Occidental Petroleum Corporation (OXY) Q3 2011 Earnings Report, Transcript and Summary

Good morning. My name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Occidental Petroleum Third Quarter 2011 Earnings Release Conference Call. [Operator Instructions] Thank you. I would now like to turn the call over to Christopher Stavros. Please go ahead, sir.

Thank you, Christie. Good morning, everyone. Welcome to Occidental Petroleum's Third Quarter 2011 Earnings Conference Call. Joining us on the call this morning from Los Angeles are Steve Chazen, Oxy's President, Chief Executive Officer; Jim Lienert, Oxy's Chief Financial Officer; Bill Albrecht, President of our Domestic Oil and Gas operations; and Sandy Lowe, President of our International Oil and Gas business. In just a moment, I'll turn the call over to Jim, our CFO, who will review our financial and operating results for the third quarter and first 9 months of 2011. Chazen will then follow with some comments on Oxy's strategy and outlook for the fourth quarter, and we'll conclude with a brief Q&A session. Our third quarter 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. I'll now turn the call over to Jim Lienert. Jim, please go ahead.

Thank you, Chris. Core income was $1.8 billion, or $2.18 per diluted share, in the third quarter this year compared to $1.2 billion, or $1.48 per diluted share, in the third quarter of last year. Net income was $1.8 billion, or $2.17 per diluted share, in the third quarter of 2011 compared to $1.2 billion, or $1.46 per diluted share, in the third quarter of 2010. The small difference between net and core income is due to discontinued operations. Here's a segment breakdown for the third quarter. Oil and Gas segment earnings for the third quarter of 2011 were $2.6 billion, the same as the second quarter of 2011 and compared to $1.8 billion in the third quarter of 2010. Higher volumes this quarter compared to the second quarter of 2011 resulted in flat quarter-to-quarter income despite lower prices. The improvement in 2011 over the same period in 2010 was driven by higher production in liquids prices. The third quarter 2011 realized prices increased on a year-over-year basis by 34% for crude oil, 41% for NGLs and remained about flat for domestic natural gas. Sales volumes, which are different than production volumes due to timing of liftings. We're 743,000 BOE per day compared to 713,000 BOE per day in the third quarter of 2010. Our production was 739,000 BOE per day compared to 706,000 in the third quarter of 2010, which included production from Libya. This represents a greater than 4.5% increase year-over-year, reflecting our continued focus on production growth. The third quarter production was also more than 3% higher than the second quarter 2011 volumes of 715,000 BOE per day. Domestically, our production was 436,000 BOE per day, representing the highest-ever domestic production volumes for the company compared to our guidance of 430,000 to 432,000 BOE per day. Our production in California rose by 6,000 BOE per day compared to the second quarter and contributed a large portion of the sequential increase in our overall domestic production volumes. Latin America volumes were 30,000 BOE per day. Columbia volumes decreased from the second quarter due to pipeline interruptions caused by insurgent activity. In the Middle East region, we recorded no production in Libya. In Iraq, we produced 4,000 BOE per day. Yemen daily production was 28,000 BOE, slightly ahead of our guidance. In Oman, the third quarter production was 79,000 BOE per day, an increase of 3,000 BOE per day over the second quarter volumes. In Qatar, the third quarter production was 73,000 BOE per day, an increase of 5,000 BOE per day over the second quarter volumes. The increase reflected the results of the development program, as well as maintenance issues that affected the second quarter volumes. In Dolphin and Bahrain combined, production increased 3,000 BOE per day from the second quarter volumes. Our third quarter sales volumes were 743,000 BOE per day compared to our guidance of 725,000 BOE per day. The improvement resulted mainly from the higher domestic production and the timing of liftings. Third quarter 2011 realized prices declined for all of our products from the second quarter of the year. Our worldwide crude oil realized price was $97.24 per barrel, a decrease of 6%. Worldwide NGLs were $56.06 per barrel, a decline of 3%, and domestic natural gas prices were about flat at $4.23 per MCF. Differentials improved in the quarter, resulting in realized oil prices representing 108% of the average WTI and 87% of the average Brent price. About 60% of Oxy's oil production tracks world oil prices, and 40% is indexed to WTI. For example, in California, our realized price was 114% of WTI and 91% of Brent in the third quarter. In Oman, our average price was 117% of WTI and 93% of Brent. Price changes at current global prices affect our quarterly earnings before income taxes by $38 million for a $1 per barrel change in oil prices and $7 million for a $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 $34 million. Oil and gas cash production costs were $12.36 a barrel for the first 9 months of 2011 compared with last year's 12-month cost of $10.19 a barrel. The cost increase reflects higher workover and maintenance activity, driven by our program to increase production at these higher levels of oil prices. Taxes other than on income, which are directly related to product prices, were $2.29 per barrel for the first 9 months of 2011 compared to $1.83 per barrel for all of 2010. Total exploration expense was $39 million in the quarter. Chemical segment earnings for the third quarter of 2011 were $245 million compared to $253 million in the second quarter of 2011 and $189 million in the third quarter of 2010. The improvement in third quarter results on a year-over-year basis reflects higher margins across most product lines. In addition, during the third quarter of 2011, we temporarily idled certain production in our Texas plants and sold power to the grid during the power shortage, resulting in an increase in the quarter's earnings. Midstream segment earnings for the third quarter of 2011 were $77 million compared to $187 million in the second quarter of 2011 and $163 million in the third quarter of 2010. The decreases from the second quarter and prior third quarter earnings were due to losses from our Phibro unit, both for the quarter and year-to-date, partially offset by higher pipeline income and increased power sales to the grid during the third quarter. The worldwide effective tax rate was 38% for the third quarter of 2011. Our third quarter U.S. and foreign tax rates are included in the Investor Relations' supplemental schedule. Let me now turn to Occidental's performance during the first 9 months. Core income was $5.2 billion, or $6.37 per diluted share, compared with $3.4 billion, or $4.14 per diluted share, in 2010. Net income was $5.1 billion, or $6.31 per diluted share, for the first 9 months of 2011 compared with $3.3 billion, or $4.07 per diluted share, in 2010. Cash flow from operations for the first 9 months of 2011 was $8.6 billion. We used $5 billion of the company's total cash flow to fund capital expenditures and $1.5 billion on net acquisitions and divestitures. We used $1.1 billion to pay dividends and had a net cash inflow from debt activity of $600 million. These and other net cash flows resulted in a $4 billion cash balance at September 30. Capital spending was $5 billion for the first 9 months, of which $2 billion was spent in the third quarter. Year-to-date capital expenditures by segment were 83% in Oil and Gas, 14% in Midstream and the remainder in Chemicals. Our net acquisition expenditures for the first 9 months were $1.5 billion, which are net of proceeds from the sale of our Argentina operations. The acquisitions included the South Texas purchase, properties in California and the Permian and a payment in connection with the signing of the Al Hosn gas project in Abu Dhabi, which is a gas development of the Shah Field. This payment was for Occidental's share of development expenditures incurred by the project prior to the date the final agreement was signed. The weighted average basic shares outstanding for the first 9 months of 2011 were $812.6 million, and the weighted average diluted shares outstanding were $813.3 million. Our debt-to-capitalization ratio was 14%, the same as the end of last year. During the third quarter of 2011, Oxy issued senior notes of $1.3 billion due in 2017 and $900 million due in 2022 at a weighted average interest rate of 2.3%, which brought the company's average effective borrowing rate down to 3.2%. Our annualized return on equity for the first 9 months of the year was 20%. Copies of the press release announcing our third quarter earnings and the Investor Relations supplemental schedules are available on our website at www.oxy.com or through the SEC's EDGAR system. I'll now turn the call over to Steve Chazen to discuss Oxy's strategy to maximize total shareholder return and provide guidance for the fourth quarter.

Thank you, Jim. This morning, I want to spend a few minutes discussing Occidental's overriding goal to maximize total shareholder return. We believe this can be achieved through a combination of: first, growing our oil and gas production by 5% to 8% a year on average over the long-term; second, allocating and deploying capital with a focus on achieving oil above cost of capital returns; and finally, consistent dividend growth. I'd like to give you an update of our progress year-to-date. Oil and gas production, the impact of our capital program and increase in drilling activity started to have a visible impact on our domestic oil and gas production volumes. Compared to the second quarter, our domestic production increased about 6,000 BOE per day per month compared to our guidance of 3,000 or 4,000 BOE per day. This increase resulted in domestic production of 436,000 BOE a day for the third quarter compared to 430,000 to 432,000 BOE a day guidance we gave you. Third quarter 2011 domestic production is the highest U.S. total production in Oxy's history, reflecting the highest-ever volumes for liquids. Compared to the prior year, total company third quarter production of 739,000 BOE a day was affected by a 7% decline in our international production. This reduction was a result of disruptions in the Middle East and North Africa and the impact of higher prices on our production sharing contract. On a year-over-year basis, our domestic production volumes increased by 15%. In our operations, we experienced disruptions affecting our production. Examples of such events in the third quarter of 2011 included the Elk Hills gas plant shutdown due to mechanical issues, mechanical issues with plants, compressors and pipelines in the Permian and Qatar and insurgent activity in Colombia that caused a significant portion of our production to be shut in for about 10 days. Without these events, our production would would've been 10,000 to 15,000 BOE a day or higher, which is more representative of our assets' current theoretical productive capacity. Some of these constraints have been removed, and we expect others removed over time. Others are not within our control and will reoccur. We believe our capital program will yield higher production growth and reliability over time. Turning to returns. Our return equity, as Jim pointed out, for the first 9 months was 20%. Our return on capital employed annualized for the first 9 months was 18%. We will continue to manage our capital program and acquisition strategy to yield well above cost of capital returns. Dividend growth is an important part of our total return to shareholders. Our ability to pay dividends is indicated by our free cash flow generation. Free cash flow after interest, taxes and capital spending but before dividends, acquisitions and debt activity for the first 9 months of the year, was $3.7 billion. Oxy's annual dividend rate is currently $1.84 per share, or about $1.1 billion for the first 9 months of 2011. Oxy has increased its dividends 10x in the last 9 years, resulting in a compound annual dividend growth rate of 15.6%. Keeping with our philosophy to raise the dividend on a consistent basis, the Board of Directors is expected to consider a dividend increase at the February meeting. Turning to a topic which I know is favored among at least some of you, share repurchases. The policy on possible share repurchase remains essentially unchanged. We do not do share repurchases as an alternative to dividends. We believe that dividends are given directly the shareholders while the effects of share repurchases on the stock price is at best murky. Therefore, you should not expect a program of regular share repurchases set to offset any shares issued on our employee programs. These share issues tend to be very small. If there's continuing excess cash, it will be used to boost the dividend rate. We do consider using the shareholders' capital to buy shares when the stock is trading at discount for the results we can expect from our capital acquisition program. To assist you in determining this, the analysis we employ is as follows: the value of the chemical and midstream assets that are not directly related to our production is determined. This is done on a very conservative basis. The debt and cash levels of the company are netted. The current capital program finding the development cost for each of oil and of gas are estimated. We use only proved reserves in the calculation, not probable or possible reserves, and we don't consider the value of acreage. The result of this analysis is not the value the company, but rather determination of whether the next dollars should be spent on capital or share repurchases. Normally, this results in a decision to invest in the business rather than a decision to buy in shares. When we do repurchase shares, we will make only the required public announcements in order to minimize what you pay for the stock, thereby enriching the remaining shareholders and not assisting the exiting ones. This approach eliminates our natural bias to think the stock is always undervalued and makes the calculations pretty straightforward. We have sufficient authority to purchase significant number of shares. Form 10-Q filings will show if any shares were purchased, at what price and how many shares remain authorized. Small repurchases are indicative of employee plan activities. We value the company's financial flexibility, especially in times of stress. It would be a disservice to our shareholders to impair that flexibility to achieve some theoretical short-term advantage. As we look ahead to the fourth quarter of the year, we expect oil and gas production to be as follows: Domestic volumes are expected to increase by about 3,000 to 4,000 BOE per day per month in the current quarterly average level of 436,000 BOE per day. This should result in a fourth quarter production of about 442,000 to 444,000 BOE per day. This would constitute a year-over-year domestic production growth rate exceeding 10% and about 6% a year production growth rate going forward. In terms of review of our major domestic assets. In California, for the year, we expect to drill and complete 154 shale wells outside of Elk Hills compared to the 107 wells we had indicated at the beginning of the year. Including Elk Hills, we expect to drill 195 shale wells for the year. We expect to drill and complete a total of 42 shale wells during the fourth quarter. Our experience has been the 30-day initial production rate for these wells, depending on areas between 300 and 400 barrels of oil equivalent per day. With respect to shale wells outside of Elk Hills, about 80% of the BOE production is a combination of black oil and high-value condensate. The cost of drilling and completing these wells has been running about $3.5 million per well, and we expect this to continue to decline over time. Our conventional drilling program is progressing somewhat better than planned. There has been no significant change in the -- of permitting issues in the state from our last call. We expect the current permitting levels to allow us to have our program go forward at these levels and enable us to continue to grow our production volumes in the state. We expect the production rig count to remain at the same 29 rig count, although we're likely to add a 30th rig by the end of the year based on a current outlook. In the Permian operations, our CO2 flood production is progressing according to plan. We expect our rig count to be about 24 in the fourth quarter. Our non-CO2 operations have stepped up their development program. This will not show significant production growth until next year. In the Williston, we are pursuing a development program with about 13 rigs expected to be running in the fourth quarter. Our production is growing as a result of the development program, and we expect the growth to continue. Natural gas prices in the United States continue to be, it says here weak, but I think, poor. As a result, we are considering cutting back our pure gas drilling in the midcontinent and possibly elsewhere. Internationally, we believe that once the current uncertainties are behind us, including the resolution of situations in Libya, the achievement of a sustained development program in Iraq, we will achieve production growth similar to our domestic operations. We expect that our fourth quarter international production to be about the same as the third quarter production, 4% higher than the second quarter of this year, which represented a low point of volumes following the situation in Libya. Colombia volumes should be modestly higher than the third quarter assuming no further pipeline attacks. The Middle East region is expected to be as follows in the fourth quarter: At this point, we expect no significant production from Libya. Our joint venture partnerships are currently in the process of resuming production, but production ramp-up will be hampered in the near term by lack of vehicles and personnel to address operational problems in the prolonged shut-in. In Iraq, we expect production to be similar to the last quarter. Going forward, we are still unable to reliably predict spending levels which determine production. In the remainder of the Middle East, we expect production to be comparable to third quarter volumes. At current -- at quarter end prices, we expect total production to increase to about 745,000 BOE a day as a result of the 3,000 to 4,000 BOE a day per month coming from the domestic production. We expect sales volumes to be around 740,000 a day to the timing of liftings. A $5 change in global oil prices would impact our production sharing contract daily volumes by about 3,000 BOE a day. We expect our total year capital expenditures to be about $7 billion. Additionally, we expect exploration expense to be about $100 million for seismic and drilling for exploration programs in the fourth quarter. Chemical segment fourth quarter earnings, which is historically the weakest quarter, are expected to be about $100 million. This reduction in the third quarter is due to seasonal slowdowns in many markets as construction, consumers' efforts to minimize inventories and the slowdown in exports. We expect our combined worldwide tax rate in the fourth quarter to remain at about 38%. So to summarize, our third quarter income of $2.18 was about 12% higher than the consensus estimate. Our third quarter oil and gas earnings of $2.6 billion were essentially unchanged to the second quarter despite a $6 per barrel decline in our average oil realizations. Our annualized return on equity was 20% for the first 9 months of 2011. Our total oil and gas production of 739,000 BOE a day during the third quarter. We had more than 3% compared to the second quarter. Domestic oil and gas volumes grew to 436,000 a day in the third quarter, 2% increase the second quarter and above our earlier guidance of 430,000 to 432,000 BOE a day. Domestic volumes are expected to further increase by about 3,000 or 4,000 BOE a day per month in the fourth quarter. I think we're now ready to take your questions as long as they're brief.

[Operator Instructions] Your first question comes from Paul Sankey of Deutsche Bank.

Steve, one on the Bakken actually. Your activity levels there seem very aggressive relative to your acreage. Can you just talk more about how you're seeing that play?

Well, at the end of the year, I think we had 171,000 acres, and we may have picked up some more acreage during the year. The wells are actually doing very well. Some of the small piece we had outside of the stuff we bought the end of last year has yielded some surprisingly positive results. Costs are a little high up there, but they seem to be coming down. So I...

Would you mind putting some numbers around some of those comments?

Well, the wells vary from where they are. So maybe Bill could answer the question on the well cost.

Yes, Paul, as Steve said, the costs are coming down. We're somewhere in the $8 million to $8.5 million range, drilling complete, but the trend is down.

Yes, and the results?

We started the year I think at 2,500 a day? 3,000? And we're running sort of around 7,000 or 8,000 currently. With a little walk, we'll exit closer to 10,000.

And would you be looking to buy more acreage up there, Steve, based on that?

I think I told you that every day, somebody shows up with some acreage to buy. So if we were open on Saturday and Sunday, we could have it 7 days a week. So there's really plenty to buy, and we're sort of picky on where we buy it. So if it's additive to what we have and something we understand, we'd probably pick up some acreage. We're not interested in company acquisitions at all.

Got you. Steve, you gave away almost all your midstream profitability, but you get it back in marketing and trading. One thing of service that -- that segment seems to performed very poorly when oil equities have a bad quarter, which I would have thought exacerbates your volatility to the downside as a stock. Can you just talk a little bit how you're seeing that segment now and whether -- where we go from here?

The segment's fine. There's certainly volatility in Phibro's results and just depends on what day you choose to measure it. You measured it today, you probably made up all that you've lost for the whole year and maybe then some. So it's pretty volatile. I mean, it wasn't intended as a hedge. It's really long oil, and so are we. So I'm not interested in hedging the company's outcome. I'm sort of long-term modestly bullish on oil prices. Not as bullish as Phibro, but modestly bullish. So I'm not really bothered by this. I think over time, we're a pretty decent-return business. It turned out to be not so decent return. It's pretty easy to exit. So I'm really not bothered by the volatility. I know you might be, but the volatility -- being long oil is sort of where we are.

Yes, but I don't understand, though, is you said that it's actually long oil, but it seems to have the worst quarters when it's the oil equities that go down a lot. I mean, I'm thinking post-Macondo was a bad one, and then it doesn't seem the rate of change in oil was quite as bad as this result would've suggested unless...

He was investing in some equities, and he's not doing that anymore.

Ah, okay. And so far, this quarter, if we stopped here, things are going well in that segment?

Yes. But again, this is the NBA game problem. No sense in tuning in till the last minute. Or a Michigan State, Wisconsin problem.

Your next question comes from Jessica Chipman of Tudor, Pickering. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Two quick questions on the California side. First, just California liquids have grown nicely after bottoming really Q4 of last year. How should we think about splitting growth going forward between conventional and unconventional drilling?

We cut back on our conventional so we could think about it some more since it requires a little more thought than the shale drilling. And I think that's had a positive effect on our results. I think we're more thoughtful, and we're getting better results. So we'll do the conventional when we -- it'll pick up as we get better results. But the results in the last quarter conventionally were pretty good. So I don't have an easy answer for you. So it just depends on how things go. Basically, the base growth comes from the shale drilling. And every so often, you'll have a successful conventional thing, which will boost -- you get an unusually high boost. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And you did have some of that this quarter?

It sure looks that way, don't it? Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. The second question, just -- you expect to drill, I think, and complete 154 shale wells outside of Elk Hills. How many of those are actually going to be hooked up in terms of sales?

Virtually all of them, probably. The way we count them is -- they don't count till they're actually flowing into the line. Complete includes hooking them up. Otherwise, you get some odd results. We're trying to get the time down between completing and hooking up. So we're only -- for your purpose, all we're doing this counting when they get hooked up.

Your next question comes from Doug Leggate of Bank of America Merrill Lynch.

Steve, I'm sorry, a couple if I may. Updates on the gas funds for 2012, just the timing of commissioning and given your comments on how weak I think you said are up here, gas prices are. How's your appetite for getting that thing done as quickly as perhaps we might [indiscernible].

Well, the plant's really handled by a contractor. I mean, he has a date, he's got to deal with it by so. It's going to be on roughly May 1. It doesn't make a difference what I think about gas prices.

Right. And so will we -- should we all think about 2012 as being a lumpy year for production? In terms of growth?

Every year is lumpy. I don't think you hadn't noticed. So yes, it could be lumpier than normal. I'm still concerned about giving away gas. Even California gas a little higher, but at $4. Even though the conventional wells have a significant amount of condensate in them, but seems wasteful to sell gas for $4.

Okay. And just a couple on the shale if I may. Why is the growth of 6,000 barrels a day per month obviously beat your prior guidance? Why is it going to slow back to 3,000 to 4,000?

I think I actually answered it in the last question. The 3,000 to 4,000 is for the whole domestic business. It turned out that we got it all in California, and the rest of the domestic business sort of equaled it. But I'm using the shale wells to drive the 3,000 to 4,000. And if I get lucky -- the conventional wells are significantly more profitable than the shale wells. In the case of maybe a shale well, you might take it 90 days to get your money back, and a conventional well might take 2 weeks. But it's less predictable. So you see, we're giving you the predictable number, and every so often, we'll do a little better, or if there's some mechanical problem, a little worse. But that's really what we're trying to do is give you something you could can count on. If we do a little better, we'd do a little better.

Last one for me is I think a few months back, I attended a dinner, you were speaking at obviously, and you said your kind of first base target was to drill about 300 wells a year on the California shale. So I'm curious where do you stand in terms of pushing forward the permit process? And do you think that's still a reasonable first base target? If so, when do you expect to get there? I'll leave it at that.

I really think at this point the program we have is all we can really count on from state permitting. Whatever portion of the 30 rigs that we're going to run in California is related to that. As the permitting process that we hope improves, then we'll get there. Predicting what somebody in the State of California might do is way -- makes predicting oil prices easy. And so I think you got to say that right now, this is sort of where we are, and I don't know -- I can't really give you a realistic number. I think as a practical matter, we could get there if we had the permits. The permitting process -- I mean, the difficulty is -- I mean, there's 2 elements of it. First, it makes it really hard to plan because while you got a visible supply of permits, it does depend on getting more, and it used to be that you sort of have an infinite supply. Second thing is if you find something, it makes it really hard to follow up because you might not have a permit for the next lease or something. So it makes the program significantly more inefficient than you might like it to be and makes it hard to plan. The other issue in the permitting, which probably has very little really effect on us currently is the injector wells. A lot of -- most of the production in California is not ours but generally, is from either steam or something or some kind of injector program. And the state is studying that more carefully now. So that has a significant impact on people who are mostly steam generators in the state as steam-based oil production. And the state is pretty tight on that, has -- the only place it's affected is [indiscernible] given long enough, it might, but -- and is in Long Beach. And it's a small effect, and it really just affects the income the way the contract works, the income of the state, the city, and the port of Long Beach. So I guess, by not making the injector wells, they like the lower level of income.

Your next question comes from Jason Gammel of Macquarie.

Steve, I just wanted to ask about your permitting operations, and appreciate you said that you don't expect the development program outside the CO2 operations to show a production growth until next year. But I just wanted to ask about the rig count of 24. How many of those rigs are actually being devoted to that development program? And are you primarily drilling Wolfberry and Wolfcamp-type wells with those rigs?

Yes, Bill will answer that.

Yes, Jason. We've got -- we're expecting a range of somewhere between 14 and 16 of those rigs working the development side of the Permian. And of those rigs, we're going to probably run 9 to 10 in the Wolfberry.

Again, note that these are -- remind you that these are our operated, and we have a whole bunch of other activity where somebody else is operating. All we're giving you is our operated.

Understood, understood. If I can just shift internationally, the production in Oman continues to show a steady uptick. I assume that is discontinued affects from the Mukhaizna steam injection program. How much more do you have to go on, on Mukhaizna, Steve? Is there something that is still a multi-year growth? Or are we starting to near the plateau there?

Well, it's really caused by 2 elements, and Sandy can cover that. But the old traditional stuff is actually doing very well in the north, and Mukhaizna's doing well. So I'll let Sandy answer your question.

Yes. Mukhaizna today is running 120,000 barrels a day gross. And during 2012, we're adding another 200,000 barrels a day of steam injectability. So that will ramp us up to around 150,000 barrels a day at the end of 2012 or maybe first quarter 2013. As Steve said, the northern Oman is running 99,000 100,000 barrels day gross, which is the highest it's ever sustained in our 25 years. So both looking good.

And Sandy, would there be any further injection phases after that one? Or is that something that you should be studying now?

We're planning to have 600,000, 625,000 barrels a day of steam. There's possibility of adding more later, but it's not yet in the plan.

These plans are approved in stages by the government and other people. So you don't give them a 30-year plan, sort of a 30-month plan.

Your next question comes from Arjun Murti of Goldman Sachs.

Steve, you have an update on the non-shale California exploration program?

Well, that was the conventional I was referring to. So I think you can see the -- again, the base guidance roughly or -- if you thought about maybe 1/2 of the growth or a little more, that we'd tell you the 3,000 to 4,000 a month is from the monotonous shorter shale drilling. The rest of it -- if you see an odd number, it comes from that program. So I think you should view it that way. The other way to view it, just to be honest, when we give you our exploration expense, it's not worth a darn every quarter, but on a cumulative basis for the year. It's basically done by risking each of the wells. So we say, well, this is a 15% chance of success. This is a 30%, and we add that up and that's what we give you as the exploration expense. When we continually are lower, you should assume we're having more success than we planned. And a lot of that would be in California, some in Colombia and some in Oman.

And I guess, a few years ago, you announced the larger Kern County discovery. Presumably, you've not had one of that size, or we might have heard about it. Any...

You might have.

We might not have.

That's right.

That's fine. A follow-up on the Bakken. You've always described it as a science experiment. These slides I think are easily the most positive you've ever been on it, by your standards at least...

Yes. It's like gas.

Is it still like you need to do a bigger transaction to step up here? The prices are obviously high. There was a recent big transaction. Do you just patiently wait out the next downturn? Or how -- I mean, how do you think about scaling your Bakken? Just patience?

I think I said earlier, this recent price that some national oil company paid for some stuff, is not reflective of what we're paying for acreage with the tax basis. And so I say there's a lot of -- I mean, whatever number of acreage you want to have, given a year or 2, you can get. So somebody's here, I'm not kidding, virtually every day with some deal to buy 7,000 or 8,000 or 12,000 or 15,000 acres. If it fits our business model, we look at it. If it doesn't, we don't. But there's no real shortage of opportunity. The leases expire. They roll over. There's really a lot going on. The prices are not -- I don't think that the recent transaction is reflective of the market. I think that was a special deal for national oil companies.

Right. So the kind of nagging concern some have that we should be braced for some inevitable big transaction [indiscernible] Yes.

The purpose of an acquisition is to make the company better, not worse. We're not -- we have plenty to do in our current portfolio, so we're looking for ways to make the company better or stronger. We're not looking for ways to dilute the outcome.

And just a final quick one, Steve, any early thoughts on 2012 CapEx?

I don't really know where I am. We've got a lot of uncertainty about the level in Iraq. The Shah gas field, some uncertainty there. We don't know what we're going to have to spend going into Libya, something, I presume, at least for trucks. So there's at least some expenditure in Libya. The U.S. business has a huge opportunity set of high return, relatively high-return projects in aggregate, probably beyond what I would be willing to commit to next year. So we'll push that off a little bit. So I really don't know where I am. We're not going to negative cash flow, that's for sure.

Your next question comes from Doug Terreson of ISI.

Steve, I have a couple of questions on Bahrain. First, there seems to be some movement over there on the changes to the natural guys price regime in that country and also, there seems to be movement on approval for your deep gas exploration plan. So I wanted to see if we could get an update on the status of those 2 items to the degree possible?

The deep gas -- I mean, the government's approved the deep gas drill. So some time, there's a seismic -- there appears there's some seismic, and I assume the well to be drilled as soon as we get -- as soon as we can. Might be -- probably going to be next year at this point. I don't know anything about gas, Sandy doesn't know anything either, so I don't know what's going on there.

Your next question comes from Sven Del Pozzo of IHS Herold.

Late 2010, I think you guys made some comments regarding what point we are in the life cycle of your CO2 floods in Texas. And then I wonder if we can tie -- if you could make similar comments this time around and perhaps tie it into the 5% to 8% long-term production growth rate?

Well, the CO2 floods normally, you have a period of increased gas injection, and then it takes 2 or 3 years for the results to show up. So the increased injection began, say, early this year, maybe middle of this year. So it'll -- you'll start to see the effects of it a couple of years from now.

Okay. So a similar kind of question on California shales -- no, no, just, sorry, total California production as a whole. In the past, you guys mentioned it would grow to equal that of Texas by 2013, I believe, was the year, correct me if I'm wrong. How's that tie into the 5% to 8% production growth rate long term?

It obviously does. It's growing -- the domestic production's growing so that if you use the 3,000 to 4,000 a month, it's growing 6% a year. So eyes on pretty good I think.

So is there a chance -- it might sound like things might be getting better. I mean is there...

You got to watch this quarterly stuff. You can have a good quarter and a bad quarter. So, maybe they're getting better, but on the ground, it's better, but there's always interruptions and stuff which make one quarter or some other quarter look good or not so good. So right now, on the ground, we're doing fine, both in the Permian and in California, and we're pretty confident about the growth over time. So I don't think there's much problem with the growth per month that we've said, and it could do better I suppose. But I mean, over time, I think it will, but probably not. It's just not that predictable quarter-to-quarter.

Okay. And then in the Midstream, I did see a pretty big jump year-over-year in terms of the Midstream CapEx. What's that related to? And if so, how much of that relates to your E&P business?

It's gas plants.

Your next question comes from John Herrlin of Societe Generale.

Steve, when you look at your growth going forward, you said you're going to do less gas. We assume that's going to be more like 2/3 liquids, crude and liquids versus 1/2 and 1/2, because your current growth has been kind of split.

Yes.

In the U.S.

I mean, where we're going to cut back easily is in the mid-continent where the gas is real dry. No sense in drilling. So you might see -- if you could see it, you might see a decline in something like the Hugoton or something like that where the gas is dry and wells are cheap. And it just drives you nuts to give it away for $3.50. You may make money at that, but I'd rather defer it.

Okay. With respect to California, your split in terms of sequential buying growth was also 50-50, liquids versus gas.

This goes back to the conventional. If you have a conventional -- conventionals are -- the Kern County-type discovery is a gas condensate reservoir. And if you happen to hit one of those, you're going to get a lot of gas and a lot of condensate. The gas is just gas, and the condensate really pays for the whole well.

Got it. With respect to your black oil, sequential line growth in California was 2,000 barrels sequentially. How much was that from your conventional operations versus the new shale type plays?

I don't really know. But my guess is the conventional added a fair amount to it.

Okay. Last one for me. You mentioned earlier with exploration expenses that when you miss on the plus side, so to speak, it's because you're having more success...

More success than the risking would have generated.

Correct. And essentially, you had overestimated by 50% basically.

And if you go back and do the -- I wouldn't focus on a single quarter because it could be just delays. But if you look at the 9 months, I think if you went back and looked at what we said and what we actually did over the 9 months, you'll find that we're pretty far below.

Okay. And then last one for me, you said of the chemical ops that you opted to sell power, how much net income did you make off that? Just...

$40 million.

Your next question comes from Ed Westlake of Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: But just a small one on the shale, well cost, the $3.5 that include hook-up? I mean what's the total cost?

Yes. We don't do what the small producers do and just give you. That includes the site -- well, let's build out the site, hook up the completion. It's not just some part of the cost. Edward Westlake - Crédit Suisse AG, Research Division: And then any update on Yemen?

We really don't know anything. I think it's fair to say. It's hard to negotiate with the government there since it's hard tell what's going on. Sandy, anything?

The only -- one of our fields is down for a while, another insurgency. But the production's holding well. Our share's well up to what we predicted, and we just don't know anything about the Masilla block yet.

Masilla's about 8,000 a day, by the way, just so you have scale for it out of the total. Edward Westlake - Crédit Suisse AG, Research Division: And then on the overall, I mean what you pick up as you walk around, some people are concerned about CO2 availability and then other people are concerned about competency in shales. I mean, these are just things that it would be interesting to hear your thoughts on?

We don't know. A lot of the discussion of the CO2 is about small producers who have different issues. Our competency, well -- I think the answer comes from the production. If we make our production that grows, you'll assume we're competent. And if we don't, you'll assume we're incompetent. Edward Westlake - Crédit Suisse AG, Research Division: I guess the question is linked back to Arjun's question earlier on the Bakken is that when I'm talking about shales, I'm talking about shales outside your corer assets.

Oh, Bakken? Edward Westlake - Crédit Suisse AG, Research Division: Yes. And...

I think we have some -- we've undergone some learning clearly in the beginning. This isn't exactly state secret up there. We got always vendors who are reasonably experienced. So I think we've come up learning curve nicely. We have some more to learn for sure. But I don't think there's any -- our productivity, because we benchmark ourselves, is the same as other people in the same area, sometimes better but sometimes a little worse. But I think it's pretty much the same, so we don't have a productivity issue whether we're competent or not up there. We'll know here in the next couple of years.

[Operator Instructions] Your next question comes from Pavel Molchanov of Raymond James. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Just one quick one if I may. Other than shortage of vehicles and other logistical issues, are there any legal or political hurdles at the moment to you resuming operations in Libya? Sanctions or something like that?

Our operations in the fields where we have interest have slowly started coming back on by the operators themselves. We actually have a management team going in there this weekend to visit with all of the government entities that we normally deal with. And I would say that we don't expect any surprises but I wouldn't want to really bet on that until after we have some meetings with them. But indications are that they're willing and happy to have us come back in and resume where we left off.

I don't think there's any U.S. issues, if that's the question. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. Do you expect the fiscal terms to be in line with what they were under the previous government?

All indications are that they're going to honor the contracts that are -- that were in existence when this war started.

Your next question comes from Ann Kohler of CRT Capital Group.

Just in looking at the Libyan situation following on to that question, do you think that there are opportunities, and maybe too early, but additional opportunities that the new government might like to expedite additional work? Or is it not -- is it too early...

I think it's just too early to talk about that. It just depends on how they want to manage their industry. Right now, they have to put up half the capital. And whether they want to do that in the future or not really determines they want continue to invest their path to capital. If they don't want to, then there'll be other opportunities. Just hard to say, because you don't really know what it'll look like a year from now.

Great. And then just on the acquisition side, if you could just give us sort of an update. A year ago, you indicated that you didn't expect that you'd have a lot of action or acquisition, and then you certainly did step things up the very end of the year. Could you just provide us a little update and color on the types of opportunities? I would assume that -- I guess in the last couple of calls, you've indicated that you really weren't interested in necessarily just adding acreage in California, and it sounds as though you would be selective in looking at opportunities within the Bakken?

I don't know if I would interpret my remarks that way. We always look for stuff in California that fits our business. So I don't think it's like we always add something to California. As far as the Bakken is concerned, we look at a lot of fairly small opportunities. I'll repeat what I said before, we're not interested in a large corporate-type acquisition.

Your next question comes from Jeff Dietert, Simmons. Jeffrey A. Dietert - Simmons & Company International, Research Division: Sorry to go back on California shale, but wanted to ask a pretty substantial increase in the number of shale wells expected to be completed, the 154. Could you talk about how that -- if the pace is accelerating, maybe what -- that looks like in third quarter and perhaps in fourth quarter as far as number of wells completed?

I think we actually give you -- I gave you the fourth quarter in my remarks. But as the well cost come down, that's basically reflecting the -- it's reflecting the fact that I'm getting more for my money and therefore, I'll drill more wells. If we started at the beginning of the year and we thought the wells were going to cost $4.5 million, we would have said some number of wells because that's how long it takes, but we're shorting the time. So the costs come down and you drill more wells in the year. So that's what's really going on here, I think, right now. This is pretty much what we have planned as far as the rig count.

You have a follow-up question from Doug Leggate of Bank of America Merrill Lynch.

Steve, I wanted to go back to your prepared remarks. You are not, by any chance, signaling a change of view in share buybacks with your commentary on that. Could you maybe just give us some clarity as to exactly what you were kind of signal there in terms of your share buybacks rank, given how much cash flow you're throwing off right now?

I'll read the relevant parts from the remarks, if you'd like, if that's helpful.

I guess.

I'll edit out the irrelevant portions. We will not have some kind of regular program in lieu of dividends, which is what some companies do. We think dividends are more effective. We've had this discussion over the last decade. So that's what we think. What we are saying here is that when the -- I'll just make up a number. If we're trading below what I think our F&D is or what I could acquire assets for, which is roughly the same, then we'll shift the money from the capital program or from our free cash or from the acquisition program into share repurchases. And that's actually -- in recent times, that's happened. So that's what we're saying. So you shouldn't expect every quarter we're going to spend $1 zillion no matter what the price is. But if the price -- if our capital program isn't -- can't add value compared to buying shares, then the shares will be repurchased.

Is there an operational limit on your capital program though? In other words, what you're capable of actually dealing with, relative to the cash flow you're throwing off? Has this become a governor for managing your balance sheet?

From a point of view, I could spend a lot of money on share repurchases. We're sitting on $4 billion of cash, I don't know if you missed that. And we don't really have -- I bought -- I took the cash because it was cheap and provide some insurance for the volatility that's in the market. But we got plenty of flexibility to repurchase the shares if they don't reflect -- if it reflects essentially below replacement cost of the reserves. So if I think that the price replacement cost or our finding and development costs, however you want to describe it, is $2 a barrel, and the stock is trading for $1 a barrel. I'll take all the money we have and dump it into the share repurchase, because it gives a better outcome for the shareholders. Other hand, if our finding and development cost is $2 and the stock is trading for $12 a barrel, the shareholders are better off us investing in the business because you've got the multiplier. This is a complicated way. This is exactly what Warren Buffett said actually, except that he tied it to book value. The book value isn't a very useful measure for us, so I'm tying this to replacement cost. So if the stock is cheap enough, the company will repurchase it because that helps the remaining shareholders. But we're also going to do it in a way that doesn't -- trying to reward the remaining shareholders, not assist the exiting ones.

Your final question comes from John Herrlin of Societe Generale.

One final for me, Steve. In terms of your production growth this year, how much of it's been in the U.S. acquisition versus accelerated spending?

The only -- in the U.S., the Williston started out I think at 2,000 or 3,000 a day. So you can decide for yourself. We bought the acreage obviously, but we didn't buy a lot of production. South Texas is -- was bought, although there's been some growth. And we bought $20 million a day of gas in California. 10 showed up in the last quarter and 10 more in this quarter because it's only a partial quarter. So there really isn't very much of it that's -- where we bought production. Now we bought acreage or opportunity, and we drill it up. But it just depends on how you want to describe, get a -- If you want to go back long enough, Elk Hills was bought too.

And there are no further questions. Are there any closing remarks?

No, that's fine.

Thanks, and if there's any further questions, call us here in New York. Thanks for listening everyone.

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