Occidental Petroleum Corporation (OXY) Q4 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 Fourth Quarter 2011 Earnings Release Conference Call. [Operator Instructions] Mr. Stavros, you may begin your conference.

Thank you, Christie, and good morning to everyone. Welcome to Occidental Petroleum's Fourth Quarter and Full Year 2011 Earnings Conference Call. Joining us on the call this morning from Los Angeles are Steve Chazen, OXY's President and Chief Executive Officer; Lienert, OXY's Chief Financial Officer; Albrecht, President of our Domestic Oil and Gas operations; Sandy Lowe, President of our International Oil and Gas business. And also listening in on the call is our Executive Chairman, Dr. Ray Irani. 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 fourth quarter and full year of 2011. Steve Chazen will then follow with comments outlining our 2012 capital program and our outlook for our oil and gas production for the first half of this year. We'll conclude with a brief Q&A session after Steve's comments. Our fourth quarter and full year 2011 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, www.oxy.com. I'll now turn the call over to Jim. Jim, please go ahead.

Thank you, Chris. Net income was $1.6 billion or $2.01 per diluted share in the fourth quarter of 2011, compared to $1.2 billion or $1.49 per diluted share in the fourth quarter of 2010. Our consolidated pretax income from continuing operations in the fourth quarter of 2011 was about $2.6 billion, $2.02 per diluted share after tax, compared to approximately $2.9 billion, $2.18 per diluted share after tax, in the third quarter of 2011. Major items resulting in the difference between the third and fourth quarter income included higher oil volumes and prices, which added $0.07 per diluted share after tax to our fourth quarter income; lower fourth quarter chemical and midstream income of $0.08 per diluted share; higher equity-based compensation cost of $0.05 per diluted share; higher exploration expense of $0.02 per diluted share; and higher fourth quarter operating costs of $0.08 per diluted share. Here's the segment breakdown for the fourth quarter. In the oil and gas segment, the fourth quarter 2011 production of 748,000 BOE per day was 9,000 BOE per day higher than the third quarter 2011 volumes of 739,000 BOE per day. Domestically, our production was 449,000 BOE per day, representing the highest ever domestic production volumes for the company, compared to our guidance of 442,000 to 444,000 BOE per day. Our production costs rose by 13,000 BOE per day compared to the third quarter, with the Permian and California contributing the bulk of sequential increase in our overall domestic production volumes. Our better-than-expected fourth quarter domestic production reflected the effect of the ramp-up in capital spending, as well as higher levels of workover and well maintenance activity. In addition, the fourth quarter was relatively free of significant operational disruptions, which also contributed to the better-than-expected results. Latin America volumes were 31,000 BOE per day. Colombia volumes increased slightly from the third quarter, while both periods included pipeline interruptions caused by insurgent activity. In the Middle East region, we recorded "1,000 BOE per day" production in Libya. In Iraq, we produced 9,000 BOE per day, an increase of 5,000 BOE per day from the third quarter volumes. The higher volume is a result of higher spending levels. Yemen daily production was 23,000 BOE, a decrease of 5,000 BOE from the third quarter. The decrease reflected the timing of cost recovery and the expiration of Masila field contract in mid-December. In Oman, the fourth quarter production was 76,000 BOE per day, a decrease of 3,000 BOE per day from the third quarter volumes. The decrease was attributable to downtime from operational issues. In Qatar, the fourth quarter production was 76,000 BOE per day, an increase of 3,000 BOE per day over the third quarter volumes. In Dolphin and Bahrain combined, production decreased 6,000 BOE per day from the third quarter volumes. Dolphin volumes declined 9,000 BOE per day because, during the quarter, they reached annual maximum volumes allowed under its contract. Our fourth quarter sales volumes were 749,000 BOE per day compared to our guidance of 740,000 BOE per day. The improvement resulted from the higher domestic production. Fourth quarter 2011 realized prices were mixed for our products compared to the third quarter of the year. Our worldwide crude oil price -- crude oil realized price was $99.62 per barrel, an increase of 2.5%. Worldwide NGLs were $55.25 per barrel, a decrease of about 1.5%, and domestic natural gas prices were $3.59 per MCF, a decline of 15%. Realized oil prices for the quarter represented 106% of the average WTI and 91% of the average Brent price. Realized NGL prices were 59% of WTI and realized domestic gas prices were 98% of NYMEX. Price changes on current global prices affect our quarterly earnings before income tax by $38 million for a $1-per-barrel change in oil prices and $8 million for a $1-per-barrel change in NGL prices. A swing of $0.50 per million BTUs in domestic gas prices reflects -- affects quarterly pretax earnings by about $31 million. Fourth quarter operating costs were about $130 million higher than the third quarter, as a result of higher workover and well maintenance activity, driven by our program to increase production at these higher levels of oil prices. Oil and gas cash production costs were $12.84 a barrel for the 12 months of 2011 compared with last year's 12-month costs of $10.19 a barrel. The cost increase reflects the higher workover and maintenance activity I mentioned earlier. Taxes other than on income, which are directly related to product prices, were $2.21 per barrel for the 12 months of 2011 compared to $1.83 per barrel for all of 2010. Fourth quarter exploration expense, which included the impairment of several smaller leases, was $73 million. Chemical segment earnings for the fourth quarter of 2011 were $144 million compared to $245 million in the third quarter of 2011. The drop in income was a result of seasonal factors. Midstream segment earnings of $70 million for the fourth quarter of 2011 were comparable to the $77 million in the third quarter of 2011. The significantly higher year end OXY stock price, compared to the distressed levels at the end of the third quarter, affected the quarterly valuation of equity-based compensation plans, reducing fourth quarter pretax income of the company compared to the third quarter by $80 million. The worldwide effective tax rate was 37% for the fourth quarter of 2011. Our fourth 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 12 months. Core income was $6.8 billion or $8.39 per diluted share, compared with $4.7 billion or $5.72 per diluted share in 2010. Net income was $6.8 billion or $8.32 per diluted share for the 12 months of 2011, compared with $4.5 billion or $5.56 per diluted share in 2010. Cash flow from operations for the 12 months of 2011 was $12.3 billion. We used $7.5 billion of the company's total cash flow to fund capital expenditures and $2.2 billion on net acquisitions and divestitures. We used $1.4 billion to pay dividends and had a net cash inflow from that activity of $0.6 billion. These and other net cash flows resulted in a $3.8 billion cash balance at December 31. Looking at overall cash flow simply, our total debt, net of cash, was $2.1 billion at December 31, 2011, compared to $2.5 billion at December 31, 2010, representing net cash generated by the company of $0.4 billion. During this period, we returned $1.7 billion to our stockholders in the form of $1.4 billion of dividends and $275 million of stock buybacks. Over 2 years, our net debt at December 31, 2011, was $0.5 billion higher compared to the $1.6 billion at December 31, 2009. During this period, we returned $2.9 billion to our stockholders in the form of dividends and stock buybacks, while executing an $11.5-billion capital program and spending about $6.9 billion on acquisitions. Capital expenditures for 2011 were approximately $7.5 billion, of which about $2.6 billion was incurred in the fourth quarter. The fourth quarter higher capital partially reflected the gradual ramp-up of our capital program during 2011. The increases were mostly at Williston domestically and Iraq, Oman and Qatar internationally. The fourth quarter capital also included spending for several midstream projects such as the Elk Hills gas processing plant, which will drop significantly during the first half of 2012 as these projects are completed. Total year capital expenditures by segment were 82% in oil and gas; 14% in midstream and the remainder in chemicals. Our net acquisition expenditures in the 12 months were $2.2 billion, which are net of proceeds from the sale of our Argentina operations. The acquisitions included a South Texas purchase; properties in California, the Permian and Williston; and a payment in connection with the signing of the Al Hosn gas project in Abu Dhabi, which is the 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 12 months of 2011 were 812.1 million and the weighted-average diluted shares outstanding were 812.9 million. Our debt-to-capitalization ratio was 13%, a decline of 1% from the end of last year. Our return on equity for 2011 was 19.3% and the return on capital employed was 17.2%. Oil and gas DD&A expense was $11.48 per BOE for 2011. We expect the oil and gas segment DD&A rate to be about $14 per barrel in 2012. The total chemical and midstream DD&A expense is expected to be about $650 million for 2012. We expect the operating cost per barrel to be about $13.75 in 2012. The 2012 expected costs reflect higher levels of workovers and well maintenance activity. However, significant and substantial product price changes and changes in activity levels and inflation resulting from product prices may affect this cost estimate during the course of the year. Copies of the press release announcing our fourth 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 discuss our 2012 capital program, year-end oil and gas reserves, and provide guidance for the first half of the year.

Thank you, Jim. We finished a strong year in terms of the 3 main performance criteria that I outlined last quarter. Our domestic oil and gas production grew by about 12% for the total year to 428,000 BOE per day. Fourth quarter domestic production of 449,000 BOE a day is the highest U.S. total production in OXY's history, reflecting the highest ever quarterly liquids volume of 310,000 barrels per day, the second highest quarterly volume for gas. Total company production increased about 4% for the year. Our chemical business delivered exceptional results for the year, achieving one of their highest earnings levels ever. Our return on equity was 19% for the year and our return on capital was 17%. We increased our annual dividends by $0.32 or 21% to $1.84 per share. We expect to announce a further dividend increase after the meeting of our Board of Directors, the 2nd week of February. I will now turn to the 2012 capital program. As I mentioned last call, we have ample legitimate opportunities in our domestic oil and gas business where we could deploy capital. We have tried to manage the program to a level that is realistic at current prices and as a result, have deferred some projects that would otherwise have met our hurdle rates. We continue to have a substantial inventory of high-return projects to fulfill our growth objectives. We're increasing our capital program by about 10% in 2012 to $8.3 billion from the $7.5 billion we spent in 2011. About $500 million of this increase will be in the United States, mainly in the Permian basin, and the rest will be spent in the international projects, including the Al Hosn sour gas project in Iraq. The program breakdown is 84% oil and gas, about 11% in midstream and 5% in chemicals. We will review our capital program around midyear and adjust as conditions dictate. The following is a geographic overview of the program. In domestic oil and gas and related midstream projects, development capital will be about 55% of our total program. In California, we expect to spend about 21% of our total capital. We expect the rig count to remain constant in the first half of 2012 to 31, same as what we were running at the end of the 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 production volumes. We will reassess our capital program when the number of permits in hand allows it. The Permian operations, we expect to spend about 20% of our total capital program. The rig count at year-end 2011 was 23. We expect the rig count to ramp up during the year to around 27 rigs by year end. Our CO2 flood capital should remain comfortable to 2011 levels. In our non-CO2 operations, we are seeing additional opportunities for good-return projects. As a result, we have stepped up their development program, and our 2012 capital will be about 75% higher than 2011 levels. In the Midcontinent and other operations, we plan to spend about 14% of our total capital. In the Williston, we have increased our acreage in 2011 from 204,000 acres to 277,000 acres. We expect that our rig count will be about 6 at the end of 2012. Additional capital that could reasonably be deployed here has been shifted to higher-return opportunities in California and the Permian. This may also encourage Bakken well costs to decline. Natural gas prices in the United States are -- it's written here, "horrible." I think that's probably an understatement. As a result, we are cutting back our pure gas drilling in the Midcontinent, South Texas and the Permian. With regard to international capital spending, our total international development capital will be about 30% of the total company capital program. The Al Hosn Shah gas project will continue to increase spending in 2012 as originally planned, making up about 7% of our total capital program for the year. The rest of international operations capital will be comparable to 2011, with modest increase expected in Iraq and Libya. In Iraq, the planned spending level should generate about 11,000 barrels a day of production. Each additional $100 million in spending, incurred evenly through the year, would generate about 2,700 barrels a day of production at current price levels. Exploration capital should increase about 10% over 2011 spending levels and represents 6% of the total capital program. The focus of the program domestically will continue to be in California and the Permian and Williston basins, with additional activity in Oman and Bahrain. With regard to our oil and gas reserves, we haven't completed determination of our year-end reserve levels. Based on preliminary estimates, our reserve replacement levels from all categories are somewhat over 100%. In the Middle East/North Africa, the highly profitable Dolphin project does not replace its production because of the nature of its contract. The makes overall reserve replacement for the Middle East/North Africa region very difficult. Despite this fact, the 2011 program, which includes only the reserve carry or its extensions to discoveries and improved recovery, covered about 70% of the region's productions. Oil price increases, which under the production sharing contracts, reduce our share of the reserves; and non-fundamental factors in Libya and Iraq, essentially negated the reserve adds to the program. As the program progresses, we expect that Libya and Iraq reserves will be restored. In the United States, the results of 2011 program and acquisitions replaced around 250% of production with both elements contributing about equal amounts. After price and other adjustments to prior year estimates, U.S. reserve replacement was well over 150%. As we look ahead to 2012, we expect the oil and gas production to be as follows: During the first half of 2012, we expect our domestic production to grow 3,000 to 4,000 BOE a day per month in the current quarterly average of 449,000 BOE a day, which would correspond to a 6,000 to 8,000 BOE a day increase per quarter. As Jim noted, fourth quarter of 2011 was relatively free of significant operational disruptions, resulting in better-than-expected domestic production. A more typical experience with respect to such issues could moderate the growth somewhat in the first quarter of 2012. If the production growth rate continued at a comparable pace in the second half of the year, our year-over-year average domestic production growth would be similar, between 8% to 10% this year. Internationally, Colombia production should be about flat for the year compared to 2011. In the first quarter of 2012, volumes should be about 3,000 barrels a day higher than the fourth quarter of 2011, although insurgent activity has picked up recently. The Middle East region is expected to be as follows for the first half of the year. Production has resumed in our operations at Libya. And at this point, we expect about 5,000-barrel equivalent a day of production with further growth to come later in the year. At this point, we reasonably expect the total year production to be about half the level that existed prior to cessation of operations. In Iraq, as I discussed previously, production levels depend on capital spending. We are still unable to reliably predict the timing of spending levels, but we expect production to be similar to the past quarter. In Yemen, as we previously disclosed, our Masila block contract expired in December. Our share of the production at Masila was about 11,000 a day for the full year. Our remaining operations in Yemen typically have higher volumes early in the year due to timing of cost recovery each year, which will partially offset the loss of Masila barrels in the first half of 2012. As a result, we expect our total Yemen production to drop slightly from the fourth quarter 2011 levels in the first half of the year. The remainder of the Middle East, we expect production to be comparable to fourth quarter volumes. At current prices, we expect total first quarter sales volumes to be comparable to fourth quarter 2011 volumes, depending on the scheduling of liftings. A $5 change in global oil prices would impact our production sharing contract daily volumes by about 3,000 barrels per day. Additionally, we expect exploration expense to be about $100 million for seismic and drilling for our exploration programs in the first quarter. The chemical segment first quarter earnings are expected to be about $165 million with seasonal demand improvement expected in the second and third quarters. We expect that lower natural gas prices and the continuing improvement in the global economy will have a positive impact on our chemical business margin, which is to be expected -- which is expected to be offset partially by higher ethylene prices. We expect our combined worldwide tax rate the first quarter of 2012 to increase to about 40%. The increase from 2011 reflects a higher proportional mix of international income with higher tax rates, particularly from Libya. To summarize, we closed 2011 on a solid note with high domestic oil and gas production in the fourth quarter, which is ahead of our guidance. We continued to generate strong financial returns, well above our cost of capital. We enter this year raising our capital program by 10% compared with last year in order to prudently pursue our substantial inventory of high-return growth projects. The business continues to grow and generate free cash flow after capital, which should allow us to consistently grow our dividend at an attractive rate, further boosting the total return to our shareholders. I think we're now ready to take your questions.

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

Steve, I'm going to go very general on the questions, actually. First of all, I wondered if you could observe how you expect the U.S. natural gas market to rationalize itself, whether we've got an issue with associated gas production. Obviously, a very low price relative to the full cycle cost of production and so on. I just would be quite interested to hear what your latest views are on that.

Well, most -- the bulk of our gas is associated gas, so it comes off with oil. There's not much I can do about cutting that back. I don't think the gas -- I mean I think currently, we're -- the current price is clearly not sustainable. I don't think anybody's pure gas drilling works at whatever it is, $2.50, $2.60. I think we need to wait for the U.S. economy to improve. I just -- all these other fixes people talk about are much longer term. But if the U.S. economy improves, we'll use more natural gas and hopefully bring the prices up. But I think $2.50 for a rational person in drilling pure gas wells, no matter what they say -- maybe they hedged it or something for next year. It's just not a sensible price and is significantly below any rational replacement cost. We can't do much about ours to reduce it because we just don't drill that many pure gas wells. We're not going to shut any in because, again, most of the gas is associated. It has -- you have to have -- in order to make this work, you have to have a reduction in gas drilling and improvement in the U.S. economy. And frankly, the costs to drilling the wells have to come down. We're obviously not, --despite what some people think, we're obviously not going to be in a $10-per-MCF gas price environment anytime soon. And so we need to bring the cost of drilling of gas wells down to rational levels. Some of that will come from efficiencies and some of it will come out of service companies.

And the second very general one is on M&A. Firstly, specifically to OXY, whether you're seeing the potential for more deals or whether you're happy with your organic growth rate as it stands today. And also, industry-wide would be interesting as well, the M&A trend for 2012.

Most of the stuff that's for sale is pretty gassy right now. And the prices that people are talking about don't reflect rational, current or even the strip in gas prices. We try to buy things for inventory, that is to say drilling 3, 4, 5 years from now. Not trying to buy current production. So I think the organic in the United States is fine. And I think we'll be fine overall. So I'm not really in any hurry to spend a lot of money on some acquisitions, especially a very capital-intensive one. A lot of the things that are being done are extraordinarily capital-intensive. On a good day, the cash flow equals capital. And so, that's just not what we want to build. So I'm really reluctant to enter one of these capital traps.

Understood. And then very finally, on California, post-regulatory change, have you had a notable change?

Yes, I think I say that in the remarks that clearly, we've gotten some permits, some injector permits. It's the first time in a long time we got that. And clearly, a change in attitude. And so I -- the question is really where you get the permits, not necessarily exactly how many. But I think as we approach midyear, we'll have a sizable opportunity based on current trends. So I think we're -- we feel pretty good about this at this point, especially -- it may be that you were being hit in the head with 2 hammers, now only 1 and you feel better. But right now, we feel pretty good about this.

Yes, and the guidance last time we spoke was 5 rigs added every 6 months, constrained by...

Yes, I think once we get rolling and the permits come at a more normal rate, the rig count will pick up. But right now, we'll wait until the permits are in hand.

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

I got a couple as well, if I may. I wanted to just pick up on Paul's final point there. It looks to us that you got about a couple hundred permits in the last few months of the year. As you say, a pretty significant step up. Can you give us an idea of how that's being split between unconventional -- or sorry, I guess the rate of unconventional drilling and the new conventional exploration program? And I've got a couple of follow-ups, please.

Most of the permits are within fields. So they were within existing fields, because those are some ways the easiest permits to give. So I think that's the best way to say it, so within current field boundaries, because those are the easiest thing to clear. And so there's no way to tell you what the split is, but it's really within the existing fields.

Okay, well, maybe my second question is really on the conventional exploration program. Because I think when we last spoke, Steve, you suggested that's where your preference for incremental capital would be. Are you actually done delineating the original Gunslinger [ph] exploration discovery? Or are you basically done with that and moved on to new exploration targets? In which case, can you give us an update on progress?

We're in a development phase on the -- there will be more wells drilled this year in that. And while it may not be perfectly delineated, it'd be delineated through a development phase, not an exploration phase. We basically moved on to look for other opportunities, so that's really -- that program has moved out of exploration.

Go it, okay. And then my final one is, in 2010, you suggested that you could double your midstream earnings to about $1 billion. And I think a large part of that was predicated upon the increased steam flood at Mukhaizna. Can you just give us an update as to where both of those things stand? And then I'll leave it at that.

Most of the -- and Mukhaizna doesn't generate any midstream earnings. Most of it was different gas processing projects around California and the Permian and the Al Hosn gas processing. So that's where a lot of it is. There's other pieces around our pipeline business. The pipeline business actually did -- is doing pretty good. So that's growing nicely and we're putting more effort in the pipeline business, because we think there's more money to be made there, so -- and the additional tariffs in Dolphin also is another area of significant growth, as they're moving more gas and we're getting -- we may not get credit for barrels but we're getting a fair amount of fee income. It's not -- Mukhaizna uses gas but don't make money on gas.

Yes, I guess what I was referring to, Steve, was the incremental steam flood on the mid -- I was under the impression that you had some control of the pipelines over there and that would generate some revenue for the gas.

As they use more gas, the gas will have to come from Dolphin, and there'll be more fee income from that. I guess that's the way to think about it.

Okay. Well, maybe just to clarify and then I'll jump off. The Mukhaizna steam flood expansion, has that been permitted and approved? Or what is the status of that?

Maybe Sandy can answer that.

The permitting is up to about 680,000 barrels of steam per day and we're running about 430,000, so we're just about to bring on quite a bit more this year. In fact, most of it comes on this year. We're now looking at the practicalities and possibilities of a third phase of steam flooding as we further understand this reservoir.

Our next question comes from Jessica Chipman from Tudor, Pickering, Holt. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: First question just quickly, could you please give us an update, Steve, on current well cost really in the Bakken, the Wolfberry and the Bone Springs?

Bakken well cost hasn't really changed from the third quarter. It's still too high for what you get relative to our other projects. Somebody else may have a different hurdle rate than we do. So we've cut back. I don't think we've had any real inflation and -- Bill?

Just on the Wolfberry, we're looking -- depending on where you are in the basin, $2 million to $2.5 million completed well costs there. And in the Bone Springs, those long-reach horizontals are somewhere in the $6-million to $7-million per well range. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And then in the Bakken, I think the last update was $8 million to $8.5 million, so that's...

It's still a good number, Jessica, yes. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, okay. Then just my second question. Your comments around the acquisition potential and to be a capital trap even sort of as a segue into this question. So OXY has ramped activity pretty significantly recently and CapEx is increasing as a percent of total cash flow. 2011 looks more like 2/3 of cash flow whereas historically, Oxy was more in the 45% to 50% range. The question is just, in general, how you think about capital efficiency as OXY allocates spend from long-dated international projects to more capital-intensive drilling in the U.S.

The long-dated projects are just that. The returns will be good, just a few years before the production starts. In the United States, you can't really ignore the fact that the price of oil is not $40 anymore, which is the way we used to budget it, but some other higher number. The objective of the exercise is that we spend about 25% of our money on finding and development; about 25% on lifting cost, production taxes, that sort of thing; giving us 50% gross pretax margins. So as oil prices go up -- and we got a lot of oil in place around both in California and the Permian. As oil prices go up, we're going to spend more on -- to basically raise the bar. It won't raise the capital, and I don't think it will hurt the capital efficiency over time. But you got -- you just have to -- you can't just assume the price of oil is going to be $40, nor can you say, "Well, what I'm going to do is I'm going to -- not going to spend the money and store the oil in the ground." So just a balance between returns and growth, and we've tried to have a system where we're sort of in between. We're not trying to spend all of our capital for sure, and we're not trying to also deplete the business. You can cut the capital and get whatever you want, but your returns would go up but the business would deplete. We could spend a lot more money and have a lot more growth. And we wouldn't have the high dividend, the growth rate that companies enjoy and will continue to enjoy. I don't know how else to answer it. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Then just 2 very, very quick ones. Going forward, will you then target a certain plowback ratio in terms of capital as a percent of cash flow? And...

No. It's totally driven by the opportunity set. And so it's not driven by some formula. It's driven by an opportunity set to -- and it depends on oil prices. Even our workover program is really an oil-price-driven program. If you get your money back real quick, we'll spend more money on workovers. Oil prices decline, you won't get your money back so quick, we'll spend less. It's really that simple. It's not very -- these are short-term programs to some extent. The stuff that's drilling in the Permian, a lot of oil there and I think capturing oil at $100 a barrel, probably a pretty good business. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And just last, will you provide an update sometime this year on the long-term growth rate of 5% to 8%? Is that still what you're targeting for 2012?

That's still a long-term target. We've had a variety of reasons, mostly outside of our control. We had a tougher year in the Middle East than we'd anticipated. But I mean, when that gets back on track, pretty straightforward to make the growth rates.

Your next question comes from Ed Westlake from Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: I guess in the past, shale has not been as much of a priority given, I guess, the returns that you have in California in the Permian, and your CO2 floods. But I guess you're increasing rig counts. You've given the cost, just announced to that previous question, for the Wolfberry and the Bone Springs. But I mean, is it encouraging progress on recoveries, EURs and IPs that's encouraging you to spend more? Or is it the oil price?

Well, it's both. If oil were $30, the higher recoveries wouldn't be any good, so it's oil price. I mean we're driven by this 25% F&D sort of margin thought, or 50% including all our costs. And we don't use the $100 oil but we're sure not using $40 to do this. And it's a relatively straightforward -- there where we have a large inventory, we can either spend a lot more or a lot less. It's really in our control. We're going to ramp the program up or down based on how we -- based on the returns that we see looking at these margins. These margins will generate, by the way, very substantial returns on invested capital. The accounting type, not the IRR things people talk about, which I could have pressed you with those but I don't think they're really meaningful. Edward Westlake - Crédit Suisse AG, Research Division: And on the mix in terms of the increase, more Wolfberry wells or more Bone Spring wells, just in terms of sort of like...

They're more Wolfberry, aren't they, Bill?

Yes, the preponderance of our program -- development program, is Wolfberry in the Permian for 2012, Ed. Edward Westlake - Crédit Suisse AG, Research Division: Good. And just on California, obviously you increase 5 rigs, say, every 6 months from the middle of this year. Any thoughts on where you see the sort of the maximum rig counts for California, driven by obviously internal constraints, say, organizational and maybe external constraints?

No, I don't have any idea. We'll find out -- as the program boosts, we'll see where it takes us. It's relatively people-intensive, so you have to build your organization as you go. It's not just a bunch of guys, hopefully with -- hopefully, it's not a bunch of guys just fooling around on a computer. So you have got to build the organization as you go and you have to -- the people have to get more experienced. So you want to do it in a way you're not wasting money. The resource isn't going away. As we own the minerals -- we either own the minerals or we have very long leases, the resource isn't going away. So we got a lot of flexibility on when. And I really don't have any idea because the program always has surprises. Some of them are good surprises; some of them are not. But the program always has surprises. It's very difficult -- especially in California, it's very difficult to predict some maximum rate. Edward Westlake - Crédit Suisse AG, Research Division: A final question for me. You said most of the permits are within fields when we're talking about the increase in permits. Any progress on sort of geologically and doing the EA, environmental assessments, to sort of define some new field areas within the acreage?

Oh yes, we're doing that. We'll get the permits eventually. This is just where we are right now. Because the state -- it's easy to clear permits within a field. I mean, it's easy in theory. They weren't doing it before. So that allows us to have a decent program and a predictable program. But there's a fair amount of progress. There's always issues in California, environmental issues that they're rightly concerned about. So are we. So I think there's always going to be something that isn't perfect for us. But we're pretty encouraged the way things are going now.

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

I know you've got the royalty advantage in California. I'm wondering if on your Permian acreage, you have similar advantages because you've had the acreage for a long time.

I think our royalty interests are significantly below average. And if you went over the whole thing, compared to current things, it's not as great an advantage as in California for sure, because a lot of ranchers still own the underlying minerals. I'm going to guess it's sort of 9 to 10 points of average against new leases that somebody might take.

Okay. And some Permian E&Ps, talking about the Wolfberry again, with the inclusion of some other interbedded [ph] zones -- perhaps it's varied from area to area -- we're talking about a 25% increase in EUR compared to a couple of years ago that the reservoir engineers are giving them. And a little bit less than that on IP rates, but I was wondering whether you're experiencing similar performance given the application of new hydraulic fracturing techniques.

I think we need to hire their reservoir engineers, as they have different numbers than we do.

Okay. Then just for clarification, in the Bone Springs, are we talking Avalon Shale or the Bone Springs sands? How is the program weighted?

It's definitely more weighted to the Bone Springs sands because, as you know, that's an oily play, whereas the Avalon is mainly gas.

Okay. Any interest in vertical stacked pays in the, say, Wolf, Bone or drilling vertically on your acreage at this point in Bone Springs now?

Yes, we're looking at that as well.

Okay. And then last question. Could you just give me a general impression of John Laird, what you know about him historically and what you've seen most recently? What you like?

Who?

Secretary of Natural Resources that's been appointed by Jerry Brown, the new guy?

That's a lot higher than -- we're sort of nuts and bolts people working with people giving permits. Policies are best left to more sophisticated people than us.

So it's bottom-up kind of bottlenecking you could say that's helping things along.

It's right in the agency that generates permits, which is basically an engineering discussion about things. It's not about California environmental policies, which is way above my pay grade.

Your next question comes from David Neuhauser of Livermore Partners.

My question is a little bit macro. I wanted to see or give some thought into some of the headwinds that are currently facing the company as you look out this year and the next few years. I mean, we've had hard asset, hard commodity prices that actually fall overall this past year with the strengthening dollar. But at the same time, we've seen recoupling between WTI and Brent crude. So I wanted to see if you think the prices will remain stable in this band or what your current thoughts are on the landscape.

For planning purposes, we're always more conservative than the current pricing. We're not very good at predicting this, you should understand. We were conservative at $25 oil too. So as a matter of running the business, we're always conservative about how we manage the business and what we expect for product prices. Having said that, I think globally, it costs more to find a barrel of oil -- I'm talking about oil, not gas -- than it did a few years ago. And it doesn't make a difference where that is. The overall finding costs are rising. And I think it's very likely that, that will continue to push prices higher over time. But just for planning purposes, we're always conservative about it. There's always a bearish argument for oil prices. There's always some explanation of why it's going to go down. And there's also the sort of the wacky extreme arguments it's going to be $200 a barrel in an hour. So I think it's almost impossible to ever -- I'd [ph] accept a general view that over time, it will rise with costs and to be, I think, conservative on a short-term basis.

Okay. And what about opportunities in general? I know you touched on a bit of M&A activities out there today and that you're seeing a lot of gassy assets. But are there areas out there or areas that you'd like to focus on where you could see increasing your footprint it, would be more advantageous to do so with an acquisition?

We're basically not, as a rule, company buyers. There's always properties around. And we added in the Bakken basically not by buying companies, but by buying assets. We'll continue to do that. I wouldn't expect to see some new areas, if that's the question. But we'll see. I'm always surprised at what shows up in the course of a year. My ability to predict this is even less good than my ability to predict oil prices.

Okay. And my last question is, what are some things -- I mean, you seem again to be hitting on all cylinders for the most part on the year. And I guess my question is, what are some of the things that you're most not happy with, with the company's performance today that you would definitely like to see...

I think we can get more efficient. I think there's always improvements in efficiency that are around. I think we're on an efficiency drive, but I think that's always something that we're looking for. You never get -- the problem with the goal is you never get to perfect. And even if you did, we'd move the goalposts. So not much chance at getting to perfect. So we look for that, and I'm always unhappy about some of the physical breakdowns. The infrastructure in the United States needs work. And so we get more breakdowns in infrastructure than you might like, so the full potential of the business really never shows up in any quarter. Those are the main things I'm concerned about. I can't do anything about the oil prices. No sense at being worried about it.

[Operator Instructions] Your next question comes from John Herrlin of Societe Generale.

Just some quick ones, Steve. In terms of your California spend, what would the breakdown be conventional versus unconventional, or shale versus your normal business?

Probably about half, about half. I wouldn't take that number to the bank. It's probably -- it's about right. And it changes from month to month, as you can imagine.

Okay. That's fine. In terms of your midstream spend, how much of that is going to be in California and the Midcontinent?

Most of the spend in the midstream is the gas plant in -- right now in the Al Hosn gas plant. So that big number there is pretty much that. The gas plant in California will be done. This one -- this plant will be done -- the spending will be pretty much done by midyear for sure, most of the remaining spend in probably this quarter. And then, there'll be some gas plant spending in the Permian on CO2 plants and stuff, but a much lower level. But the big number you see there is the finishing up in the California plant and the gas plant and the Al Hosn gas plant.

Okay. Last 2 for me. What's water disposal running per barrel in the Bakken in terms of cost?

That's definitely something I don't know. We'll find that.

And the last one, any issues with proppants since you're doing a lot of exploitation?

With what?

Proppant.

No, we haven't had any supply issues.

You're asking about supply issues?

Correct.

Yes, no. No.

Your next question comes from Faisel Khan of Citi.

Steve, just want to go back to, I think, some of your comments on Iraq and Libya. The spending level in Iraq, you talked about, about a "11,000 barrel a day" sort of number for the year, I believe. How confident are you in that number? Are things kind of -- are things getting done on the ground there to be able to keep that spending level fairly consistent?

Sandy will answer that.

We've had a series of meetings in November and December with the procurement committees in Iraq. And they've recently approved a number of drilling-related contracts, and indeed the main drilling contract got a letter-of-intent approval. This will get all the drilling started. The facilities that will be needed for the increasing production are under bid right now, and they're coming through the committees in the first and second quarter. So we are seeing an opening up of procurement, which of course drives our production.

So to put it in sort of financial terms, I think we feel okay about the 11,000, but it's certainly not the most solid number. On the other hand, if it worked right, it would be more.

Okay, fair enough. And in Libya, what's the situation on the ground with you guys right now? How confident are you that you can bring back those volumes to a level that you outlined in your prepared remarks?

Sandy can answer that.

Right now, the gross production in the fields where we have an interest are about 65%, 70% of what they were before the conflict started. We are continuing -- and our Libyan partners are continuing to repair and improve, and they still have a small drilling program going. So I think that we'll be back up to normal later this year, probably in the third quarter. We're still working with an interim government, so we're currently meeting with our counterparts in Libya every day to discuss how to go forward and how to increase production even further.

We try to be conservative in the estimate for that, understanding things don't work perfectly.

Okay, fair enough. And last question. In Bahrain, any updates on -- I think, is it the exploration of the deep gas sort of rights that you guys have?

We're doing it with the wells this year. Yes, a well will be drilled this year.

How many, Steve, sorry?

I think it's supposed to be -- it's one deep and a couple of others. Whether they get all done this year is a different issue. But the drilling will start this year.

Okay. Any operational issues in Bahrain following some of the civil unrest?

Sandy?

It's a little more difficult place to work. We have trouble with our contractor sometimes, but it's been relatively quiet recently. We're watching the anniversary of the initial problems there. But it's affected our production only a few hundred barrels on a per-day basis over the year. Things are reasonably okay.

It's growing. It's probably a little behind where we thought we'd be, but it's actually growing and doing fine.

Our final question comes from the line of Pavel Molchanov of Raymond James. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Quick question about Colombia. Given that it's one of the very few assets you have outside the Mid East and the U.S., of course, any interest in monetizing that?

No. If you ask a short question, you got a short answer. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: No, it makes a lot of sense. And just one more, if I may, about California. You've talked about permitting getting sort of tentatively better. Are there any catalysts that you envision to meaningfully accelerate the change in permitting approach of the administration there?

I think generally, they're going back to a version of their historic rules, and they have a sizable backlog from us and others, I'm sure, to clear. And so, what they have to do is work through to get back to their historic rules. And again, the easiest ones to clear are the ones within the fields. I think they'll get to some version of the historical rules. There'll be other rules that won't be quite historical, but I'm not really concerned. As long as we understand the rules, we'll abide by them. There isn't really a long-term problem. It's just that the rules have to be clear to us, that's all. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. Is it fair to say that in the last 12 months since Brown came into office, there has been a systemic change in how they approach it versus the...

The governor is very pro-jobs, -industry, whatever you want to say, and has been someone who understands that businesses generate jobs. That or a fair number of jobs here in California, we continue to. And I think the governor understands that and is appreciative of that. And it's a very -- he's very interested in this and very interested in employment here in the state, and we're pleased with the governor's involvement. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: And just one last quick one. Did you book any reserves in Iraq in 2011?

2011? We booked some in 2010 based on the program that was approved. Unfortunately, the program, because of a variety of reasons -- and the program is only approved through 2013. For a variety of reasons, we didn't achieve the program in 2011, mostly because we didn't spend the money and we couldn't. So the net result was that the reserves were negatively affected by the program. Those reserves will come back once the -- you can't book reserves beyond where the program has been approved by the government. So once they give us approval beyond 2013, those reserves will come back. As a technical matter, those reserves came off. Chris?

Thanks for joining us, everyone. And if there's further questions, please call us here in New York. Thank you.

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