Ray Irani - Chairman & Chief Executive Officer : Bill Albrecht - Vice President; President of Oxy Oil and Gas, USA Sandy Lowe - Vice President; President of Oxy Oil and Gas - International Production Christopher Stavros - Vice President of Investor Relations

David Heikkinen - Tudor Pickering Robert Kessler – Simmons & Company Paul Sankey – Deutsche Bank Arjun Murti - Goldman Sachs Jason Gammel - Macquarie Doug Leggate – Merrill Lynch Kate Minear – JPMorgan Philip Dodge – Tuohy Brothers John Herrlin – Societe Generale Monroe Helm – Barrow Hanley

Good morning. My name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Occidental Petroleum third quarter 2010 earnings release conference call. (Operator Instructions). Mr. Stavros, you may begin your conference.

Thank you Christie, and good morning, everyone. Welcome to Occidental Petroleum's third quarter 2010 earnings conference call. Joining us on the call this morning from Los Angeles are Dr. Ray Irani, Oxy's Chairman and Chief Executive Officer, Steve Chazen, our President and Chief Operating Officer, Bill Albrecht, President of Oxy’s U.S. Oil and Gas Operations, and Sandy Lowe, President of our International Oil and Gas business. In a moment, I will turn the call over to Dr. Irani for some opening remarks and comments regarding the new management structure we’ve announced recently. Steve Chazen will then review our third quarter and year-to-date 2010 financial and operating results. Our third quarter earnings press release, Investor Relations supplemental schedules and the conference call presentation slides, which refer to Steve's remarks, can be downloaded off of our website at www.oxy.com. I will now turn the call over to Dr. Irani. Dr. Irani, please go ahead.

Thank you Chris, and good morning ladies and gentlemen. I’m very enthusiastic about the new management structure we announced last week. Both for myself and for Oxy. The new structure will assure Oxy of continue of a winning team both in terms of our experience and effective management, and in terms of our emphasis on a highly successful business strategy. To recap the new structure, I informed the Board of Directors for my desire to delinquish the position of Chief Executive Officer effective at the May 2011 annual meeting of stockholders, and to continue as full time Executive Chairman. I recommended to the board that Steve Chazen replaced me as CEO, the board agreed with this new structure. Steve, he is a proven leader, he has been inner group member of our Senior Management team for many years. Steve Joined Oxy in 1994, as an Executive VP Corporate Development. Became Chief Financial Officer in 1999, President in 2007 and Chief Operating Officer earlier this year. He was also elected to the Board of Directors in 2010. He has made and will continue to make significant contribution to Occidental’s ongoing success and development. This is a carefully developed and long anticipated senior management transition. Steve and I have had an extra ordinary productive partnership for many years. Clearly maintaining this partnership is in the best interest of Oxy and the stockholders. And I look forward to continuing this partnership in future years. Nearly 20 years as I have been CEO our management team has transformed Oxy from a conglomerates of unrelated business entities with the market capitalization of $5 billion into the fourth largest oil and gas company in the United States with the market capitalization today of $67 billion. Oxy has lead its proxy peer group in total stockholder return. With cumulative returns of 76% over the past three years, 204% over the past five years and 870% over the past 10 years. I’m very proud of these accomplishments. Our management team is strong and cohesive and would be ready willing enabled under this new structure to take Oxy to new heights and performance and excellence. I’ll now turn the call over to Steve Chazen for the details on our third quarter performance.

Thank you Ray. Net income was $1.2 billion or $1.46 per diluted share in the third quarter of 2010 compared to $927 million or $1.14 per diluted share in the third quarter of 2009. In complementing the operations of $1.47 per diluted share in the third quarter this year, compared to $1.14 per diluted share in third quarter of last year. Here is the second breakdown for the third quarter. Oil and gas third quarter 2010 segment earnings were $1.7 billion compared to $1.5 billion of third quarter last year. Improvement in 2010 was driven mostly by higher commodity prices additional contributions from higher volumes. Realize curd oil prices increased 13% in 2010; domestic natural gas prices improved 38% in third quarter of 2009. Partially offsetting these gains were higher DD&A rates and higher operating expenses, partly resulting from fully expensing CO2 cost in 2010. Production for the third quarter of 2010, were 751,000 BOE a day, 6.5% increase compared to 705,000 BOE a day the third quarter of 2009. Mostly year-over-year production increases came from Middle East, North Africa with smaller increases in Argentina and United States. The world wide oil and gas sales volume for the third quarter 2010 were 749,000 barrels of oil equivalent per day. An increase of over 6.5% compared with the 702,000 BOE a day in the third quarter of last year. Sales volume differs from production volumes do mainly to the timing of lifting in Argentina. Exploration expenses $83 million in the quarter. Oil and gas cash production cost excluding production and property taxes were $10.25 a barrel for the first nine months of 2010. Last year’s 12 months cost were $9.37 a barrel. The nine month increase reflects a $0.35 a barrel higher CO2 cost due to our decision to expense 100%…

Thank you, (Operator Instructions).

And your first question comes from David Heikkinen of Tudor Pickering.

Good morning Steve.

Good morning. David Heikkinen – Tudor Pikering: Just a quick question and you think about the acquisitions in the quarter and then the medium-term run rate of adding 25,000 barrels of oil a day, can you talk about what the medium-term is and how that incorporates into your multi-year production targets that you detailed at your Analyst Day?

Sure, medium-term is three years or less. So it will fall clearly within the plan. As we look at where we are right this minute, it’s slightly it will slow up our gas drilling in the Rockies in next year. And so we view this is sort of an offset for that if that’s what turns out gas prices are higher we will spend more money. But if we—I think that’s the way I think about this we were shifting to an oilier base on the medium-term as long as we have these not for attractive natural gas prices. David Heikkinen – Tudor Pikering: And then as you think about – you mentioned that you’ll – you’d be buying CO2 or and using I guess fertility payments for that. Can you give us an idea of what the purchase price of CO2 on a per Mcf basis today just so I can start thinking about high sold out volumes and all that…

Bill can answer that better than I can.

Yeah David, normally we’re contracting for CO2 at anywhere between a $1 and a $1.15 per Mcf. And of course we also have the option to travel up our drilling in the Oxy owned Phibro don’t deals, which is up in Northeastern Mexico. David Heikkinen – Tudor Pikering: So if I think about that CO2 volume is still on track. So the acceleration in rig activity is more primary production in the Permian any particular regions that you’re increasing rig count would be helpful.

Yeah David, one of the regions is in the Wolfberry Trend, where we currently have a couple of rigs working and you could probably see some throttle up there particular David Heikkinen – Tudor Pikering: :

No, we are not drilling horizontal wells yet. David Heikkinen – Tudor Pikering: All right. Thanks guys.

Your next question comes from Robert Kessler of Simmons & Company. Robert Kessler – Simmons & Company : Good morning gentlemen.

Good morning. Robert Kessler – Simmons & Company : Can I ask to put a range around your 2011 CapEx this point? It seems like you got a number of offsetting factors you mentioned you are prudent caution with respect to natural gas prices the ramp up in activity in California and the Permian. And they kind of setting the conservatism on gas, your pie charts in the analyst meeting with 10 million pie, a pretty good uptake next year somewhere in the order the $5.5 billion to $6 billion in CapEx versus this year’s $4.5 billion. Qualitatively it seems you might be on the lower end of that – to that range. Is that the right way to think about it or can we put something around next year’s capital program at this point?

: Robert Kessler – Simmons & Company : How do you think about your exploitation CapEx for 2011 in California as you continue to have problems with the gas processing plant? What’s the risk that you have incrementally more CapEx since sort of stranded temporarily while you wait on the additional processing capacity and why not taper back a look of this since you’re not really at risk of losing this acreage next year if you don’t drill it up more aggressively?

Yes, we are shifting the more oil production. And so, we think we’ll be okay. But we are sort of not going to drill wells to shut them in for. So, we’ll just see where we are as the year progresses. But we are being cautious about not just the capacity, but not very exciting natural gas prices. Robert Kessler – Simmons & Company : Got you. And then a quick point of clarification for me. I think Bill responded to David’s question about CO2 incremental acquisition cost of $1 or $1.15 per Mcf I assume that’s the gross cost and can you remind us what the net would be after subtracting the fee for non-delivery of gas?

It depends on how much they non-deliver, but the extent that’s span making up for shortfalls is $0.25. Robert Kessler – Simmons & Company : Gotcha. Thanks so much.

Your next question comes from Paul Sankey of Deutsche Bank. Paul Sankey – Deutsche Bank: Hi thanks. If I could have a specific one on acquisitions and then a more general one? Could you talk a little bit more about the locations of the acquisitions you made in the course of the, I guess, the gas oil split would indicate that they are slightly off to a usual beaten track?

The bulk of the acquisitions are in the Permian and they may show up partially in the Midcontinent gas unit, because they’re in the New Mexico type part of the Permian which is gas here. So – and when we actually break them out since a part of the Permian is carried in the Midcontinent gas unit. So when we actually show the numbers you’ll see Permian maybe oilier natural gas and Midcontinent gas up a little bit. So, the split maybe off, but the overwhelming majority is in the Permian.

I got you. And the by extension that most of the step out acquisitions that you might be doing, or enhance the Marcellus or whatever.

No. We did a small acquisition in, I think, I’ve told you the story, but we had a small interest in Bakken, 25% interest. The sellers wanted to monetize it. So we looked the numbers and bought them out and that will show up also in the Midcontinent unit. But that’s pretty small in the total.

Great, and then if I could extend that into the wider question, if I’m not wrong, the volume targets that you set at the Analyst Meeting was – ex disposals ex acquisitions. I know there has been a lot of moving parts here obviously with California and other stuff, but do we need to reach that the – the target outlook allowing for despite, I guess we didn’t meet the full year target here without the acquisitions or can you resituate the numbers that we had at the Analyst Meeting for future growth ex acquisitions?

I think the big change is that the gas price hasn’t met so far and what – but we hope for – or we’d be at this point. So, I would view the acquisitions as a replacement for the gas production that we are probably not going to get next year from the Rockies. So I think we’ll – I think next year’s guidance is probably pretty good.

Right, so without the acquisitions we can still assume that you’ll meet that 6.2 – base that you talked about within that …

That’s what we’re looking for and right now we don’t have a reason to change that. But I would caution about the gas in the Rockies is the only place where doing the little seasick rate has.

Yeah, how much of the step down could we – could you have sustained value how much is it risk you feel like?

I don’t know, but we have two rigs running currently and we have planned to go to double that next year and I don’t think we’ll do that. So it’s whatever growth we’ve shown there I think is probably at certainly some risk and so I think the – from my perspective acquisitions are like drilling money, lose the money around and I think the acquisitions will cover that.

Right.

But in a different way.

Okay, and then finally to California performance, is that a simple math that we can do in terms of the number of rigs running relative to the production and kind of spin that forward, are there any pitfalls that you’d warn us against in terms of making that math to how…

I don’t – there is no simple math, because I’ve been unsuccessful in doing the simple math, so even complicated math is difficult. It just depends on how fast they get the wells down and where they drill them and how they get the permits. So and when where they get them. So, I wouldn’t – right now I’m being fairly cautious about in our outlooking process. Yeah. I was just being conscious about our outlooking process right now. I’m always hopeful that they’ll do better, but right now, we’ll stay with fairly cautious for you of this in the short-term.

But we could expect an acceleration in permitting or…?

Yeah, eventually the permits come through. It’s just a matter of when I think we’re probably little optimistic about – or I mean we are lot of optimistic about how fast we get them.

Right, okay thanks and Let me congratulate Ray and Bill for the management changes and success for the past.

Thank you.

I’ll show too.

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

Thanks. Sorry if I missed it in all the previous CO2 two questions. But how does the penalty compared to your purchase price of CO2 if it does…

Well, we said that for the purchased gas we’re running $1.10 $1.15 area and the penalty payment is $0.25 would be something this.

Yes, got it. You mentioned the new processing capacity in California, where do you see that, I assume you’d want to sell into it, taking your volume, your ability to produce volumes out there too?

Yeah, but basically of what it brings back on the track, on track for what we said we’d be in California.

Got it. Thanks, and then just on the Bakken comment. Should we take this as your entry into the play? And what to expand or it’s the test case we’ll see where you go with it?

It started as an experiment and the experiment worked by chance using experiments payoffs. And so and the price we got- we paid for the other three quarters was attractive. So we’ll drill wells out. We can enter cheaply; we will certainly not an area where we’re heavily focused.

Got it. Thank you very much.

Thanks.

Your next question comes from Jason Gammel of Macquarie.

Thanks very much and I would extend my congratulations to Dr Irani and to Steve. I had a couple of questions on California. First of all, the acreage that’s being added pretty big swat of acreage. I was wondering if you could comment on how such a large amount of acreage is still being pulled together? Is there is private companies, public companies that are selling or is this essentially organic leasing with landholders?

Not leasing.

Okay. And then also, just on some of the comments you made about volumes, increase in overall California volumes, but flat natural gas and NGO volumes. I was trying to reconcile how you could be increasing the oil volumes associated to gas just being able to actually re-inject at Elk Hills or something along those lines?

No, I mean, some of the wells are oil wells, legitimate oil wells. And so the amount of gas that’s produced is relatively small in the total. And so, I said flattish. So, that’s what I would look for given the outlook right now is we’re actually are drilling real oil wells, not condensate wells. Jason Gammel – Macquarie: Okay. Thank you. That’s how, I’m trying to reach too much in the semantics there.

You’re trying to be too clever. Jason Gammel – Macquarie: I’m rarely accused of being too clever. And a final question, if I could. You’ve mentioned the seven conventional exploration wells that you’ve drilled in California. Would you be, and to obviously testing, but would you be able to comment on how many of the wells that you’ve drilled so far would be, you’d be able to classify as either successful or unsuccessful?

About a third of the wells are successful, of exploration. Jason Gammel – Macquarie: Okay. That’s terrific. Thanks very much Steve.

Thanks.

Your next question comes from Doug Leggate of Merrill Lynch. Doug Leggate – Merrill Lynch: Thanks fellows, good morning. And congratulations to both of you guys. I look forward to working more with you in the future. A couple of questions Steve, please. On the increase in the rigs, can you help us understand a little bit, what exactly it’s going after here on these incremental rigs particularly in California? Is this particularly is getting some attention now, and if so, can you give us a little bit more color, please, on revising back what you said in your conference about, what the kind of IP rates were indicatively well they can [Inaudible] that kind of good stuff. Basically, what are we looking at in terms of shale drilling activity as we look forward?

No, this is clearly a step up in shale drilling activities in the numbers, with pretty sizable increase. The rest of it is, there is sort of stuff we have planned with the shale drilling has picked up and the wells are still running, 300, 400 a day on average, some a lot higher. So, I would go 300 to 400 barrels a day sort of, for a while.

And that’s looking 30 days IP type of indicative?

It’s a 30 day, or maybe a little longer. It’s not an IP number. IP number’s a little misleading.

Okay. We are looking for improvement on this because clearly, if you’re drilling these thing, I’m guessing 20, 25 days, because the radicals that are not mistaken.

Yes, about a month.

Okay. So basically, you’re drilling campaign on this, should I assume maybe 10 of these rigs have been and drilling in the shales looking to step up?

A little less than that probably. Douglas Leggate – Merrill Lynch: Okay. So in that, we’re looking a totally substantial acceleration on that program. So, basically, what did you have taken to your guidance when you gave your strategy presentation in May, by way of rig programs compared to what you’re not telling us?

May be a little more and what we are now telling you than we told you in May, there will be couple more rigs. Douglas Leggate – Merrill Lynch: Okay, and this ship is over to oil, rather than gas as you said.

That’s right. Douglas Leggate – Merrill Lynch: Okay, got it thank you. Just jump into exploration very quickly you said one in three was your success rate, but again at the start of your presentation you said you’re going to drill 30 exploration wells starting next year and I guess it’s kind of like a third of third of third between the different types of play, the big places and the bread-and-butter we call them. How many of the wells you’ve drilled this year are in not big category versus the bread-and-butter was it?

No, big once. Douglas Leggate – Merrill Lynch: So, that is also 1 million to 10 million small targets.

Yeah, they’re small targets, smaller targets. Douglas Leggate – Merrill Lynch: Okay and I guess the final thing would be [Inaudible] gas plant. Can you give a little more specific on that the new plants of 2012 starts up but I found this land with the gas gathering system has been a problem. Can you be a little bit more specific as to what the issues are being what you are doing about it and what the current status in the early part of Q4 and I’ll leave it there, thanks?

We don’t really are able to predict this is not an all excited so our goal is to get everything working as we try to run the plant there is some problems in the gathering system traditional well. And we are working on strategy we can make that better [Audio Gap]. Basically, more the old plant had it was on the curtail essentially and this plant is done incrementally so if you are the top one in this plant it’s the only way to get output for three years on the 12, it’s the only way to get two times. So, the plant is a lot steeper it’s more difficult to achieve than the old one. Douglas Leggate – Merrill Lynch: Okay, I just wanted to double check. Thanks a lot.

Thank you.

Your next question comes from Kate Minear with JPMorgan. Kate Minear – JPMorgan: Hi, good morning gentlemen.

Good morning. Kate Minear – JPMorgan: Just a question regarding your decision not to pursue additional sizable acquisitions in California, is this just an issue of portfolio balance or have you exhausted the more lucrative acreage options or prices to offer is this a combination of multiple factor?

What we said was no more acreage acquisition, not production acquisitions to make the distinction clear. There really isn’t any sizeable acreage to acquire. Kate Minear – JPMorgan: Okay.

They’re pretty much done. Kate Minear – JPMorgan: Okay, great. And then just in terms of your CapEx for the fourth quarter, it looks like here we spending about $1.6 billion, how much of that is related to activity in your newly acquired acreage, or your newly acquired, your asset acquisition?

You know very small number. Kate Minear – JPMorgan: Okay. Alright, great. Thanks very much.

Your next question comes from Philip Dodge of Tuohy Brothers. Philip Dodge – Tuohy Brothers: Yes, thank you. If I’ve done the arathametic correctly, your recent acquisitions, it sounds like about 50 million feet a day is natural gas and my question is where you intentionally buying natural gas or did you have to accept some natural gas to get the oil that you wanted?

We view all things as sort of money, not whether it’s natural gas or oil. And if you could buy natural, in our view, if you could buy natural gas that essentially -- present or based on current prices, we wouldn’t do, that’s an unattractive thing to do. You got to pay $6 – baked into what we view that is sort of unattractive. So, buying gas at the current market discounted, basically sort of $4 discounted for present ore, we don’t view as an unattractive thing to do. We produce a fair amount of gas and oil, not a pure oil company. And discussing the Permian and then lot of opportunities we think in the Permian for gas, where big processor gas in the basin. So, we prefer to buy oil for real cheap, but if we can buy gas cheap we’ll do that too in our operating areas. Philip Dodge – Tuohy Brothers: Other question unrelated, I want to understand the permitting in California, I believe you said that there is more delay in permitting on the large prospects and on the small prospects. Is that just chance or is there?

No, it’s not chance, we are the large one are locate it. Philip Dodge – Tuohy Brothers: Which based on the more complicated process, is that correct?

Which makes it longer, it’s an area maybe that hadn’t been drilled before. And so it takes longer to get the permits. Philip Dodge – Tuohy Brothers: Okay, thank you sir.

(Operator Instruction) And your next question comes from John Herrlin of Societe Generale. John Herrlin – Societe Generale: Yeah, hi Steve.

Hi John. How are you? John Herrlin – Societe Generale: For the shales that you’re participating for your well care in California your attracting number that natural have.

John they are partly [ph] stimulated John Herrlin – Societe Generale: Okay.

As said, the one or the other. John Herrlin – Societe Generale: Okay, that’s fine.

Not the, don’t get confuse it’s not, we are talking about small fracs jobs not the multi phase fracs. They are traditionally-- John Herrlin – Societe Generale: And you commented that you didn’t want to transfer all the cash flow to the series of company --

And I think with this kind of frac-ing we are not transferring the gas to the service company. John Herrlin – Societe Generale: Okay, that’s fine. Regarding the acquisitions market you guys are generating a lot of free cash, what are you saying obviously you have passed on some integrated packages, is it still small privates you are targeting or you’re pretty much up for anything?

We are always open for anything if the price is appropriate. John Herrlin – Societe Generale: Okay.

Anything with [Inaudible] John Herrlin – Societe Generale: Last one from me, you are carrying about 50% to 100% less pods than your peers. Do you think you could penalize perhaps for being too conservative with regards to reserve booking?

I don’t know we booked the reserves deliberately conservatively because that’s what the rules require and in the end it all works out and we don’t see were, whatever the right politically correct phrase for booking it would be with -- is a sensible procedure for us. John Herrlin – Societe Generale: Okay, thank you.

Thanks.

Your next question is from the David Heikkinen of Tudor, Pickering. David Heikkinen – Tudor, Pickering: I’ve a follow-up on your unconventional drilling in some of the moderate shale in California her comment and understanding that there is a least amount watered introduction how do you handle water disposal and kind of permitting process for that, as you think about ramping activity and are there any bottlenecks in that system that we have to think about heading in the next year, and the year after.

Yeah, David I mean, you’re right. We dispose of all water from this production, be a disposal wells and we have a good many of those on the most of we drill here in 2011, traditionally permitting is not been a problem although I think it is, it’s fair to say it is slow down some. David Heikkinen – Tudor, Pickering: Of course you think about 300 or 400 barrels a day well what type of water rates are you actually seeing?

Generally 1000 to 1500 barrels a day, once the load is recovered and production is stabilized. David Heikkinen – Tudor, Pickering: And thanks. That’s what I needed.

Your next question comes from Monroe Helm of Barrow Hanley. Monroe Helm – Barrow Hanley: Congratulations on the restructuring. I just had a quick question; can you give us a sense of how the cost of the barrels in the acreage required relates to what your traditional finding cost should be in the similar areas?

Well the future finding cost can be a lot less than our historic numbers, because we sort of paid for the production on front. So I think it will be very comparable we’re done, maybe a little less than what we have been doing. Monroe Helm – Barrow Hanley: Okay, thanks.

Thanks.

At this time, there are no further questions. Are there any closing remarks?

Thank you very much for joining us today. And if you any further questions, feel free to please call us in need. Thanks again for joining us.

Thank you. This does conclude today’s conference call. You may now disconnect.