Occidental Petroleum - Earnings Call - Q1 2012

Transcript

Speaker 7

There will be a question and answer session. If you would like to ask a question during this time, simply press star then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. Mr. Stavros, you may begin your conference.

Speaker 3

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 Stephen Chazen, Oxy's President and Chief Executive Officer, James 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, James Lienert, who will review our financial and operating results for the first quarter of this year.

Stephen 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 James and Stephen's remarks, can be downloaded off of our website at www.oxy.com. I'll now turn the call over to James Lienert. James, please go ahead.

Speaker 2

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 have 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 the breakdown for the first quarter.

In the oil and gas segment, the first quarter of 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 U.S., lower 48, and grew our oil production from 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 457,000 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 a 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 6,000 barrels from the fourth quarter. The decrease reflected the expiration of the missile 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 of 2012 production was lowered 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%. Domestic natural gas prices were $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 gas prices were 100% of the average 9X 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 at current global prices affect our quarterly earnings before income taxes by $36 million for a $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 12-month costs of $12.84 a barrel and fourth quarter of 2011 costs of $14.22 a barrel. The cost increase reflects higher oil 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 the 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 of 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 deicing 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. The increase over our guidance was due to higher Libya liftings. Our first quarter U.S. 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 31st. 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 Stephen Chazen to provide guidance for the second quarter of the year.

Speaker 8

Thank you, Jim. Oxy's first quarter 2012 production set an all-time record for the company, and for the sixth 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 and 834 million cubic feet a day of gas, was an increase of 6,000 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 to our 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 employed was 14%. During the quarter, the company generated cash from operations of $2.8 billion, a 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 conditions dictate. Following is a 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 and non-conventional opportunities outside the traditional Elk Hills field. 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 represented our conventional steam and shale programs that increased 30% during the same period. Essentially, all of the increase came from liquids. Excluding the traditional Elk Hills, liquids production was 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 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 have 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 net working 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 Mid-Continent and other operations, the lowest in 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 6 by the end of this year.

As I mentioned in last quarter's conference call, we have shifted some capital from this area to California in the Permian. Natural gas prices in the U.S. continue at depressed levels. As a result, we've cut back our pure gas drilling. If the current low NGL prices continue, cutbacks in liquids-rich wells, or gas-rich wells, may be necessary. International operations, the Al Hosn 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. However, total development capital for the project is expected to be in line 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, workovers, and logistics support. As we look ahead to the second quarter, we expect oil and gas production to be as follows. We expect the domestic production to grow three to four thousand barrels a day per month, and the current quarterly average of 455,000 a day, which would correspond to six to eight thousand barrels per day increase for the quarter. Internationally, Colombia's first quarter production was reduced by 7,000 barrels a day, resulting from an 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 averaged 20,000 barrels a day in the first quarter, including entitlements from the post-2011 civil unrest period. 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 historical 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 planned 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. 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 of liftings. A $5 change in global oil prices would impact our production sharing contract daily volumes by about 3,000 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.

To summarize, we close 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 6,000 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 was $2.8 billion in the quarter. I think we're now ready to take your questions.

Speaker 7

Thank you. At this time, if you would like to ask a question, press star then the number one on your telephone keypad. Your first question comes from Douglas George Blyth Leggate of Bank of America.

Speaker 1

Thank you. Good afternoon. Good morning, everybody.

Speaker 2

Morning, Doug.

Speaker 1

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 had originally said a sort of major commissioning, but more importantly, can you help us understand what that does in terms of alleviating any bottlenecks, particularly on the legacy Elk Hills field? Maybe help us understand how can we quantify how much incremental production this is actually going to bring to you when the thing comes on stream? I'll have a follow-up, please.

Speaker 2

Yeah, it's on the plant's on schedule. You know, it's in the process of testing or whatever you want to call it, currently. There shouldn't be any delays. When we talked about the plant a couple of years ago, we thought we'd drill more gas, obviously to fill it up. At whatever it is, $2 gas, it doesn't seem all that interesting. The wells would be all right, but I think that, you know, I think it's wasteful to produce gas at $2. We have a sizable inventory of gas to drill in California, would easily fill the plant and then some, but we'll probably defer that some. The exact increase, you know, basically what'll happen is you'll get a little more NGLs out of the old plant or the old field and much more reliable gas production.

What exactly it'll do, you know, we'll be able to see in the third quarter. It'll be an improvement, and we'll see what'll happen when we shift the gas, the high-pressure gas, to the new plant and keep the low-pressure gas in the old plant. I can't predict that, and I don't want to predict it until I actually see the results.

Speaker 1

Thanks. My follow-up is kind of a related question also in California. Your commentary around the permits, I think, is very much supported by at least the data we see coming out of the state. My question is that you've said in the past that you really weren't able to plan because you didn't have line of sight on permits. 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. 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? If so, what can we expect in terms of the split between unconventional drilling and conventional exploration? I'll leave it at that, Steve.

Speaker 2

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 in 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 improves. It's obviously a lot better than it was, but, you know, 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're effectively the only one drilling. I think you just got to say that as the longer lead permitting progresses, we'll build the count, and, you know, we'll see where we are at this point.

Speaker 1

Okay. Thanks, Doug. I'll leave it there, Steve. Thanks.

Speaker 2

Thank you.

Speaker 7

Thank you. Your next question comes from Paul Sankey of Deutsche Bank.

Speaker 1

Hi, Steve.

Speaker 2

Hi.

Speaker 1

On the balance sheet management, can you just talk about buybacks? You've mentioned the dividend increase. Thanks.

Speaker 2

Because we're intermittent buyers of the shares, that is, we buy them when they're cheap and, you know, when it's less clear, we let it alone. The stock declined when we were in basically the closed window period, and so we really couldn't respond in this month, essentially. We'll see, you know, we talked about the calculation a couple of quarters ago, and so that'll be something that we'll be looking at very hard in the next few weeks. The cash balance, of course, is, you know, 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, you know, in spite of, we earn 16% on equity. If we can reinvest it and earn 16% on equity, that's probably in the shareholders' interest.

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

Speaker 1

Yeah, that's interesting. I think, obviously, the business model in the past has been acquisition-led at times. I strongly sense your language is that there's bits and pieces, perhaps, but you've really got an organic opportunity set here that you're going to pursue.

Speaker 2

I really don't need to do anything material.

Speaker 1

Yeah.

Speaker 2

You know, some bargain comes up, that's a different story. We're just not going to do anything material. Bargains are one thing, but so far, I haven't heard of any bargains coming by. We're actually not a real estate company. We're not actually, you know, a lot of the stuff that has for sale isn't exactly oceanfront property. We're pretty cautious about the large-scale acreage acquisitions. If we can steal it, that's fine. Right now, we have so much on our plate. I think I told you a couple of quarters ago that the requests from the units were essentially twice the true spending level. We got a big inventory. The opportunity set continues to grow, you know, both in California and in the Permian. There's just no need to do something splashy.

Speaker 1

If we were to think about the balance sheet, is there an optimal level of leverage for you in this investment?

Speaker 2

I don't know. As you know, I'm a debt-ophobe, so there's probably not, but we still have $3.8 billion of cash.

Speaker 1

Yeah, the inefficiency of the cash more than the.

Speaker 2

Yeah. It's more the inefficiency of the cash, the leveraging up. You know, it's a commodity business. It's volatile. That's not all that exciting. You know, at 2% interest rates, it's always a little tempting. Right now, we've got a boatload of cash. 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. We got to figure out the best way to put it to work.

Speaker 1

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

Speaker 2

Sandy is an Oman expert to talk to you about it.

Speaker 6

Yeah. Paul, we're running 15 rigs in Oman right now, 10 of them in the north. We're working 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's still got a lot of opportunities for us.

Speaker 1

What sort of growth should we look for from there, Sandy?

Speaker 6

What sort of growth?

Speaker 1

Growth.

Speaker 6

In growth, we look at we're still going to get to about 110,000 gross barrels a day. We're running about 98 right now. We actually have more capacity in the ground. We're having to fix and refurbish and add some facilities to the field.

Speaker 1

Okay, thanks a lot. I'll let someone else have a go. Thank you.

Speaker 7

Our next question comes from Jessica Chipman of Tudor Pickering Holt.

Speaker 0

Okay. Good morning. A couple of questions. The first just on the break-out you gave around Permian acreage. It looks like 330,000 net acres within the likely limits that you see.

Speaker 2

That we currently see.

Speaker 0

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

Speaker 2

You mean by?

Speaker 0

Just by location, are most of those vertical Wolfberry rigs, or where are you spending?

Speaker 2

Bill can answer that. We're not going to break it down for each play. We'll do it by basin generally.

Speaker 6

Jessica, yeah. You know, about half of our rig count is and half of the program for 2012 is going to be devoted to drilling Wolfberry wells. We are active in not all of the plays that you see listed on the schedule, but in a number of them. Just also, you know, just as a reminder, we have eight rigs currently running on our CO2 floods, you know, drilling largely infill development wells.

Speaker 0

Okay. That's helpful. I've 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?

Speaker 2

Horizontal side? Oh, the Bakken stuff is still not come down to the level that's appropriate. We continue to reduce our current, we got a lot better places to put money right now than the Bakken. We're reducing that count. The rest of the stuff doesn't seem to change very much. I mean, the rest of the horizontal, I think service costs are essentially flat.

Speaker 0

Okay. Just thinking about the run rate of 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.

Speaker 2

It just will. You know, there's things that just roll off.

Speaker 0

Basically, decreasing Bakken rigs and then.

Speaker 2

Ending of buildings of the plant.

Speaker 0

Okay. The $8.3 billion of original spend that you outlined for this year, that's the only.

Speaker 2

The only thing I say that'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. The total will go up. I don't think the total over time is about $4 billion our share, and it's to be spent between now and the end of 2014. It's just a matter of you don't really know what year it'll fall in, but the total is okay. If we spend more this year, they'll spend less some other year. That's the only variable right now, unless we change the program.

Speaker 0

Okay, that's helpful. Thank you.

Speaker 7

Your next question comes from Doug Leggate of ISI Group.

Speaker 1

Good morning, guys.

Speaker 2

Hi, Doug.

Speaker 1

Steve, an 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. It's something that.

Speaker 2

There's just sort of automatic. You know, if they don't give the permits, it's hard to spend the money. There's only so many dinners you can buy in Oman.

Speaker 1

Can you talk about that position and how production is unfolding versus planned? I realize it is impossible to predict for the next couple of quarters because of what you said about the unpredictability of near-term spending. Has your outlook changed over the immediate term on that position, or just a general update on how you think about that play?

Speaker 2

Sandy would be glad to answer that.

Speaker 1

Okay.

Speaker 6

Yes, Doug. We are making progress on spending. In addition to that, we just yesterday found out they've approved some new production facilities. That will not only give us more spend, which leads to more in production, but it'll give us more gross production. There are some variables facing us. There is some common infrastructure that the Iraqis are working on. They fixed a lot of their issues on the transportation, the terminal. We're still trying to get the water injection fixed. The actual speed of ramp-up of our own production will depend on how soon we can get more water in the ground.

Speaker 1

Okay, thanks a lot.

Speaker 6

Yeah. 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 two, two and a half, three years. That’s coming together. It hasn't gone as fast as we'd like, but we've had some recent progress.

Speaker 1

What was it when we took over?

Speaker 6

We took it over to 180.

Speaker 2

Yes, that gives you a feel for the growth.

Speaker 1

Yeah, okay. Thanks a lot.

Speaker 7

Your next question comes from Leo Mariani of RBC.

Speaker 5

Hey, guys. I'm just curious on your U.S. gas production. I guess it ticked up very modestly here in the first quarter, I guess roughly a million a day over the previous quarter. You've talked about pulling back on your gas activity recently here. What should we expect your kind of U.S. gas production to do? Is that going to peak here in the first quarter of 2012 and start declining? Just any color you had on that would be helpful.

Speaker 2

I would argue it's probably pretty flattish. You know, it'll vary, but I think pretty flattish. A lot of the gas, the bulk of the gas, the overwhelming majority of the gas is associated with the oil production. We're not, we could size, we could have a huge increase in gas production as a company if we decided to drill wells. Basically, that's what's, you know, at $2, it's just not going to happen, or $2.50 or $3. That's really what we're saying is we could have a very, very large increase in gas production if, you know, if the prices were sensible. You ought to expect sort of flattish. 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 grow gas a lot.

It's a small base.

Speaker 5

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

Speaker 2

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 $100 a barrel, sort of. I think you have a pretty economic program. Those programs where there's really no $100 a barrel stuff and all you have is NGLs and gas, I think they're economically challenged in the Permian. Some of the plays are so-called liquids-rich. If there's not about a 30-year stream in condensate or black oil, I think those are economically challenged from our perspective. Somebody else may have a more limited opportunity set.

Speaker 5

Okay. Any plans for Oxy to get after some operating activity in some of those high oil cut plays?

Speaker 2

What do you think we're doing? How many rigs are we running? How many rigs are you running in?

Speaker 1

Today, we've got 30.

Speaker 2

Yeah, we've got total.

Speaker 1

Today.

Speaker 2

Yeah. So.

Speaker 5

Yeah, I guess I was trying to refer to kind of outside your traditional CO2 floods, outside those very.

Speaker 2

Yeah. We got, how many, you take out the Wolfberry wells, how many wells do you have? Rigs do you have?

Speaker 1

Without Wolfberry, we've got 17 running.

Speaker 2

Yeah, 17 rigs.

Speaker 5

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

Speaker 1

Yeah, it varies six to eight. You know, we do swap them between primary development and CO2 from time to time.

Speaker 5

Gotcha. I guess, are those kind of spread out in different portions of maybe the Delaware and Midland Basin? Just any color you kind of had around where the rest of the activity is.

Speaker 2

It's spread out, and whatever we told you today wouldn't be true a month from now.

Speaker 5

Okay, thanks, guys.

Speaker 2

Thanks.

Speaker 7

Your next question comes from Jason Gammel of JPMorgan.

Speaker 4

Thanks, guys. I had a few questions around the Permian that just been answered, but I did want to at least ask you about the CO2 operation. 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 plan operatorship and that sort of thing? If I just could, one more, I think this has been asked, but I didn't quite get the answer to it. Are you actually drilling horizontally in the Wolfcamp formation in the Permian right now?

Speaker 2

Bill will answer the horizontal question. On the other question, we would expect that the CO2 production would grow, not be flat. We have a sizable amount of CO2 right now. We've covered the problem with the sand-rich plant and with some other way. I think we're in very good shape on CO2, and the production in the CO2 area is actually growing.

Speaker 1

Jason, to answer your horizontal question, we do have a couple of rigs drilling horizontal Wolfcamp wells in addition to a couple drilling some Bone Spring horizontals.

Speaker 4

Great. Can I follow up in just one more, Steve, on just the role of the 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're just going to essentially hold on to until economics improve, or would you potentially be looking to exit that position?

Speaker 2

We don't plan to exit it. If you look at the United States, you say where the oil is, the oil's in California, the oil's in the Permian, and the oil's 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. We're 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 U.S. areas, 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. Over time, it's the Willie Sutton discussion. Why are we there? Because that's where the oil is. That's real straightforward.

We're a domestic oil producer fundamentally.

Speaker 4

Understood. Appreciate the answer, Steve.

Speaker 2

Thanks.

Speaker 7

Thank you. As a reminder, to ask a question, press star then the number one on your telephone keypad. Your next question comes from Ben Del Pozzo of IHS.

Speaker 1

Good afternoon. Good afternoon.

Speaker 2

Hi. It's morning for us.

Speaker 1

Oh, yeah. Good morning. Just a couple of 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?

Speaker 2

No.

Speaker 1

Okay. This question regarding the client 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've seen most of the industry's success thus far?

Speaker 2

I think it's too early. I think it's fair to say it's an interest at this point, it's interesting and doing reasonably well. Defining the limits right now is, I think it'd be pure speculation.

Speaker 1

Okay. On that slide 27, I'm not exactly sure what the likely limits it means.

Speaker 2

It means if it's around where there's production and people have been successful, we provided two columns because our view is probably more conservative than the average on what the likely limits are. We've given you sort of the small E&P version on one set of columns and sort of the rational economic one on the second. We would hope that, you know, some of the acreage would move over there. Right now, that's all you can really say that we would view as highly prospective.

Speaker 1

Okay. Lastly, regarding NGL prices, at least relative to spot prices, your realization held up quite well comparing the first quarter as well to the fourth quarter. I'm wondering what are some of the reasons for that and if they'll persist during the course of 2012?

Speaker 2

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 the U.S.

Speaker 1

All right. Okay. Thank you very much.

Speaker 7

Thank you. Your next question comes from the line of Edward Lowe of Credit Suisse.

Speaker 2

Good morning, gentlemen.

Speaker 1

Hi.

Speaker 2

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 on the liquid side out of the Permian? I'm probably, yeah, probably going to get in trouble if I speculate. It's gone through another rejuvenation, maybe the fifth or sixth one in my life, maybe more 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.

If product prices hold, you know, somewhere in this area, this business is going to grow sharply. I mean, every forecast I've ever made for this business, so the Permian over the last 5 or 10 years has been way too low. The business is a very large business, larger than a lot of companies. It will continue to grow at a pretty decent pace. You should remember that it's a large business. The absolute growth for the U.S. economy kind of growth is going to be quite sizable. On a percentage basis, it's not going to be as impressive as somebody who starts with 20,000 barrels a day. I can't really answer it, but I would think it'd be commensurate with the growth of the U.S. business. That is to say, it is especially, it is the core of the company's cash flow generation.

It will grow in line with our U.S. business.

Speaker 1

If oil prices remain robust and the fact that Permian has surprised you over time, when you're setting out your sort of overall 5% to 7% growth rate for Oxy as a corporation, do you think that you've been conservative and therefore any surprise would be additive to that growth rate?

Speaker 2

The only thing I learned over the years in the oil business is that the well making 2,000 barrels a day might make 0 tomorrow, but it's definitely not going to make 4,000. You got to be cautious about decline rates and stuff. The Permian has really gone through a significant rejuvenation, and we're well positioned to reap that.

Speaker 1

Given it's a large business, is 500 million acres enough? I mean, in the likely of 570, sorry, just doing the maths.

Speaker 2

The actual acreage of the Permian is much larger, so our net acreage is closer to 3 million, you know, for the whole basin. This is just in this area.

Speaker 1

Your view is over time, other areas perhaps could come into economic concern.

Speaker 2

It is the same formations. I mean, they changed the names to protect the innocent, I guess. These are the same formations that have been producing for a long time. They just changed the names to make them sound more interesting. I would guess that over time, the basin has always been very good to us, certainly very good for the U.S. industry. I'm bullish on the basin. As you move towards New Mexico, it gets a lot gassier, you should understand. A lot of people have big acreage positions out that way. That depends really on your view about gas prices rather than oil prices. You know, we're pretty much an oil company.

Speaker 1

Yeah. To summarize, the 570 here plus the overall position you have, you feel you've got enough inventory to continue to grow the Permian, say, over the next 5 to 10 years?

Speaker 2

Yeah, at least for the next 10 years. We continue to acquire more inventory when it's priced properly.

Speaker 1

Thanks, guys.

Speaker 2

Thank you.

Speaker 7

Thank you. At this time, there are no further questions. I'll hand the call back over for any closing remarks.

Speaker 2

Thank you.

Speaker 1

Thank you very much. If you have any further questions, please call us here in Investor Relations in New York. Thank you.

Speaker 7

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