Occidental Petroleum Corporation (OXY) Q1 2012 Earnings Report, Transcript and Summary

Good morning. My name is Christie, and I'll be your conference operator today. At this time, I would like to welcome everyone to Occidental Petroleum's First Quarter 2012 Earnings Release Conference Call. [Operator Instructions] Mr. Stavros, you may begin your conference.

Thank you, Christie, and good morning, everyone, and welcome to Occidental Petroleum's First Quarter 2012 Earnings Conference Call. Joining us on the call first 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'll also be providing some new information on our activity and exposure on 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 ahead.

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 start-up phase of operations after the 2011 civil unrest. Here's a breakdown from 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're 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 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 a 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 $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 NYMEX price. The NGL realization is low by historical standards and indicates a troubling trend. Over the last 5 years, domestic NGL realizations have dropped from about 73% to 52% of WTI. Absolute realized price of NGLs is not significantly different than 5 years ago. Price changes at current global prices affect our quarterly earnings before income taxes by $36 million for $1 per barrel change in oil prices, and $8 million for $1 per barrel change in NGL prices. A swing of $0.50 per million BTUs in domestic gas prices affects quarterly pretax earnings by about $35 million. Oil and gas production costs were $14 a barrel for the first 3 months of 2012 compared with last year's 12-month cost of $12.84 a barrel and fourth quarter of 2011 cost of $14.22 a barrel. The cost increase reflects higher well maintenance activity. Taxes other than our 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 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. 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 3 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 3 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 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, 834 million cubic feet a day of gas, was an increase of 6,000-barrel equivalent 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 2011, our domestic liquids production grew by 35,000 barrels per day and gas production by 100 million cubic feet per day. As you may recall, OXY is the largest 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 3 months of 2012 was 16% and return on capital employed 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, such as the Elk Hills gas plant are completed. In addition, as I indicated in last quarter's conference call, we will review our capital program around midyear and adjust as conditions dictate. The following is the geographic overview of the program. In the domestically in California, the rig count at the end of the first quarter was about the same as the 31 we're running at year-end 2011. We expect the rig count to remain at current levels through the end 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 the 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 was about -- 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 the current environment -- while in the current environment, we don't expect to drill many gas wells. The new Elk Hills gas plant will possibly 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, 3 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 networking interest 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 redrilled 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 the rig count to 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 and the Permian. Natural gas prices in the United States continue at depressed levels. As a result, we have cut back our pure gas drilling. If the current low NGL prices continue, cutback in liquid-rich wells or gas rich wells, may be necessary. International operations, the Al Hosn Shah 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 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 and 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 domestic production to grow 3,000 or 4,000 barrels a day per month in the quarterly average of 455,000 a day, which would correspond to 6,000 to 8,000 barrels per day increase for the quarter. Internationally, Colombia's first quarter production was reduced by 7,000 barrels a day resulting from increased 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 assumed in our operations of Libyan and averaged 20,000 barrels a day in the first quarter, including entitlements in the post-2011 civil unrest period. We expect that 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've 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 or quarter earnings are expected to be about $175 million. We expect lower natural gas prices and improvements in exports of VCM and polyvinyl chloride to be offset by several planned maintenance turnarounds and 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 lower 48, we increased our liquids production by 6,000 barrels a day from the fourth quarter, and by 35,000 barrels a day for the first quarter 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 Shah gas project increasing to about 10% of the 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] And your first question comes from Doug Leggate of Bank of America.

I'm going to go try a couple if I can, Steve. The gas fund, I guess, we've been waiting on this for quite a while. Can you just confirm the timeline of -- I think you'd originally said, major 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 -- 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. It's obvious. The plant's on schedule, and it's in the process of testing or whatever we want to call it currently. So there shouldn't be any delays. When we talked about the plant a couple of years ago, we talk thought we'll drill more gas and obviously to fill it up and whatever it is, $2 gas doesn't seem at all that interesting. The wells would be all right, but 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. Exact increase, basically what will happen is you'll get a little more NGLs out of Elk -- out of the old plant or the old field and much more reliable gas production. And what exactly it will do, we'll be able to see in the third quarter, but it will be an improvement. And we'll see what will happen when the 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.

My follow up is kind of a related question also to California. Your commentary around the permits, I think, is very much supported by the, at least that's what we see coming out of the state. My question is that, you've said in the past that you really were 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 hold the rig count flat in the middle of the year. But can you just give us a bit more color as to how you're thinking about the operating team performing to your satisfaction, so to speak, 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?

The second part, I don't really know. They drill a bit -- the best as it builds up. I think I 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 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. So I think you just got to say that as the longer lead permitting progresses we'll build the count, and we'll see where we are at this point.

Your next question comes from Paul Sankey of Deutsche Bank.

On the balance sheet management, can you just talk about buybacks? And you've mentioned the dividend increases.

Because we're intermittent buyers of the shares, as we buy when they're cheap and when it's less clear, we leave it alone. Stock declined when we're in basically the closed window period. And so we really couldn't respond this month essentially. And we'll see -- we talked about the calculation a couple of quarters ago. And so that will be something that we'll be looking at very hard in next few weeks. The cash balance courses, and 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 earned 16% on equity. So if we can reinvest it and earn 16% on equity, that's probably in the shareholders interest. 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 at times. I think, I strongly sense your language is this bits and pieces perhaps that you've really got an organic opportunity here that you're going to pursues?

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 the stuff that is for sale isn't exactly oceanfront property. And so we're pretty cautious about large-scale acreage acquisitions. So if they 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 request from the units were essentially twice the approved spending level. So we got a big inventory. The opportunities that continues to grow both in California and in the Permian. And there's just no need to do something splashy.

Yes. If we think about the balance sheet, is there an optimal level of leverage for you 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 of the cash is more than...

Yes it's more efficient to cash than leveraging up. Commodity business is volatile, and that's not all that exciting. But 2% interest rate'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 solid gas, the capital spending will build cash this year. So we got to figure out the best way to put it to work.

And then a follow up, which is the -- is there anything interesting to say as all there is about Oman? Any outlook there?

Well, Sandy is a Oman expert. He'll talk to you about it.

Yes, Paul, we're running 15 rigs in Oman right now, 10 of them in the north. And 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. So I mean we see that as a place that still got a lot of opportunities ahead of us.

What sort of growth should we look for from this earning?

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 right now. Some of it, we actually have more capacity in the ground we have to fix and refurbished and add some facilities to few.

Your next question comes from Jessica Chipman of Tudor Pickering Holt. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Couple questions. The first, just on the breakout you gave around permian acreage. Looks like 330,000 net acres was in the likely limits that you see...

That we currently see. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: So what is the current breakdown, if you could, on the 24 rigs that you're running there currently?

You mean by... Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just by location. Most of those were vertical Wolfberry rigs or were you spend the capital?

Bill can answer that. We're not going to break it 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 8 rigs currently running on our CO2 floods, building largely infill development wells. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. that's helpful. And then I've asked this before and I'll ask this again, could you give us an update just on well cost within the Bakken, the Permian, particularly on the horizontal side and then California?

Horizontal side? The Bakken stuff is still not come down to the level that's appropriate, so we continue to reduce our current -- we have a lot more better places to put money right now than the Bakken, so we're reducing that count. The rest of the stuff doesn't seem to change very much. The rest of the horizontal -- I think our service costs are essentially flat. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And then 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...

Not ways, it's just will. There are things just roll off. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: So basically, decreasing Bakken rigs and then...

And the buildings at the plants. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: So the $8.3 billion original spend that you outlined to the tune of...

The only thing I would say that's really out of our control is the sour gas, because we had a lower number in there, and I think they'll spend more of that now, so the total will go up. The total over time is about $4 billion our share. And so if we spent between now and the end 2014, and just a matter -- you don't really know what year it will fall in, the total's okay. So we'll spend more this year and we'll spend less some of the year. So that's the only variable right now, unless we change the program.

Your next question comes from Doug Harrison of ISI Group.

Steven, international EMP and specifically in Iraq, I think you highlighted delays for permitting and contracts and infrastructure that you guys are reducing spending.

We didn't reduce it, it's just sort of automatic. They don't get the permits, it's hard to spend the money. There's only so many dinners you can buy if you want.

So my question is, can you talk about that position, and how production's unfolding versus plant meeting? Not just 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 on that position or just cover a general update on how you think about that play?

Sandy will 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 we will not only give us more spend, which leads to more introduction, but more gross production. There are some variables facing us with some common infrastructures that the Iraqis are working on. They fixed a lot of your issues on transportation, the terminal. We're still trying to get the water injections fixed. And the actual speed of ramp up of our own production will depend on how soon we can get more water in the ground.

The gross, just to fill in, the gross is running 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 he like to, 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.

Your next question comes from Leo Mariani of RBC.

Just curious on your U.S. 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. When should we expect your U.S. gas production to do? Is that going to peak here in the first quarter of '12 and start declining? Just any color that will 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 should 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 flatfish so all the growth in the business will come out of the oil business, which is a little easy -- a little harder than growing in the size of our portfolio, a little harder than growing gas. We grow gas a lot because it's a small base.

Okay. I guess in the Permian, you talked 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? 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 1/3 of your BOEs in oil, that's a stuff that sells for $100 a barrel, sort of. You have, I think, a pretty economic program. And those programs were, there's really no $100 a barrel stuff, all you have this NGLs and gas, I think they're economically challenged in the Permian. So some of the plays are so-called liquids rich if there's not about 1/3 of your stream are condensated 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?

I'm talking about how possible variables...

How many rigs are we running -- how many rigs are you running in...

Today we've got 30.

Yes, we've got total today so...

Yes. I guess, I was trying to refer to kind of outside your traditional CO2 floods...

No, no. We've got -- how many -- you take out the Wolfberry wells, how many wells you have, rigs you have?

Without Wolfberry, we've got 17 running.

Yes, 17 rigs.

And 8 of those are CO2, is that right?

It varies, 6 to 8. We do swap them between primary development and CO2 from time to time.

Okay, got you. I guess -- so the remainder of those kind of spread out in different portions and maybe the Delaware and Midland Basin, if there's any color you kind of add 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.

Your next question comes from Jason Gammel of Macquarie.

I have a few questions about Permian but have been answered, but I did want to at least ask you about the CO2 to operations. We continue to think of that as an operation that essentially runs a flattish production profile moving forward. And 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 operation and that sort of thing? And then if I just get one more. I think it's been asked. 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 sizable amount of CO2 right now. We've covered the problem with the sand rich plant with some other way. And so I think we're in very good shape on CO2 and the production -- and the CO2 area is actually growing.

Yes. And, Jason, did I answer your horizontal question? We do have a couple of rigs drilling horizontal Wolfcamp wells in addition to a couple of drilling some Bone Springs horizontals.

Great. Can I follow up just one more, Steve, just on the oil in 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 still going to essentially hold onto 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, 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 that's basically overwhelmed the small place with the drilling activities. We're effectively looking if we can -- the right price to add to the position and build it out as a long-term resource. Right now, given the other 2 U.S. areas, it's just not -- it might be effective for somebody else to compete for capital, but it's not effective for us to complete for capital. That's why I'm slowing it down, because that money is much better used in either California or West Texas. But over time, it's the Willie Sutton discussion of why we're there because that's where the oil is. So that's real straightforward, and we're domestic oil producer fundamentally.

[Operator Instructions] Your next question comes from Sven Del Pozzo of IHS.

Just a couple of questions. On the non-operating wells that you've got in Permian, would you care to name perhaps the top 1 or 2 who's drilling is most likely to influence your overall results?

No.

Okay. This question regarding 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 shale from where we've seen most of the industry success thus far?

I think it's too early. It's -- I think it's fair to say it's -- at this point, it's interesting and doing reasonably well. To find the limits right now, it's pure speculation.

Okay. And then on that Slide 27, I'm not exactly sure what the likely limits it means...

It means -- it's around whether it's production and people have been successful. We've provided 2 columns because our view is probably more conservative than the average on what the likely limits are. So we've given you sort of small E&P version on one set of columns and sort of the rational economic one on the second. But we would hope that some of the acreage would move over there. But right now, all you can really say that we would view as highly perspective.

Okay. And lastly, regarding NGL prices, at least relative to spot prices, your realization held up quite well comparing to the first quarter relative 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 the U.S.

Your next question comes from the line of Ed Westlake of Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Thanks for all the extra disclosure to be around the Permian. I guess 2 questions. One, within that, if you add in, say, current production of 139,000 in the Permian, add in 39,000 of NGLs, call it 180,000 barrels a day in Q1. As you add rigs and as the CO2 business grows, as you said, what scale do think that business could become in a few years, also the type of growth rate would you expect on the liquid side out of the Permian?

I'm probably going to get in trouble if I speculate. But it's gone through another rejuvenation, maybe the fifth or sixth one in my life, maybe more, maybe 10 times, if I would really count them. And this is basically driven by not necessarily new technology or some of that, but really by higher product prices. If product prices hold somewhere in this area. This business is going to grow sharply. I mean every forecast I've ever made for this business, over the Permian over the last 5 or 10 years has been way too low. And so the business is a very large business, larger than a lot of companies, and it will continue to grow at a pretty decent phase, but you should remember that's a large business. And so the absolute growth for the U.S. 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. So I can't really answer it, but I would think that it will be commensurate with the growth of the U.S. business. That is to say, it is the core of the company's cash flow generation, so it will grow in line with our U.S. business. Edward Westlake - Crédit Suisse AG, Research Division: And your comment there if all prices remain robust and the fact that Permian 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're being conservative and therefore any surprise would be additive to that growth rate?

Only I learned over the years, the oil businesses that the well making 2,000 barrels a day and might make 0 tomorrow, but it's definitely not going to make 4,000. And so you've got to be cautious about decline rates and stuff. But the Permian has really gone through a significant rejuvenation, and so we're well positioned to reap that. Edward Westlake - Crédit Suisse AG, Research Division: And given it's a large business, is 500 million acres enough? I mean in the likely of 570 million, so I'm just doing the math.

The actual acreage in Permian is much larger. And so that acreage is closer to 3 million for the whole basin. This is just in this area. Edward Westlake - Crédit Suisse AG, Research Division: So your view is overtime, other areas perhaps could come into you economic...

It is the same formation. 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 changed the names to make them sound more interesting. And I would guess that over time, the basin has always been very good to us, but certainly very good for the U.S. 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. Edward Westlake - Crédit Suisse AG, Research Division: So your -- to summary, the 570 million here plus the overall position you have, you feel you can -- you've got enough inventory to grow the Permian, say, for the next 5 to 10 years?

At least for the next 10 years. We'd continue to acquire more inventory when it's priced properly.

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. 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.