西方石油 (OXY) 2008 Q2 法說會逐字稿

Good morning.

I will be your operator.

I would like to welcome everyone to the Occidental Petroleum second quarter 2008 earnings conference call.

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

After the speakers' remarks, there will be a question-and-answer period.

(OPERATOR INSTRUCTIONS) Thank you.

It is now my pleasure to turn the floor over to your host, Christopher Stavros.

Sir, you may begin your conference.

Thanks very much.

Good morning, everyone.

I'd like to welcome you to Occidental's second quarter 2008 earnings conference call.

Joining us on the call from Los Angeles are Dr.

Ray Irani, Oxy's Chairman and CEO; Steve Chazen, our President CFO; and Casey Olson, Oxy's President of Oil and Gas in the Eastern Hemisphere.

In a moment I will be passing the call over to Dr.

Irani who will highlight some of Oxy's recent announcements and future development opportunities.

Steve Chazen will the review our second quarter and six-month financial results.

We'll also provide greater detail on our plans for increased capital spending, oil and gas drilling activity and our outlook for growing our oil and gas production through the remainder of the decade.

Our 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, everybody.

Today we're very pleased to announce a record second quarter with net income of $2.3 billion, 63% increase compared to the second quarter of 2007.

Net income for the first six months of 2008 was $4.1 billion, an increase of 58% over the comparable six-month period last year.

These results reflect not only the strong oil and natural gas prices, which have generally benefited the industry, but also the increased production across Oxy's operations.

Comparing the first six months of this year to the first six months of 2007, our total worldwide production has increased by about 7% to an average daily production of 598,000 BOE per day.

Despite a labor dispute in Argentina during May which is now settled.

Very shortly Steve will discuss our results in more detail.

But first I would like to mention some recent developments that will enable us to further expand our worldwide production and create additional value for Oxy's stockholders.

As most of you are aware, the majority of Oxy's production is in the United States, which last year provided 63% of our total production and 75% of our proven reserves.

We are the leading oil producer in the Permian basis in Southwest Texas and Southeast New Mexico with production at a rate of about 200,000 barrels of oil equivalent per day.

In California, we are the largest natural gas producer, the third largest oil producer, and in total, our current net total production in California averages 126,000 barrels of oil equivalent per day.

We have stated repeatedly that our long-term strategy is to maintain the U.S.

production to be over 50% of worldwide production and to have reserves well over 50% of the total.

So we intend to strengthen Oxy's North American position even further.

We are making a significant effort to increase North America production with strategic acquisitions and increased drilling.

In the coming months we will increase our 2008 capital expenditures budget to a total of $4.7 billion.

This year we plan on drilling and recompleting approximately 400 wells located in each of our key business areas throughout the United States.

Namely, the Permian basin in Texas and New Mexico, the Piceance basin in Northwest Colorado and all our California operations.

We're also increasing drilling activity in Argentina, Colombia, and Libya.

A primary means of increasing production is through enhanced oil recovery, including carbon dioxide flooding in which Oxy is an industry leader.

We're now able to apply this technology to wells which at lower oil prices previously were not economical to operate with EOR.

Consequently, these wells are what I would call low laying fruit.

To enhance our position in CO2 oil recovery, last month we announced that we will develop a hydrocarbon gas processing plant and related pipeline infrastructure in West Texas that will provide a new source of CO2 for EOR at our existing properties in the Permian basin.

The project is expected to add approximately 500 million barrels to our industry leading reserves in the Permian over the next five years, at a very attractive cost, all from assets we currently own.

This additional CO2 supply will enable us to expand production in the Permian by a minimum of 50,000 barrels of oil a day within the next five years.

Adding further to our North American assets, last month we agreed to purchase a 15% interest in the Totale operated Jocelyn oil sands project in Alberta, Canada.

As you may know this is one of the premier oil sands projects in the world with over 8 billion barrels of hydrocarbon in place.

We estimate recoverable reserves net to Oxy to be about 370 million barrels.

We expect to spend about $2 billion over the next few years to develop these reserves in Canada, with production targeted to begin in 2014.

While we are emphasizing Oxy's North American operations we continue to pursue our long-term strategy to grow the business at a faster pace in the Middle East.

And to pursue opportunities that meet our stringent standards for financial return.

Last month, I joined with officials from the Libya National Oil Company to formally sign new 30-year agreements upgrading our existing petroleum contracts in Libya, covering fields with approximately 2.5 billion barrels of recoverable high quality oil reserves.

The new contract will increase our profits from Libya immediately, and allow us to increase production for the future.

Also significant for Oxy's continued potential growth in the Middle East long term is our prequalification by the government of Iraq to participate in discussions to develop a number of that country's most prolific oil fields.

As you are aware, development of these massive fields is a critical engine of growth for the Iraqi national economy.

Depending on the security situation in Iraq, which is fluid, there is a possibility of projects being finalized by late next year.

With the first two quarters of 2008 now concluded, we are pleased with Oxy's success and growth.

In light of the excellent additions to our asset portfolio and promising projects in the pipeline, we expect 2008 to be another outstanding year for Oxy, and I would now like to turn the call over to Steven Chazen.

Thank you Ray.

Core results for the quarter were a record $2.3 billion or $2.79 per diluted share, compared to $943 million or $1.12 per diluted share in the second quarter of 2007.

Second quarter core results exceeded the previous record set in the first quarter of -- by 26%.

Here's a segment breakdown for the second quarter.

Oil and gas second quarter 2008 segment earnings were $3.8 billion compared to about $1.7 billion for the second quarter of 2007.

Oil and gas core results for second quarter of 2007 were about $1.6 billion after excluding gains from the sale of oil and gas interests last year.

The following counter fee increase in oil and gas earnings between these quarters.

Higher worldwide oil and gas price realizations resulted in an increase of $2.2 billion of earnings over the comparable period last year.

Oxy's average realized crude oil price in the 2008 second quarter was $110.12 per barrel, increase of 86% from the comparable period in 2007.

Oxy's domestic average realized gas price for the quarter was $9.99 per Mcf compared with $7.07 per Mcf in the second quarter of 2007.

Worldwide oil and gas production the second quarter averaged 588,000 barrels of oil equivalent per day, an increase of over 5% compared with 558,000 BOE production second quarter of last year.

The bulk of the production proven was 46,000 BOE a day from the Dolphin project which began production third quarter 2007, and from the recently acquired domestic assets partially offset by a 15,000 barrel a day in lower volumes from Argentine operations due to a strike in the Santa Cruz province in May of this year, which I will discuss later, and lower production of 19,000 BOE per day caused by higher oil prices affecting our production sharing contracts.

Dolphin contributed $101 million to after-tax income during the second quarter on sales volume of 46,000 BOE a day.

Dolphin sales volume decreased in the first quarter 2008 to the effect of higher prices on our production sharing contracts which have reached a cost recovery ceiling for this year.

Exploration expense is $58 million in the quarter.

Oil and gas cash production costs first six months of 2008 were $14.08 a barrel, compared with last year's costs of $12.33 a barrel.

Approximately 47% of the increase related to increased energy costs.

The increase reflected higher production and ad valorem taxes in field operating costs.

An additional 17% of the increase was caused by ineffective production sharing contracts.

In the bask half of the year we are boosting our expense to workover activity by 65% in order to increase production in the current high product price environment.

Chemical segment earnings the second quarter of 2008 were $144 million.

Chemicals earned $158 million in last year's second quarter.

Midstream segment earnings the second quarter 2008 were $161 million.

Increase of $136 million from the second quarter of 2007 results.

Improvement was due to higher pipeline income from Dolphin, higher NGL margins in the gas processing business, improved margins in the marketing side.

Positive mark to market adjustments also contributed to pipeline and storage earnings during the second quarter of 2008.

The worldwide effective tax rate was 42% the second quarter of 2008.

Now let me now turn to Oxy's performance during the first six months.

Net income was about $4.1 billion, or $5.01 per diluted share for the first six months of 2008, compared with about $2.6 billion or $3.11 per diluted share for the same period last year.

The six months 2008 reported net income was another record and was 58% higher than the first six months of 2007, the former record.

Income for the first six months of 2007 included $893 million net of tax, the items noted on the schedule of reconciling by net income to core results.

Capital spending for the quarter was $1.1 billion and $2 billion for the first six months.

Cash flow from operations for the six months was $5 billion.

We used $2 billion of the Company's cash flow to fund capital expenditures, $2.3 billion for acquisitions, which included a $450 million payment for the Libya contract bonus, and $415 million to pay dividends.

We used $816 million to repurchase 11.1 million common shares, at an average price of $77.82 a share.

These outflows decreased our $2 billion cash balance at the end of last year by $500 million to $1.5 billion at June 30.

That was $1.8 billion at the end of June which was unchanged from year end.

The weighted average basic shares outstanding for the six months were 822.5 million and the weighted average diluted shares outstanding were 826.9 million.

At June 30, there were 818.1 million basic shares outstanding, and the diluted share amount was approximately 822.4.

The Board has authorized repurchase of an additional 20 million shares which brings the total remaining share repurchase authorization to 35.2 million.

Oxy's 2008 annualized return on equity was 35% with annualized return on capital employed of 32%.

As we look ahead in the current quarter, regard to prices, $1 per barrel change in oil price impacts oil and gas quarterly earnings before income taxes by about $37 million.

The sensitivity includes the impact of Dolphin.

We also included as a production sharing contract price impact approximately 300 barrels per day.

The swing of $0.50 per million Btu's in domestic prices has a $25 million impact on quarterly earnings before income taxes.

Additionally, we expect exploration expenses to be about 90 million to $110 million for seismic and drilling for our exploration programs.

We expect chemical segment earnings for the third quarter to be similar to second quarter results with a range of 135 million to $150 million.

Weakness in the construction and housing market continue to impact domestic demand while higher feed stock and energy costs have reduced margins.

These factors have been partially offset by higher caustic soda prices and higher poly vinyl export volumes.

Despite difficult economic conditions, the concerns over export opportunities over the balance of the year we believe this range of earnings is highly likely.

We expect our combined worldwide tax rate in the third quarter to remain at 42%.

Our second quarter U.S.

and foreign tax rate is included in the Investor Relations supplement.

Now turning to our capital spending program we expect to increase our 2008 capital spending estimate to $4.7 billion which is an increase of $700 million or 17%.

This additional money we'll use to drill 254 new wells, complete 145 additional capital workovers.

Overall, this represents a 16% increase in new wells and a 12% increase in capital workovers.

Scheduled detailing this increased capital activity in 2008 is included in the Investor Relations slides.

The majority of the activity will be in California where we're adding six additional drilling rigs.

We will be expanding our rig fleet in the Oak Hills area by five, drilling additional 100 wells mostly in shallow zones.

We've added 50 capital workovers to our activity in the second half of the year.

We are doubling the exploration wells in the Elk Hills are to 20.

In other California areas we're expanding existing developments.

We are also adding six drilling rigs in Latin America where in Argentina we will be increasing drilling to offset the impact of the recent strike during which we could not engage in any drilling activities.

We are also carrying out an extensive workover program in Argentina.

In Columbia we are expanding drilling into LCI field.

In the Middle East, North Africa, additional wells are being drilled in the soil area in Yemen.

In Libya we'll be drilling four additional exploratory wells, three of which are within the new contract area.

Finally, we are increasing mid stream spending primarily for the construction of the new West Texas gas processing plant and related pipeline which is announced at the end of June.

As we look at future production, we expect oil and gas production to be in the range of 590,000 to 600,000 barrels a day during third quarter, approximately $125 oil price.

The strike in Argentina's Santa Cruz province lasted approximately five weeks, resulted in complete shut-in of all production and drilling activities in that region.

Production is back to approximately prestrike levels.

In addition, drilling activity expect to increase in the second half of the year with additional rigs that are being deployed.

As a result the Argentine production is expected to increase about 19,000 BOE a day from second quarter levels.

Libya's production is expected to be 8,000 barrels a day in the third quarter with listings of only about 5,000 BOE a day.

The new contract terms reduce the Company's share of production offset by a reduction in tax rates.

This results in a much more favorable earnings, perhaps two to three times existing levels.

Other operations expected to have an increase in production.

Shown in the Investor Relations slides, the table which provides daily production rate forecast, first using -- using the first six months of this year as a base, production expected to be 610,000 barrels a day in the second half of the year, of 2008, and total growth in 2008 will be 6%.

Due to higher prices we have lost 13,000 barrels a day, which is about 2% of our production versus our original $80 WTI outlook from production sharing contracts.

Production is expected to be 650,000 barrels a day in 2009 and 705,000 barrels a day in 2010.

Our growth rate for both years would be 8% per year.

The cumulative growth rate for the three-year period is 7.3%.

These estimates are all based on WTI price of $111 consistent with the first six months of 2008.

At this price level for every $5 change in WTI, production will be inversely impacted by about 1500 barrels a day.

Recognizing the likelihood for fluctuations and project timing, expect the range of 600,000 to 620,000 barrels a day for the last six months of this year.

640,000 to 670,000 BOE per day in 2009, 690,000 to 720,000 BOE a day in 2010.

Turning to the individual areas, we expect to increase production by expanding our drilling program in Elk Hills and surrounding areas.

We placed up to the Antelope shale and deeper pay zones where we have had recent exploration successes.

We are also planning various enhanced oil recovery projects, such as expansion of the successful Eastern shallow oil zone water flood.

In Ventura County, California, we have an active drilling exploitation program and a deeper pay horizon beneath an existing successful water flood which is also being enhanced.

The Wilmington field in Long Beach we are planning to drill several delineation wells as a follow-up to a deeper exploration success.

In the Mid-Continent Rockies area we're expecting to double our gas production exit rate in Piceance basin by the end of the year from the current levels of 40 million a day to 80 million a day as a result of 2008 drilling program and to 100 million a day in 2009 through expanded development program.

In conjunction with the increased production we are retrofitting our concrete cash plant compression facility to double its capacity to 80 million a day by year end, and to increase it to 100 million a day next year.

We currently have 40 million a day of gas transportation capacity out of the Rockies based on contracts in place we will increase capacity to 100 million a day this year and expect to finalize agreements for an additional 50 million by 2011.

Our joint venture with Plains is also expanding its drilling activity in the basin which should increase production at the current rate of 26 million a day to 36 million a day by the end of the year and 44 million a day next -- by 2010.

In addition we are pursuing oil exploration activity in Utah which we expect to add to our production in that region.

In the Permian basin our ongoing drilling program is being celebrated around several plays to take advantage of the exploitation opportunity from acquisitions over the last few years.

We will expand our workover activity, significantly increasing our service rigs from 155 to 175 in the next few months.

We are increasing our CO2 flood program through additional resources from Bravo Dome together with the drilling program and workover activity is expected to increase our production over the next two years by about 10,000 barrels a day.

By 2010 we should also see positive impact on our production from additional CO2 resources and the recently announced SandRidge transactions which will enable us to increase our production by a minimum of 50,000 barrels a day within the next five years.

In Latin America our near field exploration program in Argentina conditions to be successful.

This has enabled us to identify multiple new drilling locations in addition to those in our current program.

We will achieve significant production growth by expanding our drilling in these areas and other areas with the addition of five high-performance rigs.

In Columbia we expect that the LCI will largely offset the national decline at Canyon Lamone.

Moving to North Africa and Dolphin, the higher prices and success realized to date have resulted in a very rapid pace of cost recovery.

Consequently at the $111 oil price we realize fewer barrels of production going into the future.

Libya's net production will decline a result of the new contract which took into effect at the end of the second quarter.

Based on current pricing we expect earnings to increase two or three times under the new contract.

As a result of our increased capital development program production will increase over the next five years to former levels with much improved profits.

In Oman, development efforts in the giant Mukhaizna steam flood are on track and we expect to exit 2008 at a goes level of approximately 50,000 barrels a day.

Large scale drilling activity in the range of 200 wells per year coupled with the introduction of multiple water treatment facilities that supply the steam generators, allows increased gross production at the rate of 100,000 barrels(Sic -- see presentation slides) a day by year end 2009, and 115,000 barrels per day by year end 2010.

We expect our net production at Oman to double by 2010 to around 54,000 barrels a day.

In Cutter we have agreed with the government on a third phase of development plan for the highest ND field.

This phase entails about 70 low risk infill drilling products as well as further platform and pipeline enhancements over 2008 through '10 time frame.

The third drilling rig has been recently added to perform a large number of rig enhancing workover projects at IS&ND and further development drilling activity expected at the [El Ryon] field beginning in late 2008 and 2009.

We expect these additional development activities to increase Oxy's net production Cutter by as much as 20% over -- by 2008 over 2008 -- by 2010 over 2008 levels.

Yemen's production reflects a base decline on the Masila field.

It's important to note that this forecast is based on existing projects and does not contemplate any new projects or future acquisitions.

A copy of the press release and our schedules are available on our website or through the EDGAR system.

We're now ready to take your questions.

(OPERATOR INSTRUCTIONS) Your first question is coming from Paul Sankey of Deutsche Bank.

Good morning, Steve.

Good morning.

Steve, you've stepped up here in terms of giving us the kind of detail we wanted to see on growth.

You also had an an announcement on buyback.

Could you just go through the (inaudible), strategic decision that you've taken there in terms of how much you want to spend on developing organic growth and how much you would spend on buying back stock given where the stock price is now?

On the stock buyback, organic growth, we'll spend what we need to have on organic growth as long as it works at some reasonable oil price.

I think where the difference will be, it's very difficult right now to do large-scale acquisitions that would compete with buying back stock.

And so the excess cash would be used as long as the stock -- reasonable price, would be used to buy back shares.

So we originally asked for additional authority from the Board was we felt we would run out of authority before the next Board meeting.

I got you.

So that means we can expect to see the buyback accelerating pretty much from here, I guess?

As soon as the window end.

Right.

So basically you haven't been in the market recently because you've been blanked out and it's not ratable.

But based on the time when it closes we would expect to see, therefore, more than 860 million which is the first stock number, obviously, of share repurchase in the second half?

Obviously, you could compute the free cash flow of the Company and for the back half of the year using whatever estimates you want to use.

.

We're not going build cash.

While we will have some smaller acquisitions and the large scale ones.

I think you can get an idea of

The bottom line, we will accelerate the share repurchase through the second half.

Okay, great, thanks, guys.

I'll leave it there.

Thank you.

Next question is coming from Michael LaMotte of JPMorgan.

Thank you for all this detail.

It's great.

Where to start with the questions.

I guess, first in California, if I look at the volume progression in the first half and then look at the increase in commitments to wells and -- rigs and wells how quickly do you think we'll see a production response in that region?

Well, things always go slower than you might like.

As far as production.

They always want to test and fool around.

I think to schedule we've shown hear is a reason reasonably conservative schedule.

We would hope for better results earlier but given the history of it, we'll stay with this conservative view.

Okay.

You can sea it boost in the second half, and then into next year and the year after.

The range that you sea at the bottom, while it has some other things in it is, the upper end of the range is probably some idea where we would hope California would wind up.

Okay.

And then I was intrigued that the 17% increase in CapEx roughly correlates with the increase in wells so it would suggest that you're not seeing much rig inflation or service cost inflation.

We've seen a lot of increase in tubular costs and other equipment and services costs.

Are you booked up with -- are the rigs secured and a lot of equipment procured at this point?

We wouldn't show them unless they were secured.

Very good.

In terms of '0--?

Tubular growth, there's no question that's soaring, but it's a small portion of the total.

Shallow wells then?

Yes.

We drill mostly post holes.

Okay.

Then if I could get you to touch on Elk Hills specifically and sort of what you're learning in the Monterey shale play in that particular field, anything you want to elaborate on there?

Nothing I want to elaborate on.

But we've had some pretty good success, and I think as we expand the program as you see a lot of it is dedicated to that kind of activity, whether it's called Monterey or Antelope, and so we'll have more detail as the year progresses but the initial results are very encouraging.

We have a huge acreage position, not just around Elk Hills, but in California.

So if this works, it probably works pretty good.

Great.

I will end it there.

Thanks, Steve.

Thank you.

Thank you.

Next question is coming from Eitan Bernstein of FBR Capital Markets.

Eitan, your line is live.

Congratulations on strong quarter.

Thanks for the additional detail.

Would you consider levering up and accelerating share buybacks more meaningfully?

Obviously the balance sheet is very, very strong.

Maybe a little more so than is needed.

Having been through a rider for the last decade it's hard for me to say the balance sheet could be too strong.

But we'll just look at the product -- at the stock price and take appropriate actions to ensure that the stock is -- that we're getting good value for the shareholders, which we clearly are at this point.

We couldn't replace any portion of the -- a good sizable portion of the business at what the stock is trading for now implicitly.

So we've got plenty of cash for now and we'll see as we go forward.

Okay.

Great.

Thank you.

Your next question is coming from Bernard Picchi of Wall Street Access.

Good morning.

I'm going to ask about something you didn't talk about in the slides.

By the way, thanks very much for all that information.

It's great.

I know it's early days but Dr.

Irani you said that you are looking at Iraq, and can you give us an idea of what you're looking at in terms of target sizes, whether you're looking in the North or the South and kind of what kind of -- would it be a production sharing contract or a more traditional Western contract?

Kind of give us a little bit more detail, a little bit more color if you could on what you have in mind for Iraq?

Because it could be very important for the Company going forward.

Right.

Let me say a couple words, and I can turn over to Casey Olson.

There are some very large fields in Iraq which are going to be available, and there are smaller ones but which are very significant.

Realistically, the huge ones are going to be run by consortium.

A consortium would have majors in it, and companies our size.

So we will be trying to be participating in those large ones.

What I'm really saying is no one Company is going to get a feel with 20 billion barrels or more, period.

So we will be participating with some of the super majors and looking at some of the large formations.

This may take time and thought.

But we're also looking at some of the smaller fields where we could do them by ourselves.

Now, all of this depends on new registration, whether (inaudible) situation takes place, Afghanistan, da, da, da, and so it is tough to say when all this is going to happen but it's moving in the right direction and we just wanted to share with you that we have been prequalified, and that we are serious about the opportunities.

When that's going to happen, I'm sure all Americans would like to know.

Casey, would you add to that?

Sure, the -- even back to the late 1980s as a Company we were very actively looking at Iraq and heavily engaged in detailed negotiations on various areas in the country.

Unfortunately most of that went south with the problems between Kuwait and Iraq, then subsequent history has occurred since then.

Dr.

Irani's comments are exactly correct.

I think the other thing to point out is the Iraqis are, as you probably know, looking at a formal process.

They have identified eight or so of the giant fields in-country that they're going to work through a formal bidding process with the industry, probably starting later this year and going through a good part of next year.

Based on our previous work in the country, we actually have a pretty good handle on what those fields are what potential they might have, et cetera.

I think we're very well positioned because of our work with the ministry years ago.

And like many countries, a lot of the key technical people in the ministry are still the same folks that were there before, so we have an excellent relationship, a good solid understanding of what the potential is and certainly are going to be very aggressive in participating in whatever process the Iraqis decide to follow through on.

Thank you.

Your next question is coming from Robert Kessler of Simmons & Company.

Good morning, guys.

I appreciate it as well as the others on the incremental detail you provided.

I'm curious.

I suppose we could say that this incremental $700 million of spending is marginal by definition given that it came late in the year and with an eye towards higher crude prices, but with that said I imagine the returns are still quite robust.

Can you characterize the average, say, internal rate of return on these new investments relative to your base program and perhaps something with a payback period or something like that?

I think one of the things that you want appreciate is some of this low laying fruit, we talked about earlier, if oil prices is still over $100, you're looking at payback of six months or less.

Some others are more intermediate and some are longer term.

But anyway, we're going to pick up the low laying fruit and Steve, would you add to all that?

Well, we're sort of embarrassed to say that the rates of return on these items are well over 100%.

And actually the returns are better the underlying returns in the Company and you get paybacks -- the workover rig is hardly off the well before you get paybacks.

You get paybacks in a lot of these things under 90 days.

So rates of return are spectacular.

Even in product price environments well below current levels.

Any thoughts on average production per well or average reserves added per well?

No.

I mean, yes, we have got thoughts, but we're not going to share them with you.

Fair enough.

Thank you.

Your next question is coming from Erik Mielke of Merrill Lynch.

Several questions if I may.

Firstly on the CapEx increase.

For 2009 and 2010 is the 2008 level, is that a good place to start?

And also, from what you've been talking about, the enhanced recovery, some of the short-term -- short pay back period projects, what would the impact be on operating costs more from the modeling perspective?

I guess you have two questions.

What's the capital going forward, if we can estimate it, is that right?

Correct.

2009 and 10, is that right?

Yes.

I would take the -- some version of this year, maybe increased a little.

It might approach 5 billion.

We don't know exactly.

But some of that's things will go away and change but we could wind up with a 5 billion, including chemicals and midstream.

The second question was operating costs.

Correct.

The -- we're likely to have more expense workovers in the back half of the year, because we're accelerating some backlog of those.

And so you're likely to boost your operating costs for the whole Company of under $1 a barrel, but certainly $0.50 to a $1.

Deliberate policy.

To spend $1 a barrel to get $100 net, even if it's $2 or $3 on the well, or $5 on the well, seems to us to be okay economics.

Sure.

Do you have a rough idea of what the impact will be on your reserved bookings for 2008 based on the program that you've announced?

No.

I mean, the answer to your question is yes, we do, but we don't forecast reserve bookings.

That's not something we're capable of forecasting from year to year.

But I would say we are comfortable that we will more than replace the 100% of our production this year.

Can I ask a follow-on question.

You mentioned very briefly the acquisition you made in the oil sands in Canada.

How should we think about this project strategically?

I'm sure there are other companies that would have run a rule over the project when the asset was for sale.

Should we think of Oxy as potentially seeing other oil sand fields and is there a need for you to integrate downstream if you are going to be doing more oil sands?

There are some pretty expensive refining assets available.

As far as refining assets we don't have any current plans for any refining assets.

Actually, there were very few companies interested.

It was a very -- because people felt that the current operator would want the property, which they did, and we paid very little more than the current operator offered for it.

We expect to have a good relationship with Totale and participate in market in crude with them, so I don't see us going downstream.

And are you looking for--?

We would view this as not -- you shouldn't view -- we're not capable of operating this kind of activity so if there were other interests available, non-operated interest with competent operators, we would be interested in that.

But as you know, we did emphasize, and maybe we should again, that not all of oil sands are oil sands.

This is very high quality oil sand area, and the opportunity came along, and even though it's longer term than we'd like it to be working on, it's a unique opportunity, so we decided to make the investment.

And it gives us an option value because we know we can flip it easily if we had to in the future.

It's not our intent at the current time but it gives us an optionality to participate and understand this activity better.

Remember, these oil sands ultimately affect our ability to market our production in West Texas.

So I think it's important for us to understand the flows of oil in North America and plan our marketing appropriately to keep our differentials low.

Thanks so much.

Thank you.

Next question is coming from Pavel Molchanov of Raymond James.

Just a follow-up on discussion about Canada from the prior question.

Are you looking to build kind of a core position in either the oil sands or perhaps in Canada outside of the oil sands, or should we think of this as more of a one-off investment?

We're not building a core position.

We're not building a core position in Canada, but as we said, this opportunity came along, and it's rather unique, and so we took advantage of that, and we will see in the future.

If there's other opportunities of this kind, we'll look at them.

But it's not the beginning of an avalanche into Canada or into oil sands.

It is part of our North American production.

Understood.

Thanks very much.

Thank you.

Your next question is coming from Mike Jacobs of Tudor Pickering Holt.

Just a quick high level CapEx question.

Clearly your rates of return in California and the Permian business were pretty economic at lower prices so understanding what you said about the low hanging fruit and thinking about the rationale for boosting domestic spending now is it solely a function of higher commodity prices or have you learned something new that deserves capital?

No, I think really it's a multiplicity of things.

One of them is, we were wanting to do this earlier.

These projects would have been very attractive at lower oil prices, much lower oil prices, in some cases we were accumulating acreage and we didn't want to get the price of land going up.

In other cases folks were working on the facilities in terms of getting best shape, safety, et cetera, and now we are moving along to capitalize on acquisitions we made earlier and money we spent on facilities and to explore acreage we've accumulated over a number of years.

These are not worse projects than our average.

They'd work at $50.

Just delving a bit deeper, does your CapEx include any capital for the proposed seismic shoot or is that just drilling CapEx?

The seismic would show up in the exploration program, so it's included.

Thanks.

Your next question is coming from Faisel Khan of Citigroup.

Just a question on Elk Hills.

You talk about the deeper pay zone where you've had decent exploration success.

Can you elaborate more in terms of what are the deeper pay zones?

How deep are you drilling and what are those well costs?

They're not expensive.

These are deeper compared to post holes, that's all.

It isn't to the bowels of the Earth.

This is directly below the Antelope shale?

It's in that area.

Okay.

We're talking not expensive wells.

Expensive compared to Elk Hills, but we're not talking about 15,000-foot wells or anything like that.

Are the recovery rates in terms of the well recovery rates the same as what you were experiencing before?

Are these larger wells or larger targets?

These are more productive than the average Elk Hills wells by a significant amount.

You also talked about drilling delineation wells for a deeper exploration success in Long Beach.

Can you talk a little bit about that?

Is this a larger target, or is this going to keep production kind of flat from your Long Beach production?

No, this is a sizable target.

So it has the potential to grow it in the total.

So this would grow your thumbs production you're saying, right?

Thumbs and some other things.

We've been accumulating down in the Wilmington field for awhile.

But you know we do have to discuss with the State of California to get their approval on this because they do have some ownership to some of that oil in the Long Beach vicinity.

And how difficult is that to do?

Well, nothing is easy, but we're talking.

Because it's a win-win for everybody.

But what I'm saying is this is not as easy to exploit as Permian and Elk Hills where the -- it's a different atmosphere.

Long Beach is kind of a vacation spot, so being developed as such.

No problems, but that will probably come at a slower pace than the Permian where we think we can get quicker execution than in Elk Hills, where we continue to exploit the success we've had in the large acres position that we have accumulated.

Are these deeper exploration wells part of your growth plans in California, so if I look at your production growth target through 2010, would these targets be in that exploration, that production growth plan?

A highly risk portion of them.

Understood.

And then in terms of your Permian basin CO2 enhancement projects, with the new sandwich deal how should we think about how those reserves get booked, because I think previously in the past you told us that as you find a way to get CO2 to your flooding project, that's when you start looking at booking some of those reserves.

So if you can elaborate how that works.

In order to book a reserve, isn't just a physical barrel being there, but you have to be committed to do it and have in this case a CO2 supply firmly committed.

We don't know exactly the pace, but I would not -- I would expect that would it come over several years rather than all in one year.

Fair enough.

Thanks for the time, gentlemen.

Our next question coming from Doug Leggate of [Quadrant Capital].

I want to probe on a couple things if I may.

Forgive me for going through reserves in a little bit of detail, but Argentina, it sounds like you're cranking up the CapEx and drilling activity a little bit but you haven't, as far as I know, re-signed the lease there yet.

Can you kind of update us s to where you are there and -- because obviously that comes with some pretty significant reserve bookings.

Similarly, on Libya, and just maybe give us a kind of magnitude or some kind of feel for the lumpiness that we could seeing the reserve this year.

Because it looks like it could be a pretty big year if you add a lot.

Starting with Argentina, we're negotiating with the state province, and negotiating with governments is never easy to predict.

That's why I mentioned California easier.

Makes Long Beach look easy.

So we don't know the answer to that.

Obviously it would be a fairly sizable reserve, because if you took the PDPs and just extended them out it's a fairly sizable number.

In Libya, going back to the definition of approved reserve you really have, in order to book puts, you have to have government commitment and our commitment to spend the money.

So the rate of booking would be reflective of those levels of approval.

Okay.

You shouldn't expect to see it all at once.

And the US, the impact of SandRidge and the impact of California, that's more ratable over a number of years?

Ratable over a number of years.

So you ought to see, if you were to think about it, you would see over the next, this time frame, 2010 time frame, pretty safe reserve replacement levels over the years.

Good.

Just two other quick ones.

Libya, I know you've signed a deal.

How do you catch up the earnings from December 1, last year?

How do you go about getting that through?

We expect to get a check.

Okay.

That will come probably in the third quarter?

Well, we expect to get a check.

Probably in third quarter.

That's kind of cash, and then it's a one-timer to catch up on the profits.

It would show up as a reduction in the bonus.

Okay.

Final one is, I guess the focus of this -- the call today appears to be clearly the great success you've had or are having in the U.S.

It seems to be taking the shine off the Middle East a little bit.

I think there are some concerns that maybe things aren't going so well there in terms of your ability to lock in new projects.

Could you maybe just spend a little bit of time updating us on where you are, particularly in, obviously the [Amaretsu] mine and Bahrain and how you see things going forward?

Well, I think the things we've tried to do in this call is to give you news.

Bahrain, we continue to be optimistic that we will see success there.

We've continued to talk with them and they have set a time schedule where they hope before the end of the year to choose one of three people who have made the cut, and those three are Oxy, Exxon, and Maersk..

So we just to have wait that.

As I said we're optimistic but there's nothing new I can tell you on that.

We continue to negotiate on Oman and elsewhere for projects but nothing I can tell you that it's going to happen next week or next month.

These things, we repeatedly say governments negotiate very slowly.

Okay.

I guess just one follow-up real quick.

Steve, you said $5 billion could be the CapEx number.

Would that take account of any success in the Middle East or would there be -- could that number go higher?

I seem to recollect you saying that that's kind of where we'll--?

It might go higher.

I think right now you'd have to say that's a reasonable guess, but I would call it purely in the guess area.

If we have more success we're going to spend more money because that's just the deal.

But you shouldn't -- if we are spending more than that, then these numbers we're showing you on production are too low.

Remember, we demand high returns.

And we have enough of those to tell you that we're going to grow production over the next three years faithfully but over 7%.

Hopefully we will conclude projects domestically and elsewhere that have very good returns.

We demand.

So the growth could be faster.

So increased capital should always be understood in the case of Oxy to mean higher growth and projects that have outstanding returns.

We do still like free cash flow.

(OPERATOR INSTRUCTIONS) Your next question is coming from Michael LaMotte of JPMorgan.

Thanks.

I just had a quick follow-up on the comments throughout the presentation on strategic acquisitions.

It really does strike me with this kind of organic growth, and Steve, as you put it, in the last meeting, doing more with what you've got, and the opportunity now in the buyback, your comments on bigger deals that by strategic you're really -- we're talking pretty small.

Is that a fair interpretation in terms of what your appetite is today?

Given where the stock is, it would be challenging to find a sizable acquisition that was--.

Give us better return than buying our own stock.

It's hard -- I'm not saying it's impossible.

I just don't have one in my mind right now.

Do you have -- the returns on the oil side, again, doing more of what you've got seem to be great relative to even the gas plays and acreage opportunities that are out there.

Do you have any thoughts or comments on gas versus oil in terms of--?

They're just about money.

I don't believe in 6 to 1 as you, I'm sure, know, but sort of 10 to 1, it's really about money.

We're very pleased with the Piceance play.

That's developing very nicely.

The production is coming along, the reserve booking is coming along, supply, being able to ship it in little differentials is coming along.

There's a lot of acreage there that we have, so we're very pleased with that gas play.

We think there's some nice gas plays in the Permian that we haven't really worked on much.

We think we'll do okay there.

Going to fool around with stuff, if you look at acquisitions you say, well, why are you acquiring it?

You're acquiring it because you have expertise to make it work.

Other companies have better expertise than we do in some of these plays so I think with the where the stock price is today, pretty hard to make a sizeable thing like that work.

You do to have move the needle on these numbers to spend that kind of money.

Then lastly, going back to California, some of the newer zones that you're targeting within the shales, et cetera, I know it's light oil.

Is the gas-oil ratio any different from what you've seen in the conventional?

It's a little gassier.

Little gassier.

Thanks.

Thank you.

There appear to be no more questions at this time.

I would now like to turn the floor over back to Christopher Stavros for any closing remarks.

Well, thank you very much for joining us today and we do appreciate all your questions and please call us here in New York if you have any follow-up issues that you would like to discuss.

Thanks again.

Have a great day.

Thank you.

This concludes today's Occidental Petroleum financial quarter 2008 earnings conference call.

You may now disconnect.