment bankers. So we never say never, but I think right now there's a lot of synergies between them.

Very difficult for the international business to have anything less than a single A credit rating to get new contracts. And so it's just improbable if that would create new value to split them off that way.

Bill, just had a follow-up question, thinking about the vertical well split around, talking about 60% oil, 40% gas, that's for all the wells drilled including the Elk Hills, primary wells but your guidance is reflecting more oil growth. Can you talk us through kind of what are the kind of 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'm 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.

Yes, what I was referring to was the 60-40 split was just solely on unconventional shale wells.

That's an average rather than sort of the outcome. If they look at it, that's what they're sort of doing because when you produce the oil, you get a fair amount of gas with it.

The wells are oil wells. They just have -- they have associated gas.

It's just hard -- most of the growth is oil, but I think you asked about really a -- the answer to a very narrow range of wells.

Okay. So out of your total, what's your conventional development program heading forward and how do those wells look like?

Those wells are basically oil wells with 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.

But we think most of the growth for this year will be oil because we're trying to bias it that way. Although occasionally, we have this issue with you drill a little bit deeper and you wind up in a gas zone.

And the properties acquired, that was kind of 30 million to 35 million cubic feet equivalent a day primarily?

I think it was less. I think it's less than that.

We're the largest gas producer in the state and that's an old field, been around a long time, it's in different part of the state. And I think we could probably market a little different than maybe the predecessor.

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.

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

No. It's 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's a long-term problem for us rather than a short-term problem. The only place it affects us in the sort of intermediate term is 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's hard to produce oil without producing saltwater. So we're going to have to ultimately have more injection wells and so it's an issue.

But it's more an issue for people in steam-like business, which for some large players out here in California that have I think a much bigger issue than we do.

Okay. All right, thanks.

And then can I just switch quickly to Latin America. It just looks like the production that's being reported from Colombia is kind of trending downward.

I'm just curious as to whether that's a price-related impact or whether it's project delays?

Basically, there is a kicker to the Colombian government on price.

So going to cannibalize the front of your conference call, at least for some folks. I'll give you a break on the California questions.

We thought we'd run out of counties.

I thought so. But on the Permian, my question is, are wider differentials impacting the way you think about capital allocation and potentially away from the Permian at least on operating level, at least until this normalize and move in to 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 a reported basis or whatever. Historically, $100 is a pretty decent price.

And so the fact that somebody says, well, maybe it should be on some basis of $106. Yes, it's true but this is still $100.

Given a very oily portfolio in the Permian, I mean, this is enormously profitable. I mean, you should get -- I mean just say -- well, you should get some more, I don't know if we should get some more now, but I don't know about a year from now.

So I think we'll take the money and run.

Well, I mean that's -- I guess the second question, and clearly respect that, that's very profitable, do you think of changing any kind of hedge position into 2012 if you have...

We're not hedgers, we don't know. The Phibro guys are bullish on oil forever, so I guess we're not hedgers in that sense.

Okay, so nothing to protect any TILOS exposure?

The reason we keep sort of 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're not good speculators on product prices.

Okay, that's fair. Just maybe last question on Iraq.

I apologize if I missed it early, you mentioned it on your last call, did you begin liftings in the second half of '11?

Lifting will be this month, first lifting is this month.

Steve, sorry for the follow-up. I just wanted to get clarification on a couple of things.

You've said in the past that your shale wells were predominantly oil, meaning north of 90%, has that changed?

No.

So what's the 60-40 then, I'm confused?

It's just, 60-40 is related as to whether it's called oil well or gas well.

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

Closer to 90%, 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're 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 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 rates, again, going back to Bill's comments.

Previously you've said sort of 350 reserve was a good run rate as an IP rate. But you described that as 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 compare to what you gave us a year ago?

Doug, just to clarify really, when I was talking about 7 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's an average.

So how would I think about that in terms of let's say a month, underlying 30-day average, is that a good number or...

That's a good number, Doug, yes.

I think what he was trying to say is as opposed to just the IP rate like the Haynesville well, which is sort of one day or something, what he's trying to say is it takes them a week or so to clean up the well. It stays at this 370 for a month or so and then the decline will begin.

All right, great. And the final one is previously $3 million of well was kind of the number to drill, complete and hooked up, I guess, that you've given us.

Can you just talk a little bit about what's happening to service cost in the state and what about -- those results were still a good run rate that we should be thinking about in terms of the CapEx, and I'll leave it at that.

Doug, I think $3.5 million to $4 million is really a good range drill, complete and hooked up to sales. We are seeing some inflation on pressure pumping obviously just as the whole industry is.

But that's still a pretty good number, $3.5 million to $4 million.

You're not frac-ing these wells, Bill?

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

Sorry, Just returning to the NGL question from our view. In fact if things go up, just wondering are you -- is that part of the South Texas acquisition, is that rich gas, is that why -- I'm looking at the end, the domestic NGL production looks like...

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

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

No.

Thank you.

Well, thanks very much for joining us today on the call and if you have any questions, feel free to call us here in New York. Thanks again and have a great day.