西方石油 (OXY) 2012 Q1 法說會逐字稿

Good morning.

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

At this time I'd like to welcome everyone to Occidental Petroleum's first-quarter 2012 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.

Mister Stavros, you may begin your conference.

Thank you, Christy, and good morning everyone, and welcome to Occidental Petroleum's first-quarter 2012 earnings conference call.

Joining us on the call this morning from Los Angeles are Steve Chazen, Oxy's President and Chief Executive Officer; Jim Lienert, Oxy's Chief Financial Officer; Bill Albrecht, President of Oxy's Oil and Gas Operations in the Americas; Sandy Lowe, President of our International Oil and Gas Operations; and Oxy's Executive Chairman, Dr.

Ray Irani, is also joining us on the call today.

In just a moment, I'll turn the call over to our CFO, Jim Lienert, who will review our financial and operating results for the first quarter of this year.

Steve Chazen will then follow with comments on our key performance metrics, our capital program, oil and gas production, and outlook for the current quarter.

We will also be providing some new information on our activity and exposure in select Permian Basin plays, and, on a one-time basis, some additional data on our California production volumes.

Our first-quarter 2012 earnings press release investor relations supplemental schedules and the conference call presentation slides, which refer to both Jim and Steve's remarks, can be downloaded off of our website at www.oxy.com.

And I'll now turn the call over to Jim Lienert.

Jim, please go read.

Thank you, Chris.

Net income was $1.6 billion or $1.92 per diluted share in the first quarter of 2012, compared to $1.5 billion or $1.90 per diluted share in the first quarter of 2011.

Several factors lowered earnings during the first quarter by about $0.05 per diluted share.

These factors included higher insurgent activity in Colombia, resulting in pipeline interruptions; a maintenance related shutdown in Qatar; field shut-in due to labor disputes, which shut down the pipeline in Yemen; and inclement weather at our Elk Hills operations, partially offset by additional oil entitlements in Libya related to the initial startup phase of operations after the 2011 civil unrest.

Here's a breakdown for the first quarter -- in the oil and gas segment, the first-quarter 2012 daily production of 755,000 barrels per day was the highest in the Company's history, and was up over 3% for the same period of 2011.

We are the largest liquids producer in the US lower 48, and grew our oil production in the first quarter of 2011 by 10% to 244,000 barrels a day.

Our total domestic production was 455,000 barrels per day, the sixth consecutive domestic volume record for the Company, in line with our guidance of 455,000 to 459,000 barrels per day.

Inclement weather, which resulted in numerous power outages in California, reduced Elk Hills gas production by about 11 million cubic feet per day.

Our total domestic production was about 13% higher than the first quarter of 2011.

Latin America volumes were 26,000 barrels per day.

Colombia's production of 24,000 barrels per day was about 7,000 barrels lower than its typical production capacity, due to higher insurgent activity that resulted in pipeline interruptions.

In the Middle East region, Libya production was 20,000 barrels per day, which included additional entitlements related to the post-2011 civil unrest period.

In Iraq, we produced 5,000 barrels per day, a decrease of 4,000 barrels from the fourth-quarter volumes.

The lower volume is directly related to reduced spending levels.

Yemen daily production was 17,000 barrels, a decrease of 6000 barrels from the fourth quarter.

The decrease reflected the expiration of the Masila Field contract in mid-December, partially offset by the timing of cost recovery volumes, which are typically higher in the first half of the year.

In Oman, the first quarter production was 74,000 barrels per day, a decrease of 2,000 barrels from the fourth-quarter volumes.

The decrease was attributable to operational issues.

In Qatar, the first-quarter production was 72,000 barrels per day, a decrease of 4,000 barrels over the fourth quarter volumes, resulting from a maintenance shutdown in March.

For Dolphin and Bahrain combined, daily production increased 3,000 barrels from the fourth-quarter volumes.

As a result of higher year-over-year average oil prices and other factors affecting production, sharing, and similar contracts, first-quarter 2012 production was lower by 10,000 barrels per day from the first quarter of 2011.

These factors did not materially affect production compared to the fourth quarter of 2011.

Our first-quarter sales volumes were 745,000 barrels per day.

The 10,000 barrel-per-day difference, compared to the production volumes, is larger than the typical difference between production and sales, and was due entirely to the timing of liftings, almost all of which was related to Libya and Iraq.

First-quarter 2012 realized prices were mixed for our products, compared to the fourth quarter of the prior year.

Our worldwide crude oil realized price was $107.98 per barrel, an increase of 8%.

Worldwide NGLs were $52.51 per barrel, a decrease of about 5%.

And domestic natural gas prices were up $2.84 per MCF, a decline of 21%.

Realized oil prices for the quarter represented 105% of the average WTI and 91% of the average Brent price.

Realized NGL prices were 51% of WTI, and realized domestic prices were 100% of the average Nymex price.

The NGL realization is low by historical standards and indicates a troubling trend.

Over the last five years domestic NGL realizations have dropped from about 73% to 52% of WTI.

Absolute realized price of NGLs is not significantly different than five years ago.

Price changes and current global prices affect our quarterly earnings, before income taxes, by $36 million per $1 per barrel change in oil prices; and $8 million for a $1 per barrel change in NGL prices.

A swing of $0.50 per million BTUs in domestic gas prices affects quarterly pre-tax earnings by about $35 million.

Oil and gas production costs were $14 a barrel for the first three months of 2012, compared with last year's twelve-month cost of $12.84 a barrel, and fourth quarter of 2011 costs of $14.22 a barrel.

The cost increase reflects higher well maintenance activity.

Taxes other than on income, which are directly related to product prices, were $2.49 per barrel for the first quarter of 2012, compared to $2.21 per barrel for all of 2011.

First-quarter exploration expense was $98 million, in line with our guidance.

Chemical segment earnings for first quarter of 2012 were $184 million, compared to $144 million in the fourth quarter of 2011, and $219 million for the first quarter of 2011.

The sequential quarterly improvement was primarily due to stronger domestic demand for polyvinyl chloride, brought in part by the unseasonably mild weather, resulting in an earlier start to the construction season and rebuilding a downstream inventories.

The year-over-year decrease was primarily a result of lower export volumes and higher raw material costs, in large part caused by a rapid increase in ethylene prices.

Calcium chloride sales volumes for de-icing applications were significantly lower, due to the mild winter weather.

Midstream segment earnings were $131 million for the first quarter of 2012 compared to $70 million in the fourth quarter of 2011.

The improvement in earnings was in the marketing and trading businesses.

The worldwide effective tax rate was 42% for the first quarter of 2012; an increase over our guidance was due to higher Libya liftings.

Our first-quarter US and foreign tax rates are included in the investor relations supplemental schedule.

Cash flow from operations for the first three months of 2012 was $2.8 billion, representing a $600 million increase from the first quarter of 2011.

We used $2.4 billion of the Company's total cash flow to fund capital expenditures, and about $375 million to pay dividends.

We also used about $300 million of cash for working capital during the quarter.

There were no significant acquisitions during the period.

These and other net cash flows resulted in a $3.8 billion cash balance at March 31.

Capital expenditures for the first quarter of 2012 were $2.4 billion, slightly lower than the run rate incurred in the fourth quarter of 2011.

Year-to-date capital expenditures by segment were 84% in Oil and Gas; 14% in Midstream; and the remainder in Chemicals.

The weighted average basic shares outstanding for the three months of 2012 were $810.5 million.

And the weighted average diluted shares outstanding were $811.3 million.

Our debt to capitalization ratio was 13%.

Copies of the press release announcing our first-quarter earnings and the investor relations supplemental schedules are available on our website, or through the SEC's EDGAR system.

I'll now turn the call over to Steve Chazen to provide guidance for the second quarter of the year.

Thank you, Jim.

Oxy's first-quarter 2012 production set an all-time record for the Company.

And for the six consecutive quarter, the domestic oil and gas segment produced record volumes.

First-quarter domestic production of 455,000 barrel equivalents a day, consisting of 316,000 barrels of liquids, 834 million cubic feet a day of gas, was an increase of 6000 barrel equivalents per day compared to the fourth quarter of 2011.

All of the domestic production growth in the fourth quarter was in liquids, which grew from 310,000 barrels a day to 316,000.

Gas production was flat.

Compared to the first quarter of 2011, our domestic liquids production grew by 35,000 barrels per day, and gas production by 100 million per day.

As you may recall, Oxy is a large producer of liquids in the lower 48 states.

Focusing on the total return for shareholders in February, we increased our dividends by $0.32, or 17%, to $2.16 per share.

Our annualized return on equity for the first three months of 2012 was 16%.

And our return on capital deployed was 14%.

During the quarter, the Company generated cash from operations of $2.8 billion, 25% increase from the same quarter last year.

In the first quarter, our capital spending was $2.4 billion.

The current capital run rate may come down over the course of the year, as certain projects at the Elk Hills gas plant are completed.

In addition, as I indicated in the last quarter's conference call, we will review our capital program around mid-year, and adjust as the conditions dictate.

Following the geographic overview of the program -- domestically, in California, the rig count at the end of the first quarter was about the same as the 31 we were running at year-end 2011.

We expect the rig count to remain at current levels through the middle of the year.

Relative to last year, we are seeing improvement with respect to permitting issues in the state.

We have received approved field rules and new permits for both injection wells and drilling locations.

The regulatory agency is responsive and committed to working through the backlog of permits.

We expect to maintain our capital program at current levels for about the first half of the year, which will enable us to grow our production volumes.

We'll reassess our capital program as the year progresses, and the current regulatory environment clearly stabilizes.

Starting in 2011, we shifted our development program on focusing on conventional/nonconventional opportunities outside their traditional Elk Hills area.

As you can see in the investor relations supplemental schedule, our traditional Elk Hills production, on a BOE basis, has declined 14% since we began this program, while the remainder of our California production, representing our conventional steam and shale programs, has increased 30% during the same period.

Essentially all of the increase came from liquids.

Excluding the traditional Elk Hills, liquids production is up about 35%, or about 17,000 barrels a day.

As we have previously discussed, we are shifting our program to emphasize oil and liquids-rich production.

We are starting to see the effect of this shift in the first quarter of 2012.

We expect most of the California production growth in the near future to come from liquids.

While the current environment -- while in the current environment we don't expect to drill many gas wells, the new Elk Hills gas plant will positively affect our operational efficiency and production in the back half of the year.

In the Permian, the rig count at the end of the first quarter was 26, three higher than we were running at year-end 2011.

We expect our rig count to remain at about this level during the year.

As the attached investor relations supplemental schedule shows, we had significant acreage positions in a number of plays in the Permian basin that will give us ample opportunity for future growth.

Our total acreage position in these plays, broadly defined, is approximately 2.9 million gross acres, or about 1 million acres net.

Based on what we currently believe are the likely limits of these plays, our gross and networking interests are 1 million acres and 300,000 acres, respectively.

We are currently operating 24 rigs in these areas.

Additionally, 74 wells, in which we have a working interest, were drilled by third-party operators during the first quarter of 2012.

We currently expect about 300 additional wells to be drilled by those operators during the rest of the year.

We expect that our program and the third-party drilling will accelerate our Permian production in the latter part of this year.

In the Midcontinent and Other operations -- the Williston, our rig count was 13 at the end of the quarter, down from 14 at year end.

We expect our rig count will be about six by the end of this year.

As I mentioned in last quarter's conference call, we've shifted some capital from this area to California in the Permian.

Natural gas prices in the United States continue at depressed levels.

As a result, we've cut back our pure gas drilling.

If the current low NGL prices continue, cutbacks at liquids-rich wells -- or gas-rich wells -- may be necessary.

International operations -- the Al Hosn Shaw gas project is approximately 38% complete and is progressing as planned.

This project made up about 10% of our total capital program for the first quarter.

If spending continues at current levels, we will see higher than anticipated spending for the remainder of this year.

Of our total development capital for projects this expects to be in line for with previous estimates.

In Iraq, the spending declined compared to the fourth-quarter levels as a result of contract approval delays.

However, recently, a number of major contracts were approved, covering drilling completion services, work overs, and logistics support.

As we look ahead to the second quarter, we expect oil and gas production to be as follows -- we've got the domestic production to grow 3000 to 4000 barrels a day per month, a current quarterly average of 455,000 a day, which would correspond to 6000 to 8000 barrels per day increase for the quarter.

Internationally, Colombia's first-quarter production was reduced by 7000 barrels a day resulting from increase in insurgent attacks on the pipeline.

Production should go back to normal levels, assuming no significant insurgent activity.

Production has been about normal levels so far in the current quarter.

The Middle East region production is expected to be as follows -- production has resumed in our operations in Libya and average 20,000 barrels a day in the first quarter, including entitlements in the post-2011 civil unrest period.

We expect the second quarter daily volumes to be about 11,000 barrels a day.

We expect production to increase gradually during the course of the year, reaching the historic levels of about 14,000 barrels a day by year end.

In Iraq, as I previously discussed, production levels depend on capital spending amounts.

We are unable to predict the timing of the capital spend.

For Dolphin, a plant shutdown reduced production in January and February.

Production increased significantly in March.

We expect second-quarter production to increase modestly over first-quarter volumes.

In the remainder of the Middle East, we expect production to be comparable to the first-quarter volumes.

We expect sales and production volumes in the second quarter of 2012 to be about equal, subject to scheduling and liftings.

A $5 change in global oil prices would impact our production sharing contract daily volumes by about 3000 BOE a day.

Additionally, we expect exploration expense to be about $125 million for seismic and drilling for exploration programs in the second quarter.

Chemical segment quarter earnings are expected to be about $175 million.

We expect lower natural gas prices and improvements in the exports of VCM and polyvinyl chloride to be offset by several planned maintenance turnarounds, and an anticipated slowdown in domestic PVC demand, following the unusually strong start in the first quarter.

We expect our combined worldwide tax rate in the second quarter to decrease to about 41%.

The decrease in the first quarter reflects lower Libyan liftings.

So, to summarize, we closed the quarter with an all-time record total Company production, and the sixth consecutive record domestic oil and gas production.

As the largest liquids producer in the lower 48, we increased our liquids production by 6000 barrels a day from the fourth quarter, and by 35,000 barrels a day from the first quarter of 2011.

We increased our dividend rate by 17% to $2.16 per share.

Our capital spending was $2.4 billion in the first quarter, with the Shaw gas project increasing to about 10% of total spending.

The business generated cash from operations of $2.8 billion in the quarter.

I think we're now ready to take your questions.

(Operator Instructions).

Doug Leggate, Bank of America.

I'm going to try a couple if I can, Steve.

The gas plant -- I guess we've been waiting on this for quite a while -- can you just confirm the timeline of -- I think you originally said a sort of major in commissioning.

But more importantly, can you help us understand what that does in terms of alleviating any bottlenecks, particularly in the legacy Elk Hills field?

And maybe help us understand what the -- how can we quantify how much incremental production this is actually going to bring to you when the thing comes on-stream?

And I have a follow-up, please.

Yes, the plant's on schedule.

And it's in the process of testing, or whatever you want to call it currently.

So there shouldn't be any delays.

When we talked about the plant a couple years ago, we thought we'd drill more gas, and obvious -- to fill it up.

At -- whatever it is, $2 gas, it doesn't seem all that interesting.

But wells would be all right; but I think that -- I think it's wasteful to produce gas at $2.

We have a sizable inventory of gas to drill in California.

It would easily fill the plant and then some, but we'll probably defer that.

The exact increase -- you know, basically, what will happen is, you'll get a little more NGLs out of the old plant -- the old field, and much more reliable gas production.

What exactly it'll do, we'll be able see in the third quarter.

It'll be an improvement.

And we'll see what will happen when we shift the gas, the high-pressure gas, to the new plant and keep the low pressure gas in the old plant.

So I can't predict that, and I don't want to predict it until I actually see the results.

Thanks.

My follow-up is kind of related question, also in California.

Your commentary around the permits, I think, is very much supported by the -- at least, the data we see coming out of the state.

My question is that you've said in the past that you were really unable to plan because you didn't have line of sight on permits.

Well, now it seems that you're getting that line of sight.

And you've said you'll hold the rig count flat through the middle of the year.

But can you just give us a little bit of color as to how you are thinking about the operating team performing to your satisfaction, such that you're prepared to allocate more capital.

And if so, what can we expect in terms of the split between unconventional drilling and conventional exploration?

And I'll leave it at that, Steve.

The second part, I don't really know.

They drill the stuff that's best as it builds up.

I think I've told almost everybody that a massive buildup of drilling rigs in California is probably counterproductive at this point.

We expect to build the rig count in the back half of the year as the line of sight improvements.

It's obviously a lot better than it was, but we need to be able to plan to keep those rigs.

Because once you bring them into California, it's hard to get rid of them.

We are, effectively, the only one drilling.

So, I think you just got to say that as the longer lead permitting progresses, we'll build count, and we'll see where we are at this point.

Thanks.

I'll leave it there, Steve, thanks.

Paul Sankey, Deutsche Bank.

On the balance sheet management, can you just talk about buybacks?

And you've mentioned the dividend increase.

Thanks.

Because we are intermittent buyers of the shares -- that is, we buy them when they're cheap and let them -- when it's less clear, we let it alone.

The stock declined when we were in the basically closed-window period.

And so we really couldn't respond in this month, essentially.

We'll see -- we talked about the calculation a couple quarters ago.

So that'll be something we'll be looking at very hard in the next few weeks.

The cash balance, of course is -- we're not exactly getting rich off the interest.

And so, we need to put the money to work one way or another.

There may be some small acquisitions.

But we're earning -- in spite of -- we earn 16% on equity.

So if we can reinvest it and earn 16% on equity, that's probably in the shareholders' interests.

But if the shares reflect a different number, then we'll take a different tact.

Yes, that's interesting.

I think, obviously, the business model in the past has been acquisition-led at times.

I strongly sense your language is -- there's bits and pieces, perhaps; but you've really got an organic opportunity set here that you're going to pursue.

I really don't need to do anything material.

Some bargain comes up, that's a different story.

But we're just not going to do anything material.

Again, bargains are one thing, but so far I haven't heard of any bargains coming by.

And we're actually not a real estate company.

And so, we're not actually -- a lot of this stuff that's for sale isn't exactly oceanfront property.

And so, we're pretty cautious about large-scale acreage acquisitions; so if we can steal it, that's fine.

But right now, we have so much on our plate.

I think I told you a couple quarters ago that the requests from the units were essentially twice the approved spending level.

So we got a big inventory.

The opportunity set continues to grow, both in California and in the Permian.

There's just no need to do something splashy.

Yes, if we were to think about the balance sheet, is there an optimal level of leverage for you that -- in this environment?

I don't know.

As you know, I'm a debtophobe, so there's probably not.

But we still have $3.8 billion of cash.

Yes, the [inefficiency], is it the cash more than the --

Yes, it's more inefficiency than cash than leveraging up.

It's a commodity business; it's volatile; and that's not all that exciting.

But at 2% interest rates, it's always a little tempting.

But right now we've got a boatload of cash.

And we would expect, this year, even with a modest level of acquisitions and the growth of the sour gas capital spending, we'll build cash this year.

So we got a figure out the best way to put it to work.

Thanks.

And then the follow-up would just be, is there anything interesting to say -- I'm sure there is -- about Oman and the outlook there?

We'll let Sandy -- is in Oman expert, to talk to about it.

Yes, Paul, we're running 15 rigs in Oman right now, 10 of them in the north.

And we are working in the relatively new Block 62, and still working Block 9 and 27.

We're revamping a lot of our facilities so that we can get consistent production, over 100,000 gross barrels a day in the north.

We see that as a place that has still got a lot of opportunities for us.

What sort of gross should we look for from this, Sandy?

What sort of gross or --?

Growth, growth.

In growth, we look at -- we're still going to -- we're going to get to about 110,000 gross barrels a day.

We're running about 98,000 right now.

Some of what -- we actually have more capacity in the ground.

We're having to fix and refurbish and add some facilities to the field.

Okay.

Thanks a lot.

I'll let someone else have a go.

Thank you.

Jessica Chipman, Tudor, Pickering, Holt.

Couple questions -- the first, just on the breakout you gave around Permian acreage.

It looks like 330,000 net acres was in the likely limits that you see.

(multiple speakers)

That we currently see.

So what is the current breakdown, if you could, on the 24 rigs that you're running there currently?

You mean by -- ?

Just by location.

Are most of those vertical Wolfberry rigs, or where are you spending on --?

Bill can answer that.

We're not going to break down for each play.

We'll do it by basin, generally.

Jessica, yes.

About half of our rig count is -- and half of the program for 2012, is going to be devoted to drilling Wolfberry wells.

But we are active in -- not all of the plays that you see listed on the schedule, but in a number of them.

And just also, just as a reminder, we have eight rigs currently running on our CO2 floods, drilling largely infill development wells.

Okay, that's helpful.

And then -- I asked this before and I'll ask it again -- could you give us an update just on well costs within the Bakken and the Permian, particularly on the horizontal side, and then California?

Horizontal side?

Oh, you -- the Bakken stuff has still not come down to the level that's appropriate, so we continue to reduce our current -- we got a lot better places to put money right now than the Bakken.

So we're reducing that count.

The rest of the stuff doesn't seem changed very much.

The rest of the horizontal -- I think service costs are essentially flat.

Okay.

And then just thinking about the run rate, as CapEx in Q1 was $2.4 billion.

And I think you made a comment, there are ways to bring that down over the year, in addition --

Not ways, it just will.

There's things that just roll off.

So basically, decreasing Bakken rigs, and then --

(multiple speakers) An ending the buildings of the plant.

Okay.

So the $8.3 billion of the original spend that you outlined for this year, that -- (multiple speakers)

The only thing I say, it's really out of our control, is the sour gas.

Because, you know, we had a lower number in there.

And I think they'll spend more than that now.

So the total will go up, but -- I don't -- that total over time is about $4 billion, our share.

And so it'll be spent between now and the end of 2014.

And just a matter of -- you don't really know what year it will fall in.

But the totals are okay, so we spent more this year, they'll spend less some other year.

So that's the only variable right now, unless we change the program.

Okay, that's helpful.

Thank you.

Doug Terreson, ISI Group.

Steve, in international E&P, and specifically in Iraq, I think you highlighted delays for permitting and contracts and infrastructure, and that you guys were reducing spending.

We didn't reduce it.

It's just sort of automatic.

If they don't give the permits, it's hard to the spend money.

There's only so many dinners you can buy in Oman.

So my question is, can you talk about that position, and how production is unfolding versus planned?

Meaning, not so much for the next couple of quarters -- which I realize is impossible because of what you said about the unpredictability of near-term spending.

But has your outlook changed over the immediate term [limit] position?

Or just kind of a general update on how you think about that play.

Sandy would be glad to answer that.

Yes, Doug, we are making progress on spending, in addition to -- we just yesterday found out they've approved some new production facilities.

So that will not only give us more spend, which leads to more earned production, but it will give us more gross production.

There are some variables facing us.

There's some common infrastructure that the Iraqis are working on.

They fixed a lot of the issues on the transportation, the terminal.

We're still trying to get the water injection fixed.

And the actual speed of ramp up of our earned production will depend on how soon we can get more water in the ground.

Okay, okay, thanks a lot.

The gross, just to fill in the point, the gross is around 260 right now.

These latest approvals on contract awards can get us up to 550, 600 over the next 2, 2.5, 3 years.

So that's coming together.

It hasn't gone as fast as we would like, but we've had some recent progress.

But what was it when we took over?

We took it over at 180.

That gives you a feel for the growth.

Yes.

Okay, thanks a lot.

Leo Mariani, RBC.

Just curious on your US gas production.

I guess it picked up very modestly here in the first quarter.

I guess roughly 1 million a day over the previous quarter.

You talked about pulling back on your gas activity recently here.

What should we expect your US gas production to do?

Is that going to peak here in the first quarter 2012 and start declining?

Just any color you had on that would be helpful.

I would argue it's probably pretty flattish.

It will vary, but I think pretty flattish.

A lot of the gas, the bulk of the gas, overwhelming majority of the gas, is associated with the oil production.

And so -- but we're not -- we could size -- we could have a huge increase in gas production as a Company if we decided to drill wells.

And, basically, that's what's -- at $2, it's just not going to happen; or $2.50, or $3.

So that's really what we're saying is, we could have a very, very large increase in gas production if the prices were sensible.

So you ought to expect sort of flattish.

So all the growth in the business will come out of the oil business, which is a little easier -- a little harder than growing, given the size of our portfolio.

A little harder than growing gas.

We could grow gas a lot because it's a small base.

Okay, and I guess in the Permian you guys talk about participating in 70-something industry wells in the first quarter in a number of different areas.

Any thoughts on what you guys are seeing as a result of those wells?

Is there any particular area, other than the Wolfberry, that you're very active that has you guys excited at all?

Most of it is doing pretty well, the oily areas.

I think if you've got about a third of your BOEs in oil, that's the stuff that sells for about $100 a barrel, sort of -- you have, I think, a pretty economic program.

In those programs, where there is really no $100 a barrel stuff, and all you have is NGLs and gas, I think they are economically challenged in the Permian.

So some of the plays are so-called liquids-rich.

If there's not about a third of your stream in condensate or black oil, I think those are economically challenged, from our perspective.

Somebody else may have a more limited opportunity set.

Any plans for Oxy to get after some operated activity and some of those high oil cut plays?

What do you think we're doing?

(Multiple speakers).

How many rigs are you running in --?

Today we've got 30 --

Yes, we got --

-- total, today.

I was trying to refer to outside your traditional CO2 floods, outside --

No, no, no.

No, no.

We got -- how many -- if you take out the Wolfberry Wells, how many wells you -- rigs you have?

Without Wolfberry, we've got 17 running.

Yes.

17 rigs.

Okay, and eight of those are CO2, is that right?

Yes, it varies, six to eight.

We do swap them between primary development and CO2 from time to time.

Okay, got you.

So the remainder, are those kind of spread out in different portions in maybe the Delaware and Midland basins?

Just any color you had around where the rest of the activity is.

It's spread out.

And whatever we told you today wouldn't be true a month from now.

Okay.

Thanks, guys.

Jason Gammel, Macquarie.

I had a few questions around the Permian that have just been answered, but I did want to at least ask you about CO2 operations.

Should we continue to think of that as an operation that essentially runs a flattish production profile, moving forward?

Are you still able to secure the type of CO2 that you've been talking about in recent years, just given some of the changes in Century Plant operatorship and that sort of thing?

And then, if I just could, one more-- I think this has been asked, but I didn't quite catch the answer to it.

Are you actually drilling horizontally in the Wolfcamp formation in the Permian right now?

Bill will answer the horizontal question.

But on the other question is -- we would expect that the CO2 production would grow, not be flat.

And we have a sizable amount of CO2 right now.

We've covered the problem with the SandRidge Plant and -- some other way.

So I think we're in very good shape on CO2.

And the production in the CO2 area is actually growing.

Yes, and Jason, to answer your horizontal question, we do have a couple of rigs drilling horizontal Wolfcamp wells, in addition to a couple drilling the Bone Springs horizontals.

Great.

Could I follow-up with just one more, Steve, on the role of Bakken.

It is a play that you talked about being a little more challenged economically than a lot of the other liquids plays that you have.

Is this still something that you are just going to, essentially, hold on to until economics improve?

Or would you potentially be looking to exit that position?

We don't plan to exit it.

If you look at the United States, you can say where the oil is.

The oil is in California; the oil is in the Permian; and the oil is in the Bakken.

The Bakken, right now, if you think about it, there's labor issues.

It's basically overwhelmed, a small place, with the drilling activities.

Effectively looking, if we can -- at the right price to add to the position, and build it out as a long-term resource.

Right now, given the other two US areas, it's just not -- it might be effective for somebody else to compete for capital, but it's not effective for us to compete for capital.

That's why I'm slowing it down.

Because money is much better used in either California or West Texas.

But over time -- this is the Willie Sutton discussion -- why are we there?

Because that's where the oil is.

It's real straightforward, and we are a domestic oil producer, fundamentally.

Understood.

Appreciate the answer, Steve.

(Operator Instructions).

Sven Del Pozzo, IHS.

Just a couple questions.

On the non-operated wells that you've got in the Permian, would you care to name, perhaps, the top one or two that -- whose drilling is most likely to influence your overall results?

No.

Okay.

This question regarding Cline shale, looking at your slide 27.

Is it too early to tell?

Or is there evidence of an eastward expansion of the play onto the eastern shelf from where we see most of the industry's successes thus far?

I think it's too early.

I think it's fair to say, at this point, it's interesting, and doing reasonably well.

Define the limits right now is -- I think it'd be pure speculation.

Okay.

And then on that slide 27th, I'm not exactly sure what the likely limits, it means --

It means, if we -- it's around where there is production and people have been successful.

We provided two columns, because our review is probably more conservative than the average, on what the likely limits are.

So we've given you sort of the small E&P version on one set of columns, and the rational economic one on the second.

But we would hope that some of the acreage that's -- would move over there.

But right now, all you can really say that we would view as has highly prospective.

Okay.

And lastly, regarding NGL prices -- at least relative to spot prices, your realization held up quite well, comparing the first quarter of 2012 to the fourth quarter.

So I'm wondering, what are some of the reasons for that, and if they'll persist during the course of 2012?

If you look at the pricing, we produce a moderate amount of NGLs here in California.

California pricing is fundamentally better than the rest of US.

All right, okay.

Thank you very much.

Ed Westlake, Credit Suisse.

Thanks for all the extra disclosure, particularly around the Permian.

I guess two questions -- one, within that, if you add in, say, current production 139 in the Permian; add in 39 of NGLs; call it 180,000 barrels a day, Q1.

As you add rigs, and as the CO2 business grows, as you said, what scale do you think that business could become in a few years?

Or what sort of type of growth rate would you expect from the liquid side of the Permian?

I'm probably going to get in trouble if I speculate.

But it's gone through another rejuvenation, may be the fifth or sixth one in my life, maybe more; my career, maybe 10 times, if I were to really count them.

This is basically driven by, not necessarily new technology or some of that, but really by higher product prices.

Product prices hold somewhere in this area, this business is going to grow sharply.

Every forecast I've ever made for this business in the Permian over the last five or 10 years has been way too low.

The business is a very large business, larger than a lot of companies.

And it will continue to grow at a pretty decent pace.

But you should remember that it's a large business.

So the absolute growth, for the US economy kind of growth, is going to be quite sizable.

But on a percentage basis, it's not going to be impressive, as impressive as somebody who starts at 20,000 barrels a day.

And --

So, I can't really answer it.

But I would think it'd be commensurate with the growth of the US business.

That is to say, it is the core of the Company's cash flow generation.

And --

So, it'll grow in line with our US business.

And the -- your comment there, if oil prices remain robust and the fact that Permian has surprised you over time -- when you were setting out, your overall 5% to 7% growth rate for Oxy as a corporation, do you think that -- that you've been conservative?

And, therefore, any surprise would be additive to that growth rate?

No, the only thing I learned over the years in the oil business is that the well making 2000 barrels a day might make zero tomorrow; but it's definitely not going to make 4000.

And so you've got to be cautious about decline rates and stuff.

But the Permian has really gone through a significant rejuvenation, so we are well-positioned to reap that.

Given it's a large business, is 500 million acres enough?

In the likely, you're 570 million, so we're just doing the math.

Well, the actual acreage of the Permian is much larger.

So our net acreage is closer to 3 million for the whole basin.

This is just in this area.

So your view is, over time other areas perhaps could come into economic --

It is the same formations.

I mean, they changed the names to protect the innocent, I guess.

But these are the same formations that have been producing for a long time.

They just change the names to make them sound more interesting.

I would guess that, over time -- the basin has always been very good us, but also certainly very good for the US industry.

So I'm bullish on the basin.

As you move towards New Mexico, it gets a lot gassier, you should understand.

And a lot of people have big acreage positions out that way.

And that depends, really, on your view about gas prices rather than oil prices.

We're pretty much an oil company.

Yes.

So to summary, the 570 here plus the overall position you have, you feel you have can -- you've got enough inventory to continue to grow the Permian, say, over the next 5 to 10 years?

At least for the next 10 years.

We continue to acquire more inventory when it's priced properly.

Thanks, guys.

At this time there are no further questions.

I'll hand the call back over for any closing remarks.

Thank you.

Thank you very much.

And if you have any further questions, please call us here in Investor Relations in New York.

Thank you.

Thank you.

This does conclude today's conference call.

You may now disconnect.