西方石油 (OXY) 2010 Q2 法說會逐字稿

Good morning.

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

I would like to welcome everyone to the Occidental Petroleum second quarter 2010 earnings release conference call.

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

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

(Operator Instructions).

Thank you.

Mr.

Stavros, you may begin your conference.

Thanks, Christy, and good morning, everyone.

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

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

Ray Irani, Oxy's Chairman and CEO, Steve Chazen, President and CFO, Bill Albrecht, President of Occidental's US Oil and Gas operations, and Sandy Lowe, President of our International Oil and Gas business.

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

I am now going to turn the call over to Steve who will review our second quarter and first half 2010 financial and operating results.

Steve, please go ahead.

Thank you, Chris.

Net income was $1.1 billion or $1.31 per diluted share in the second quarter of 2010 compared to $682 million or $0.84 per diluted share in the second quarter of last year.

There is a segment breakdown for the second quarter.

Oil and gas second quarter 2010 segment earnings were $1.9 billion compared to $1.1 billion for the second quarter of 2009.

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

Realized crude oil prices increased 36% in 2010 and domestic natural gas prices improved 46% for the second quarter of 2009.

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

Worldwide oil and gas production for the second quarter of 2010 was 743,000 barrels of oil equivalent per day, an increase of 3.5% compared to 717,000 BOE a day in the second quarter of last year.

Second quarter of 2010 production was lower than our guidance due primarily to shortfalls in California and adjustments resulting from the mechanics production sharing contracts in the Middle East.

Our production in California continues to be affected by the gas plants' and related infrastructures' inability to process all the gas that could be produced.

Also, this affects the liquid that are associated with this production.

Year-over-year production was negatively impacted by 29,000 BOE a day in the Middle East/North Africa, Long Beach and Colombia, as a result of higher oil prices affecting our production sharing and similar contracts.

Second quarter 2010 production includes volumes in Bahrain of 3,000 barrels of oil, 161 cubic feet of gas, and 16,000 BOE a day higher volumes in the Mukhaizna field of Oman.

Our domestic operations added 11,000 BOE.

Volume gains in the Kern County discovery area were moderate rated by production declines in Elk Hills which was caused by gas gathering and processing issues.

Exploration expense was $73 million in the quarter.

Oil and gas cash production costs excluding production and property taxes were $9.90 a barrel for the first six months of 2010.

Second quarter 2010 per barrel production costs were slightly lower than this figure.

Last year's 12-month costs were $9.37 per barrel.

The increase reflects $0.30 a barrel higher CO2 costs due to our decision to expense 100% of injected CO2 beginning in 2010 and somewhat higher field support operation and maintenance costs.

Taxes other than income were $1.80 a barrel for the first six months of 2010 compared to $1.60 for all of 2009.

These costs are sensitive to product prices reflecting the effect of the higher crude and gas prices this year.

Chemical segment earnings for the second quarter of 2010 were $108 million.

Second quarter results reflected improvement for the first quarter in 2010 in margins and volumes across most product lines.

Midstream segment earnings for the second quarter of 2010 were $13 million compared to $63 million last year.

The decrease in earnings was mainly due to a pretax $104 million $0.07 per share after taxes loss at Phibro, the bulk of which result from marking its quarter-end open positions to market.

This is partially offset by higher margins in the marketing, gas processing and pipeline business.

The worldwide effective tax rate was 43% for the second quarter of 2010.

Let us turn briefly to our first six months results.

The net income was $2.1 billion or $2.61 per diluted share for the first six months of 2010 compared to $1.1 billion or $1.29 per diluted share for the first six months of 2009.

Capital spending for the second quarter of 2010 was about $865 million and $1.7 billion for the first six months.

The year-to-date capital expenditures were segment by segment were 81% in Oil and Gas, 13% in Midstream and the rest in Chemicals.

Our total year capital expenditures is estimated to be about $4.5 billion.

The capital spending rate will increase in the second half of the year largely from Iraq, Bahrain and California.

Cash flow from operations for the six months 2010 was $4.3 billion.

We used $1.7 billion of the Company's cash flow to fund capital expenditures, $460 million in acquisitions, and $300 million on foreign contracts.

These investing cash flow uses amounted to $2.5 billion.

We also used $540 million to pay dividends and $300 million to retire debt.

These and other net cash flows increased our $1.2 billion cash balance at the end of last year by $1.1 billion to $2.3 billion at June 30th.

The first six months free cash flow after capital spending and dividends but before acquisition activity and debt retirements was about $2.1 billion.

The weighted average basic shares outstanding for the six months of 2010 were 812.3 million and weighted average diluted shares outstanding was 813.7 million.

Our debt to capitalization ratio was 8% at the end of the second quarter.

As we look ahead to the current quarter, we expect oil and gas production and sales volumes to be in the rage of 750,000 BOE to 760,000 BOE a day at about current oil prices.

Volume increases in the third quarter expected to come from California, Oman's Mukhaizna field and Dolphin.

With regard to prices of current market price of $1.00 per barrel change in oil prices impacts oil and gas quarterly earnings before income taxes by about $37 million.

The average second quarter WTI price was $78.03 per barrel.

A swing of $0.50 per million BTUs in domestic gas prices had a $30 million impact on quarterly earnings before income taxes.

The current NYMEX gas price is around $4.80 in MCF.

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

For the chemical segment modest volume and margin improvement is expected over second quarter levels for chlor-alkali and vinyl products.

The chemical segment is expected to provide earnings for the third quarter of about $125 million.

While the domestic market continues to be lackluster, export volumes are up about 13% compared to 2009.

Chlorine exports are averaging about 42% of total production.

We have successfully renegotiated and extended our hydro carbon concessions of the Santa Cruz province of Argentina increasing our oil and gas reserves from 129 million-barrels to 202 million-barrels.

The current quarter DD&A expense reflects the resulting decrease in the DD&A rate.

We have recently negotiated a number of asset acquisitions in the oil and gas business that in aggregate would be about $1.5 billion.

We expect these acquisitions are mainly from private individuals largely in the gasser parts of the Permian basin where there have been several more much more expensive deals recently announced.

When the acquisitions are concluded, they will add to production mostly in the Midcontinent business unit, which include these parts of the Permian Basin.

Virtually all of the improvement in the production rate will be in subsequent years.

We expect our combined worldwide tax rate in the third quarter to be about 42%.

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

During the first half of the year, we drilled six conventional exploration extension wells in California.

Of these, five currently outside the Kern County Discovery area.

Two of these new areas are currently being tested.

In the second half of the year, we are planning to drill two conventional exploration wells to Kern County Discovery area and one exploration well outside this area.

We also drilled seven unconventional exploration wells in the first half of the year of which two were successful and two were being tested.

We plan to drill 15 additional and conventional exploration wells in the second half.

In addition, we have drilled 10 conventional exploitation wells in the current discovery area in the first half of the year and plan to drill 23 more in the second half.

We have also drilled 10 unconventional exploitation wells in California in the first half with 25 more expected to be drilled in the second half of the year.

The skid mounted gas processing plant came online at the end of the second quarter.

The existing main processing plant and related infrastructure continued to have operating issues which are constraining Elk Hills production.

We are in the process of upgrading the infrastructure to alleviate this issue until a new gas plant comes online.

We believe these upgrades will be in place by the end of the third quarter.

Construction in the new gas plant has started and is expected to come online in early 2012.

Copies of the press release announcing our earnings and the supplemental schedules are available on our website at www.oxy.com or through the SEC's EDGAR system.

We're now ready to take your questions.

(Operator Instructions).

Your first question comes from Doug Leggate of Bank of America.

Thanks.

Good morning, Steve.

Good morning, everybody.

Good morning.

I am going to try a couple, Steve, I don't want to hog the line here but Phibro appears to have been really attending for the bulk of at least the miss compared to what the street was expecting.

For a company which is generally quite conservative and having that kind of volatility to earnings, can you speak to what is the danger of us over reacting to this versus what is your intentions in terms of perhaps trying to manage that risk a little tighter and I have a follow-up, please?

We have reduced the amount of their exposure and reduced the bar if you will in hopes of reducing the volatility.

Some of it is he buys long-term contracts and some of of it simply was market-to-market.

Some of it was realized to you can't say that his trading results in the quarter were anything but lousy.

Okay.

I appreciate that.

The other one I have is it really relates to acquisitions.

You have talked about $1.5 billion, just to be clear I assume that means there is no current production with these assets.

No, I didn't say that, no.

So what is the production associated with those assets?

We haven't said because we haven't signed it, completed the deals, but there is some current production of -- fairly compared to the whole business not a sizable amount.

But, certainly in the Permian a fair size amount.

Okay.

I guess what I was driving at here was we were starting to hear about Occidental perhaps getting involved in structured acquisitions overtime because the Marcellus and perhaps the [Mondi] shales.

Can you offer us color what your thought process there and likely scale and timing of you getting involved in those areas?

We have a modest position in the Marcellus which we have had for a while and compared to the size of the enterprise fairly small, and it is out of the way some, and we're basically on the edges of the play, and we'll just see how it evolves over time, but compared to the size of the enterprise, fairly small, fairly small total I would expect.

We'll see how the drilling progresses over the next year or so there to see what we want to do.

Forgive me.

I am going to risk one very last quick one.

Sure.

CapEx was a bit light.

I am just curious how that plays into volumes as it relates to cost recovery because I am wondering if that's one of the reasons your guidance was a little --

Some of the adjustments in the production sharing contracts are a result of not quite spending at quite as quickly and therefore not putting into cost recovery as quick and that's at least some of it.

The bulk of it was that they really didn't get at, I'm not talking about foreign, didn't get at the drilling in the second quarter at the pace that we had planned.

So it is a little more back end loaded, so the wells come on pretty quickly, so some of it was related to production sharing contract capital effects and some of it was related to domestically not getting the drilling done as quickly as one might have hoped.

Nothing terminal in here that you are concerned about?

I am always concerned.

You shouldn't view -- we're not concerned, but I think ultimately is the work itself out a matter of timing and I think a little more focus on short-term results are needed.

Got it.

Thanks, Steve.

I will leave it there.

Our next question comes from David Heikkinen of Tudor Pickering, Holt.

Good morning, Steve.

As I think about your analyst day and providing the primary and secondary opportunity in the Permian versus these acquisitions, can you talk about how you will update the number of locations and kind of that inventory or will you give us some idea of what do you think about the inventory of what you are buying given that you haven't closed any of those deals?

We'll provide aggregate numbers in the next -- after the things are closed.

We're not going to talk about each acquisition because these are private individuals.

These aren't public companies selling or something like that.

These are private individuals who just may not want their neighbors to know they're rich, so I think we'll provide aggregate numbers rather than what each one did.

The mix is -- if you look at them in aggregate and compared to some of the announced deals, these are more reasonably priced.

And the comment in the gasser parts of the Permian, does that also imply more liquids rich or --

They look like the deals that have been announced recently in the mix of around half gas, around a quarter NGLs which are related to the gas, and around a quarter of oil.

That's useful.

And then shifting over to California exploration and kind of the combination of conventional and unconventional tests, as you think about remember some horizontal drilling plans and some testing of horizontals in the conventional side, can you give us any update on the activity?

Bill, do you want to do that?

David, we have two horizontals planned in and around the Kern County Discovery area, have those planned to be drilled and down before the end of the year testing some of the tighter parts of that particular structure.

Okay.

So those are still towards the back half of the year?

They are.

And then as you think about the five drilled outside the Discovery area, you kind of broke down the types of prospects that you're drilling at your analyst day.

Can you talk about that distribution of or categorize those five within the buckets that you described at your analyst day of what types of prospects those are?

I think I broke them down between conventional and unconventional.

Meaning more specifically, kind of getting into the details, you had the larger concepts down to the smaller concepts?

The concepts always start large, just that times they turn out small.

Okay.

Fair enough.

Not going to get the high potential versus Discovery type?

No.

We're shooting for the high potential ones, but sometimes when you drill them they turn out to be a lot smaller.

That's fair.

So the plan is that they're high potential but how they turn out we'll see as the year progresses.

If we find something sizable, we'll tell you about it.

Yep and then just back of the envelope on your acquisitions, a 10% added to your Permian basin production in the acquisition side, is that a reasonable type plus or minus a couple percentage?

If you give us two or three years, yes.

Buying production, up front production is generally the most expensive way to acquire because it is sort of easy to measure.

We try to buy some production but we also try to buy drilling potential because the returns are a lot better.

If you pay ten times current EBITDA for something, the way some people have, it is very hard to make the numbers work from the returns have to come from the development drilling or whatever you want, and so the assets here are a mix of some current production but a fairly sizable backlog of future drilling which will add to the numbers.

Thanks for the perspective.

A question from Robert Kessler of Simmons and Company.

Good morning, Steve.

Good morning.

Any chance I could ask you given the volatility in Phibro earnings this quarter before the net book value at quarter end to confirm that essentially its a long only book?

Essentially, it is long only book.

As far as he didn't short anything.

But he had some initially in the beginning of the second quarter he had some -- he used a past basket of stocks and ETF or something like that to track oil prices, and the for obvious reasons the stocks didn't track the oil prices too well for the stocks that were in the ETF some kind of accident somewhere.

Right.

And so he sort of backed out of that, but the book is our net investments under $200 million at this point.

Okay.

The management there owns a tracking instrument in this, so relative to his net worth even though it is sizable he is feeling the pain disproportionately.

All right.

Okay.

Thanks for giving some order of magnitude on the net exposure then going forward.

In California, at the risk of sort of splitting hairs quarter to quarter when you're in the middle of working out kinks the midstream and adding capacity, any guidance on the degree of up lift in California production and 3Q versus 2Q?

We're expecting to go up from the third to the second.

We expect some of the kinks are already worked out as we go into this month.

I am loathe to predict an exact number because the old gas plant that work well good for a couple of hours and then it won't work so good, so we have had a lot of problem getting it to work the way we would like it to.

Okay.

So maybe excusing the unexpected hiccups and the old plant, the new skid mounted plant you expect to ramp up to full capacity fairly quickly or has it already?

It is essentially there now.

Okay.

Thank you very much.

Next question comes from Arjun Murti of Goldman Sachs.

Hey Steve.

Just a follow-up on some of the language on the conventional California exploration.

Of the I guess five wells drilled outside of the Kern County Discovery which two are testing, just to be clear, those are I realize they're outside of the Kern County Discovery area but are they completely different sort of objectives and targets?

Yes.

And then the two that you will be drilling in the second half within the Discovery area, those are also separate prospects or they could be part of the existing Discovery?

We hope they're extension but they could be separate.

It looks like they're separate, but one can hope that it just makes -- I think you could call them either exploration or exploitation depending on your choice of words.

Great.

And any update on how some of the oiler drilling within the Kern County Discovery area has been going?

Bill?

Yes, Arjun.

It is going just fine.

We're continuing to drill bread and butter oil wells in the Discovery area.

These are generally shallow or shales, and those wells are anywhere 200 to 300 barrel a day kind of wells on average.

That is terrific.

If I missed in your remarks I can read the transcript, but any comments on Colombia production which has been trending down here a little bit?

Some of it is a production sharing contract.

We put a new net a new deal starting this year, so some of the production sharing contract, but some of it is Cano Limon field which is in probably its last decade or so.

Yep.

Okay.

And then just lastly any update on Iraq and spending there this year?

Sandy?

Good morning.

Our rehabilitation plan has been approved, and we're moving ahead with drilling completions, work overs, the Minister of Petroleum and his ministry have expedited the approval of bringing in new rigs and we're going to be remediating some of the facilities to get the production up to the 10% target increase for this year.

Do you have a CapEx in Iraq for this year for you all?

It is uncertain, but it is because the schedule is not exactly nailed down, but it is in the order of 100 million or so.

That's terrific.

Thank you very much.

Probably in the fourth quarter.

It is back end loaded.

Terrific.

Thank you.

Our next question comes from Paul Sankey of Deutsche Bank.

Hi, guys.

Hi.

Did you break out, forgive me if I missed this, but you mentioned 2Q production was lower than guidance.

Did you split how much is California and how much was PSCs in the Middle East?

We actually didn't because I probably started when I estimated the guidance I started with a different number than I gave you.

I started with essentially a higher number, so I can't really tell you how much was this and how much is that.

I think for the PSE effects we lost 8,000 to 10,000 a day.

That's the Middle East and PSCs, not the California ones obviously?

California ones are pretty small.

These are really not caused by the price as much as just a contract -- a recalculation of our cost pools.

Yes.

Okay.

And again I am not sure if you mentioned in response to an earlier question but have the infrastructure issues had a knock on impacts on the activity levels that obviously you are ramping up quite aggressively, but I was wondering if there was effectively a knock on slowdown that occurs because of the problems you are having with the infrastructure?

We're planning that the infrastructure is going to be fixed and therefore the drilling will move forward.

Right.

So you just continuing to drill.

Does that mean you are going to have essentially stranded production until the infrastructure is fixed or how will that work out?

The hope and the belief is that that won't happen, that infrastructure will be fixed but it is possible you could have shut-in production for short periods of time and that's where we are now effectively.

Great.

Thanks.

Just to follow up on Iraq, there was some word that you might be pursuing further opportunities there in the relatively short-term.

Is there anything more to say about that beyond what you have already signed and I will leave it there.

Thanks.

I think it is in the very early stages if anything happens.

Thanks, Steve.

Your next question comes from Monroe Helm of Barrow Hanley.

Thanks a lot but my questions have been already answered.

Thank you, Monroe.

Your next question comes from Vidula Merke of CVP US.

Hello.

Your line is open.

Can't hear him.

Your next question comes from David Neuhauser of Livermore Partners.

Hey, good morning, gentlemen.

Good morning.

With price being relatively stable now in this band, $60 to $80, what's the biggest issue here as far as how you are going to ramp up production going forward?

Is that the biggest hurdle?

Product price?

Production, with price being stable are you focusing more on production and looking for growth there is that going to come more still from organic or are you still focused on some areas of acquisition?

The Company is always followed a balanced approach.

You buy stuff when you can buy it at a reasonable price.

And when you can't, you can't.

So we have plenty of financial flexibility, but most of the growth will come from organically over the next few years.

You might pick up something, but it is pretty hard to tell.

Is the difficulty just valuation and valuation is still relatively pretty high?

We're seeing some sort of carve out of some assets of some other companies, and does that potentially present an opportunity or are you really still focused on sort of the smaller private players?

We're focused on generating value for the shareholders.

If you do a dilutive to value deal you're going to destroy value, so somebody else may have different stock with different kinds of value in it.

If you pay ten times EBITDA for production, you have a high hurdle to generate future growth in order to pay for that kind of acquisition.

If you pay 50% more than the next guy is willing to pay for some asset, you probably haven't added value to the Company unless you have some special insight, so we look for opportunities where there is some reason why we can have a competitive advantage.

Some of it we have in the Permian because of costs and such, but the purpose of the exercise to make the acquisition is to make the Company better, not worse.

So we're not trying to dumb down the Company.

We're trying to strengthen the business.

Of course.

But with some of the private companies you're seeing better value as far as multiples as far as what you are willing to pay, you're seeing those with the smaller?

That's right.

Sometimes it works the other way where the large deals are more better, and sometimes it works the other way.

For example, in the Arco Permian assets we bought out Permian the last seven or eight years - two packages out there basically buying all the true oil out of the packages, so what's left is sort of the residual after it has been picked over.

Nothing wrong with the properties, but the price paid was the full price.

My last question really is more on looking at more of a macro question, looking into 2011, potentially 2012, again price being stable, if it stays in this band, what are some of the biggest challenges for a company like Oxy's?

Efficiently spending our capital.

Remember while we're oily there is a fairly sizable gas component and whatever it is, $4 and change we would hope that the price of gas would be less stable and more up.

All right.

Thanks a lot, guys.

Appreciate it.

(Operator Instructions).

Your next question is from John Herrlin of Society General.

Hi, Steve.

You're back.

Yes, I am back.

With respect to your unconventional drilling, could you characterize what worked and what didn't work?

Is this primary symmetric or is it digenetic or can you tell us what you found so far?

I think generally we're looking for natural fractures that are there, and we're trying to define a technique to figure it out before we drill the well.

Sometimes it works okay and sometimes it doesn't.

It is fundamental truth that the natural fracking process is got us cheaper than Halliburton, and so our natural frac -- we're looking for the flow from natural fractures, and we're trying to figure out what the amount of acreage we have.

We should have plenty of opportunities to find that rather than spending a boat load of money to do a high -- a large scale frac.

We'll probably try some large scale fracs because there is a lot of pay here but the goal in the unconventional is to find areas with natural fracturing so that it is more economical to produce.

Always come back and try something more exotic later.

What's the orientation of the beds and also are you looking at say [nosis] or crests of folds, innings like that to get more fracture?

We're looking for things around the fields that have been flexed, cleverly figuring the flex or there might be some fracturing.

Great.

Next one, what's reasonably priced?

What's your definition of reasonably priced given recent transaction prices?

It is accretive to the company's value.

Okay.

You won't specify?

That's fine.

Anything going on in the Hugoton with respect to the oil drilling?

Hugoton oil drilling, Bill?

Yes, John, we've got two rigs running, drilling mainly these higher rate of return oil opportunities as opposed to the traditional shallow gas that you have generally seen in the past in the Hugoton, but we have a two rig program going there and we expect to continue that throughout the rest of this year.

Okay.

Last one for me, with respect to acquisitions, you have already opined a little bit about, Steve, what about Argentina?

Would you want more there since there is acreage available and production available?

We'll be cautious in Argentina I think is the best way to say it.

Great.

Thank you.

Thanks .

I will turn the call back to management for closing remarks.

Thanks very much for dialing in.

If there is no further questions feel free to give us a call here in New York.

Thanks again and have a great day.

Thank you.

This does conclude today's conference call.

You may now disconnect.