Occidental Petroleum Corporation (OXY) Q4 2010 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 2010 Earnings Conference Call. [Operator Instructions] Mr. Stavros, you may begin your conference.

Thank you, Christy, and good morning, everyone. Welcome to Occidental Petroleum's Fourth Quarter 2010 Earnings Conference Call. Joining us on the call this morning from Los Angeles are Dr. Ray Irani, Oxy's Chairman and Chief Executive Officer; Steve Chazen, our President and Chief Operating Officer; and Bill Albrecht, President of Oxy's U.S. Oil and Gas Operations. Sandy Lowe, President of our International Oil and Gas business, wasn't able to join us for today's call as he is currently traveling in the Middle East. In a moment, I will turn the call over to Dr. Irani for some opening remarks and comments regarding some of our recent transactions and new project announcements. Steve Chazen will then review our fourth quarter and full year 2010 financial and operating results. Our fourth quarter earnings press release, Investor Relations supplemental schedules and the conference call presentation slides, which refer to Steve's remarks, can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Dr. Irani. Dr. Irani, please go ahead.

Thank you, Chris, and good morning, ladies and gentlemen. In a few minutes, Steve Chazen will provide details on our financial results for the fourth quarter and full year of 2010. But first, I want to mention some key developments of the last week and of the past quarter that we believe are significant to continuing Oxy's success in 2010 and beyond. Last week, we announced that the government of Abu Dhabi selected Oxy to participate in the development of the Shah gas fields, one of the largest natural gas fields in the Middle East. Oxy will hold a 40% participating interest in a 30-year contract, with Abu Dhabi National Oil Company, ADNOC, holding the remaining 60%. We're indeed pleased that the Abu Dhabi government has chosen Oxy to participate with them in this major project. This is another important step in the implementation of our growth strategy in the Middle East and in our relationship with the Emirates of Abu Dhabi. You will recall that in 2007, Oxy submitted a bid on the Shah project and was not selected. However, development of the field under the agreement announced last week provides an exciting opportunity to create value for the people of Abu Dhabi and, of course, for Oxy stockholders. We expect it to provide similar returns to Oxy as our traditional Middle East properties. Working in close partnership with ADNOC, we will apply our expertise in this technically challenging project to develop high sulfur content reservoirs within the Shah field. The project is anticipated to produce approximately 500 million cubic feet per day of sales gas, providing net to Oxy in the range of 200 million cubic feet a day. In addition, the project is expected to produce about 50,000 barrels per day of condensate and natural gas liquids, which we expect to yield in the range of 20,000 barrels per day net to Oxy. ADNOC is already in the process of developing the field, and the majority of its [indiscernible] and procurements and construction contracts have already been awarded. Production from the field is scheduled to begin in 2014. Capital expenditures for the entire project are estimated to be in the range of $10 billion, with Oxy's share proportional to the ownership. Another key development for Oxy and very exciting, which we announced last month, was the strategic adjustments we have made to our asset base in order to improve the company's performance and profitability. While selling our Oil and Gas operations in Argentina, which have not performed to our expectations, the subsidiary of Sinopec had expected after-tax proceeds to be about $2.5 billion. We have made acquisitions and new producing areas for Oxy, North Dakota and South Texas, which we believe have solid potential for growth. We expect the combination of these transactions to immediately improve our earnings, return on capital employed and free cash flow. The North Dakota acquisition has already closed, and we anticipate the Argentina and South Texas transactions to close by the end of this quarter. Two years ago, we went into North Dakota with a modest amount of acreage in the oil-rich Bakken and Three Forks Formation of the Williston Basin. Now we have expanded our position in the area to over 200,000 acres by purchasing about 180,000 net contiguous acres from a private seller for about $1.4 billion. We expect to grow our production in the Williston Basin from these properties to about 30,000 BOE per day over the next five years. The South Texas acquisition from Shell for about $1.8 billion gives us properties which have over 320 billion cubic feet of gas equivalent, improved and developed reservoirs and are liquid-rich with a solid inventory of building opportunities. Oxy's already a major producer in Texas, and East South Texas assets further expand our footprint in the state. We anticipate the new U.S. assets to immediately yield reasonable earnings and produce good free cash flow even at current gas prices. As gas prices improve in the future and we optimize overall area opportunities, these properties will fit well with our overall presence, performance and continued growth in the United States. The U.S. acquisitions, together with those we made in the third quarter of last year, will replace our production from Argentina with better profits, return on capital employed and free cash flow. And as evidence of our confidence in Oxy's performance with the addition of our new U.S. assets, Oxy's Board of Directors has announced its intention to increase our common share dividend rate by 21% to an annual rate of $1.84 effective with the April 15 payment. This will mark Oxy's 10th dividend increase since 2002, bringing the compounded annual growth rate over the period to 15.6%. In 2011, we will maintain our focus on delivering value to our shareholders and partners as we continue improving our asset base, while growing production and reserves. I'll now turn the call over to Steve Chazen to report on Oxy's financial performance during the first quarter and full year.

Thank you, Ray. The core income was $1.3 billion or $1.58 per diluted share in the fourth quarter this year compared to $1.1 billion or $1.35 per diluted share in the fourth quarter of last year. Net income was $1.2 billion or $1.49 per diluted share in the fourth quarter of 2010 compared to $938 million or $1.15 per diluted share in the fourth quarter of 2009. As required by accounting rules, Argentina has been classified as discontinued operation. Therefore, Argentina's results have been excluded from continuing operations net of tax for all periods. What this means is everything about Argentina has collapsed into a single line. Details of Argentina's operating results for the years 2008 and '09 and by quarters in 2010 are included in the Investor Relations supplemental schedules. Argentina has not been profitable for the last four years. The 2010 fourth quarter also included after-tax non-core charges of $175 million for impairments predominantly of gas properties in the Rockies, and an $80 million benefit related to foreign tax credit carryforwards. The fourth quarter 2010 core income included $110 million higher pretax expense compared to the third quarter or $70 million after tax or $0.09 per diluted share from equity and related compensation programs, mostly due to the effect of the steep rise in the company's stock during final quarter. Here's the segment breakdown for the fourth quarter. Oil and Gas segment earnings for the fourth quarter of 2010 are $1.7 billion. Realized crude oil prices increased 11.5% in 2010, but domestic natural gas prices declined 5.5% in the fourth quarter of 2009. Production volumes in the fourth quarter 2010 were 750,000 BOE a day, a 5% increase compared to the 717,000 BOE a day in the fourth quarter of 2009. Fourth quarter production of 753,000 per day was slightly higher than third quarter's production of 751,000 BOE per day. Fourth quarter volumes compared to the third quarter were negatively impacted by 10,000 BOE a day from the effects of our production-sharing contract, 6,000 BOE a day due to strikes in Argentina and inclement weather in December, which impacted our California production. In California, oil production was higher by 2,000 barrels a day in the fourth quarter compared to the third quarter. It was offset by 1,000 barrels a day decline resulting from higher oil prices, affecting the production-sharing contracts at our THUMS operation, and by 3,000 barrels a day of lower natural gas liquids volume resulting from lower gas production. Excluding Argentina, worldwide oil and gas production for the fourth quarter was 714,000 BOE a day. Third quarter production would have been 716,000 BOE a day if Argentina were excluded. The fourth quarter sales volumes were 751,000 BOE a day. Sales volumes differ from production volumes due mainly to the fourth quarter lifting in Argentina, which slipped from the third quarter, partially offset by Iraq production, which will be sold in 2011, and a lifting in Colombia, which was sold at the beginning of this year. Exploration expense is $54 million in the quarter. Chemical segment earnings for the fourth quarter of 2010 were $111 million and in line with our earlier guidance. Midstream segment earnings for the fourth quarter of 2010 were $210 million compared to $163 million in the third quarter of 2010 and $81 million in the fourth quarter of last year. The increase in earnings was mainly due to higher trading and marketing income. Worldwide effective tax rate was 38% for the fourth quarter. Now let me turn to Oxy's performance during the last year. Core income was $4.7 billion or $5.72 per diluted share for the 12 months of this year compared to $3.2 billion or $3.92 per diluted share for the full year of 2009. Net income was $4.5 billion or $5.50 per diluted share for the 12 months of 2010 compared with $2.9 billion or $3.58 per diluted share for the same period of 2009. Income for the 12 months of 2010 included $134 million of charges net of tax and 2009 included $277 million net of tax for the items noted on the schedule reconciling net income to core results. Oil and gas cash production costs, which exclude production and property taxes, were $10.19 a barrel for 2010, excluding Argentina. Last year's 12 months costs were $8.95 a barrel on the same basis. The year-over-year increase reflects $0.32 a barrel and higher CO2 costs due to our decision to expense 100% of injected CO2 beginning this year and higher field support operations workover and maintenance costs. Taxes other than on income were $1.83 a barrel for 2010 compared to $1.67 per barrel for all of 2009. These costs, which are sensitive to product prices, reflect the effect of higher crude oil and gas prices in 2010. Capital spending for the fourth quarter was about $1.4 billion and $3.9 billion for the 12 months, excluding Argentina. Capital expenditures by segment were 80% Oil and Gas, 13% in Midstream and the remainder in Chemicals. Cash flow from operations for the 12 months of 2010 was $9.1 billion, excluding Argentina. We used $3.9 billion of the company's cash flow to fund capital expenditures; $4.7 billion on acquisitions and $225 million on foreign contracts. These investing cash flow uses amounted to $8.8 billion. We issued $2.6 billion of debt in the fourth quarter. We also used $1.2 billion to pay dividends and $310 million to retire debt. Argentina's net cash flow for the year was a negative $125 million after spending $415 million for capital expenditures and contract extension payments. These and other net cash flows increased our $1.2 billion cash balance at the end of last year by $1.4 billion to $2.6 billion at December 31. Free cash flow from continuing operations after capital spending and dividends, but before acquisition activity and debt retirements, was about $4.3 billion. Our acquisition costs in the fourth quarter were $3.1 billion, which included the previously announced purchases of Oil and Gas bolt-on properties, mainly in the Permian. We expect to close the purchase of several additional properties and the sale of Argentina in the first quarter of 2011. During the year, we spent $4.1 billion on Oil and Gas acquisitions, of which about 50% was on unproved properties. On a preliminary basis, our 2010 reserve replacement ratio was about 150%. Approximately 1/3 of the current year reserve adds came from acquisitions. We will provide additional details regarding reserves as soon as the information is available. The weighted average basic shares outstanding for the 12 months of 2010 were 812.5 million, and the weighted average diluted shares outstanding were 813.8 million. Our debt-to-capitalization ratio was 14% at the end of the year. Our 2010 return on equity was 14.7% and return on capital employed of 13.2%. As we look ahead in the current quarter, our first quarter 2011 production will be impacted by the following factors. First, we will no longer report Argentina production. Second, the timing of completion of the new acquisitions, while the acquisition the Oil and Gas properties in North Dakota closed at year end, the acquisition of the South Texas properties is yet to close. We have a planned one-month maintenance and production shutdown at Elk Hills and Dolphin. The impact of the Elk Hills shutdown, which will only impact natural gas and liquids production, will be about 8,000 BOE a day for the first quarter of 2011. The impact of the Dolphin shutdown will be about 5,000 BOE a day for the quarter. We expect the first quarter Oil and Gas production volumes to be between 740,000 and 750,000 BOE a day and fourth quarter average prices of $85 for WTI. We expect sales volumes to be around 725,000 BOE a day. A $5 increase in WTI would reduce our daily volumes by about 5,500 BOE a day. Once we know the first quarter's results and the timing and the initial production rates on transfer from the pending acquisitions, we can provide an accurate full year production guidance. Production growth will resume in the second quarter. We reasonably expect by at least the second half of the year, production would be similar to the run rate we showed you in last May's investor presentation, adjusted for oil price changes. With regard to current prices, at current market prices, a $1 per barrel change in oil prices impacts quarterly earnings before income taxes by about $41 million. The average fourth quarter WTI price was $85.17 per barrel. A swing of $0.50 per million BTUs in domestic gas prices has a $36 million impact on quarterly earnings before income taxes. This is a significant increase in gas price sensitivities from what we have told you in the past. The current NYMEX gas price is around $4.50 per MCF. Additionally, we expect exploration expense to be about $85 million for seismic and drilling for our exploration programs. The Chemical segment is expected to provide earnings for the first quarter of about $125 million. We expect margins and volumes to continue to improve as the economy strengthens. We expect our combined worldwide tax rate in the first quarter of 2011 to be about 40%. Our fourth quarter U.S. and foreign tax rates are included in our Investor Relations supplements. For all of 2011, we expect capital spending for the total year to be about $6.1 billion compared to the 2010 total of $3.9 billion. Both amounts exclude Argentina and the Shah Field Development Project. Occidental's share of the Shah Field development capital will total about $4 billion over the next several years. Our 2011 capital is close to our fourth quarter annualized run rate of $5.5 billion and in line with the five-year capital program we gave you in the May investor presentation, plus the capital that was deferred from 2010. The breakdown of the 2010 and 2011 capital by area and segment is included in the supplemental schedules. Our Oil and Gas DD&A expense for 2011 should be approximately $11.75 per BOE. Depreciation for the other two segments should be about $500 million. In California, we have about 520 geologically viable so-called de-risked shale drilling locations in California, excluding traditional Elk Hills. Of these locations, about 250 are outside both of the Elk Hills proper in the Kern County Discovery Area. During 2011, based on a conservative view of the permitting process, we expect to drill a total of 107 shale wells outside of Elk Hills proper. As additional permits become available, the level of drilling activity would pick up during the year. We will also drill 28 exploration wells in California in 2011. About 50% of these will be for conventional exploration. We expect the exploration activity will, at a minimum, create more unconventional drilling locations. Copies of our press release and our supplemental schedules are available on our website or on the SEC system. We're now ready to take your questions.

[Operator Instructions] And your first question comes from the David Heikkinen of Tudor, Pickering. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: As we think about the industry and then your operation, we can qualitatively get some thoughts around primary potential in the Permian, also kind of the development potential and exploration potential in California. But trying to quantify that has been difficult given current disclosure, particularly versus some of the smaller peers that we do follow. Can you talk about how you think about that asset operationally? And then also how you think about how and what your disclosure process will be heading forward?

If we take the two U.S. assets, let's start with the Permian, which in some ways is easiest. I think last year, we gave you a notion of how much additional was recoverable with the CO2 flooding process. The drilling in the smaller opportunities, there's a fair amount of potential there, but it's sort of hard for us to quantify in a meaningful way. We're not going to provide individual well data like some companies do. So I think the potential in the Permian is very sizable. But we did provide last year how much additional CO2 flooding potential we thought there was, and we think that's probably a fairly conservative outlook. We switch to California, as the shale drilling program accelerates this year, it would be fairly obvious, we think, of what the potential there is. We've got I think I said 500 shale locations. We don't think that the description of them is materially different from what we gave you in May, and that is roughly how much is recoverable per well as the initial rates and the costs. So I think we have at least 500. That's a very small percentage of our acreage. So I think the potential there will become pretty obvious as the year progresses, we start getting permits and start getting our production up. The permitting process in California is fairly complicated once we leave the main field areas. So it may take a little longer than I would like, for sure, but I think it will be pretty obvious when you look at production going forward. I think you'll see some pretty decent results as the year progresses. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then as I do think about the Permian, kind of operationally, kind of core competencies and skill sets required to run a large CO2 flood versus running a larger primary program. Can you talk about how you operationally run that? And then any details around activity, more on the primary side, as far as are you accelerating activity with the increased CapEx on more of the primary smaller opportunities there?

Almost all the increase is in primary drilling. The numbers we're showing is a percentage, you can multiply the percentage out. Almost all the increase is on primary drilling. The capital in the CO2 program is very modest because almost all capital is just CO2. I mean, these are fields that are just increasing basically their flood size. So the increase is overwhelmingly in what you would describe as primary drilling. We have a lot of acreage available, several in the area. We've acquired some new areas or additional areas next to what we had. I think you'll see a pretty sizable impact of that as the year progresses, but it is overwhelmed, really, by the size of the CO2 flooding opportunity, which is billions of barrels as supposed to hundreds of millions of barrels. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then just kind of bigger picture and not trying to replace you, but have had a question about succession planning and thoughts at Oxy. Can you talk about, kind of Board level, and what the thoughts are around management and...

I think we'd let the Chairman of the Board discuss at the Board level.

What is your specific question? David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Basically, as we go through the transition, people ask who's behind Steve, and just wanted to understand the Board level thoughts there.

Well, Steve will take over as CEO at the May meeting of this year. I will continue as Executive Chairman, and we do have other people behind Steve. But let's have Steve take over first, and we can also be looking at replacements. We have a bench, but we think we can execute our plans with our current manpower.

Our next question comes from the line of Paul Sankey with Deutsche Bank.

Steve, can you just help me a bit with some of the volume outlook that you gave me and the effect of California? I think that you said that you would expect your volumes to be around 740,000 to 750,000 in Q1 and 725,000 of sales.

Right.

But obviously, that would be negatively impacted by the loss of Argentina?

No, we've already done that.

Okay, so that's all out?

Yes, right.

I think what you said was by second half you would expect volumes -- second half of 2011, you would expect volumes to be back in line with the volume outlook presented at the May Analyst Meeting, which the top line on that was like 837,000, but then there was a base CAGR of 6%. Should we think of it like as a percentage line or how should we work that out?

It's hard to say. The variance is built of our demonstrated inability to predict all that well. So somewhere in that range. But I think that run rate adjusted for the price. You got to take out the oil price change. Last year was $175. So you got to adjust the production down for the product price. And so you should look for a run rate in the back half of the year for the company that looks like that. Argentina was 40-some thousand a day, net, or 48,000 or something like that. But we basically replaced that with the other stuff.

So the net difference is zero, let's say, and then...

That is around zero, except for the noise in the first quarter of the handoff.

But then, essentially, what we're looking for is, allowing for the change in price, around a 6% growth rate being achieved by the second half of the year?

I think that's right. Argentina is out of the numbers I've given, but -- and the new acquisitions are in it. And roughly speaking, they're a push, once everybody's -- you got a full quarter. The first quarter's a little noisy. Second quarter may be a little noisy, but by the last two quarters, we should be back in line at that rate.

And then just on Slide 7, at a very kind of simplistic level, if I look at your Oil and Gas segment earnings, they're down from Q4 '09 to Q4 '10 despite, whatever it is, a $10 increase in the oil price and the increased volume. Can you just talk a little bit about what's going on there and some of the...

I think two major factors: one, some of this employee expense got rolled into that; and second -- it's not really operating costs. Second is the mix, the mix is a little gassier.

Paul, the slide you're referring to as well includes the impairment charges because this reflects on a reported basis.

Our next question comes from the line of Arjun Murti of Goldman Sachs.

Steve, just to follow up on the California shale comments you made. I think you said about 107 wells outside of Elk Hills proper in the shale. How many rigs do you need to do that? Do you have them? And where do you stand on completion crews and the fracture stimulation side of things?

Yes, we're planning to run about 12 rigs drilling exclusively shale wells. And that's in all of California, not just on Elk Hills proper.

And do you have the 12 now or do you still need to procure some?

No, we have the 12 right now.

And how about completion crews?

Well, a lot of these shale completions are acidized as opposed to fracturing, and we're in pretty good shape on our acid.

So this is a situation where, as you drill the wells -- the production should show up as you drill the wells?

Yes, we shouldn't have a large inventory of wells waiting on completion due to a shortage of services.

We're running along pretty well right now. We're tracking the first three weeks of the month, we're right on. We gave you a number here for number of wells drilled. The locations are permitted, and the rigs are in place and the completion crews are in place. Except for a rainstorm or something like that, it's unlikely that there's much downside to this.

And in the Analyst Meeting, you gave a range of 400,000 to 700,000 BOEs per well. If you take 500,000 BOEs a well times 100 wells, that's 0.5 billion barrels a year of opportunity. From a reserve booking standpoint, is that how we should think about it or is there some lag because you got to see production over time? And that's obviously just one year's drilling.

No, I think the way you should look at it is that, once you start a development program and you drill a few wells, the rest are pretty much by analogy. You don't get enormous variation on average. So in theory, you could book a lot of PUDs. We tend to be light on PUDs. I think this past year, we're about 25% PUDs as a company. So booking a lot of PUDs is not something we do an enormous amount of. But we do book PUDs because a lot of these are very similar to each other, so a statistical approach gives you a pretty conservative result. We are working on, our costs are coming down as it's repeatability, and the completion techniques are improving, so I'm pretty optimistic that we'll do pretty good. But as far as the booking goes, we'll book on a pretty conservative basis, but we are booking some PUDs.

And then the last question, on California. It looks like, at least relative to the 520, a decent number is within the Kern County discovery area as a shale opportunity. Is that all still within that broad range of economics you provided at the Analyst Meeting or is the Kern County Discovery Area --

Yes.

It is. Will Iraq be accretive to earnings when you actually sell the oil in the first or second quarter of this year?

Yes.

Our next question comes from Doug Terreson of ISI Group.

In E&P, the growth outlook clearly appears to be improving with the new ventures, but, Steve, my question, regards to potential for return enhancement between better performance on the base, some of the divestitures that I think Ray talked about, and/or investment, some of the new ventures that were discussed. How do you envision normalized returns changing over the next several years related to some of these mechanisms? And which do you consider to be the most important for better returns?

Well, we'll start with the fact, of course, Argentina, which I said hadn't made money in four years. So without a lot of effort, I can improve returns.

The 40,000 barrels per day making no profit.

That was a fairly easy thing for us to compute. The only drag on the base I think, the rest of the base ought to be improving. A little higher gas prices, doesn't need a lot. And a more aggressive, California outcomes should generate very high returns on invested capital. And as that accelerates, we should be doing pretty good. Same thing in the Permian. The CO2, remember, CO2 doesn't really cost any additional capital. And so the returns ought to improve there, and that's really a big number. The only downside is we're going to invest the money in the Shah field. And so that investment will show up as investment and no production for four years. So it will be a drag. But I think the rest of it will easily overcome that.

Your next question comes from Doug Leggate of Merrill Lynch.

The first one in California. Steve, you did mention this in one of your answers to the other questions, but just to be clear, I mean, the 520 locations that you've de-risked so far, approximately what are we talking about in terms of de-risked acreage on your 1.6 million acres?

It wouldn't be material.

So less than 10%?

Oh, for sure.

So you take your rig count up. You treble it, by the looks of things, from the start to the end of 2010. Where do you think that trajectory gets to? I mean, are you still building rigs, not just in California, but across the lower 48? Can you just give some sense in this high oil price environment, which I'm guessing you didn't plan for, how that might play into your opportunities in terms of activity levels?

On California, I think that once we get real clarity on the permitting, this thing will accelerate rapidly. There's no reason, except right around the Kern County Discovery Area, why we can't put more rigs to work. We just don't have the permits to drill the wells. And so once we get clarity on that in the back half of the year, it'd be a fairly sizable increase in the rig count. In the Permian, I think, we're doing okay. We may accel -- as the production starts to build and we get more confidence in some of these smaller primary wells, we'll probably build that up by a couple more rigs. So the answer to your question is as the year progresses, if it does what we hope, then the number of rigs will continue to build until we would expect, as we exit this year to be about -- a year from now, to be at a much higher rig rate than we are now. I can't tell you exactly when because California, we're still pretty much constrained by the permitting process.

So I'm trying to reconcile the two, Steve, I'm sorry to belabor the point. So basically we've got 12 rigs running, I think is what Bill said before, and 520 locations. So let's assume you double the rig count in California. How much running room do you really believe that you have there in terms of the shale drilling program?

The 520 is a small percentage of the total that we actually have. If you count our contingent locations and those sorts of things, right now we're triple this or something.

The final one from me is just going back on the production guidance. The numbers you gave in May were high due north of 800,000 barrels a day as an average for this year, netting out Argentina, adding back the acquisitions. Can you just help us a little bit with if -- what you're trying to tell us with your guidance for the second half. What would you ideally be looking at in terms of an exit rate, if you like, for the end of 2011, if that's a number you could provide?

I don't really think of it that way. I think the simplest way to look at it is to say that the exit rate for this year will easily lead to next year's number -- the following year's numbers, the 2012 numbers we've given.

So the 2012 guidance is still...

That's right. We may have to redo it a little bit and raise it, but other than that, if you just look at the 2012 guidance, assume the Argentinian and the acquisitions are a wash just for this purpose. When you get through, I think you're -- so your run rate as you enter sort of December next year will lead you to the following year's numbers we've given you.

Adjusted for oil prices?

Adjusted for oil prices, right. Hopefully, they continue to go up. So that would be all right.

Your next question comes from Philip Dodge of Tuohy Brothers.

It looks like your U.S. gas production increased quarter to quarter in the fourth quarter even though California was down. So if that's correct, can you fill us in on where some of the increases were taking place?

We'll let Bill answer that way. He was looking at his tables here. I could guess, but we'll let Bill answer it for real.

One of the things to point to again is increased primary drilling in the Permian. As you know, a big part of our program in the Permian on a primary basis is in the Wolfberry. And you get a lot of associated gas production with those Wolfberry barrels. And you also, in terms of California shales, about 60% of the production on a typical shale well is going to be gas. And those are the two primary areas where we're focusing on in terms of primary development.

Next, could you bring us up-to-date on the expansion of the processing capacity in the discovery area in Kern River, both gross and net?

The plant's been ordered and we would expect it to be on in the first quarter of next year.

So no change?

No change.

Then finally, as a detail, in Iraq, can you give us the gross production number for Zubair that goes along with the 11,000 barrels a day net?

I can't.

We expect the exit rate for Iraq in 2011, the exit rate, to be over 300,000 barrels a day.

Then we just relate your ownership to that number, and we're pretty far along.

Well, it's hard -- it's more complicated than you might thing.

Can you say how much of that will be cost recovery oil?

The cost recovery percentage is 50% of the excess over the base. So let's say it was -- let's say, I think the base is 100.

The base was 180,000 barrels a day.

Cost is 50% over that. And you're over that now obviously so...

Right.

Our next question comes from Faisel Khan of Citigroup.

Of the 107 shale wells outside of Elk Hills that you guys plan to drill, are those all vertical wells or is there any horizontal wells planned in that program?

Bill can answer that.

Yes, these are predominantly going to be vertical wells, although we do have a few horizontals tossed in. But predominantly, they're going to be verticals.

Okay, and then as you step out into these other areas, is there sufficient infrastructure to move these volumes to market?

That's why we're assuring that as we go.

So you're building the infrastructure out as you go along in this program?

Or attaching to existing infrastructure. That's part of the process of making sure these are the numbers we can deliver.

On the permitting side, when you file a permit, how long does it take to -- you file a permit outside the traditional areas where you've been drilling before, how long does it take to get that drilling permit once you filed?

That's a more complicated question than you probably want the answer to. It depends. You have to file a permit for your facilities and a permit to drill the well, if you're outside of field. And so it varies based on the air quality board and those sorts of people. It's been running right now significantly longer than historical, but that's probably because we've given them so many more permits to look at. It just depends. It's very, very difficult to give a rule of thumb because it just depends. But you do have, you can think of it as two separate permitting processes, one for the facilities, which would include a tank battery review of this facility.

On a positive note, the new Governor of California and his administration really want to focus on accelerating job creation, and they do understand that, as they speed up our permitting program, as well as other things they could do, this could lead to new jobs. So they are focused on trying to be helpful. But as Steve said, it's not something you push a button, it happens. Many of these permits have been applied for already, and others would be continuing to be applied for. But there is an interest in Sacramento to speed up the permitting process. We'll see what happens, but at least the intention is very much by the Governor and his staff to be helpful.

Is there a manpower issue in the permitting process in these offices?

No, it's just paying attention. Look, you're dealing with the government of the State of California. And I think as the Governor and his people direct speed-up in some of this, I think we'll get some results.

And then one last question on the Shah gas project. Will the CapEx kind of be ratable over the next four years? Or will we see more upfront or more towards the back end?

More towards the back end of the four years.

Our next question comes from Pavel of Raymond James. Pavel Molchanov - Raymond James & Associates: Just a quick housekeeping item on the Bakken. How many rigs do you guys plan to run in 2011?

Right now, Pavel, we're running seven rigs in total, and we plan to ramp that to 12 by the end of the year.

Your next question comes from John Herrlin of Societe Generale.

Steve, what's the average completed well cost estimate for the California wells?

Shale wells?

Yes, exactly.

We're right around $4 million, drilled, completed and hooked up.

In terms of your CapEx budget for this year, how much would you consider conventional, how much unconventional, since you're getting into the Bakken and shales and all that?

Bakken is going to be small in the total. We show you I think in the slide there, the small percentage for that. And the rest is -- California, maybe half of California, maybe a little more than half. A lot of the drilling on Elk Hills is shale wells, which is why we've excluded it from this.

With respect to the acquisition market, you're still going to have a fair amount of free cash in the current environment. What are you seeing in the marketplace?

Well, right now our tummy is fairly full. So we may -- if there's some tuck-in acquisitions or something like that we can do, but right now, we're focused on delivering this year against our very sizable backlog of activity. I'm not saying we wouldn't buy anything, but it's got to be something that doesn't stretch the organization.

On the services cost front, any issues with escalation in some of the areas you're working in? Or is everything pretty much manageable for you?

Yes, John, this is Bill. I think things are manageable. I mean we're starting to see a little bit of cost pressure on the workover rig side on the Permian, but that's really the only place that we're seeing any kind of current cost pressure.

Your next question comes from Steve Marr of Citizens Trust.

Speaking about your finances overall for this year, as input costs, what are you folks using for the price for a barrel of oil for 2011?

We generally don't provide outlooks for what we think, but, obviously, oil's sitting between $85 and $90. So it's got to be something like that because we're not going to forecast something radically different than that for this year.

Our next question comes from Jeff Dietert of Simmons & Company. Jeffrey Dietert - Simmons & Company: You talked about with the Shah gas field development, you provided gas processing volumes and production gas volume expectations. Could you talk about associated condensate and NGLs? Are those volumes...

I think we've provided that too.

We said that the gross number is 50,000 barrels a day, and our share will be 20,000.

Your next question comes from Sven Oposo [ph] of IHS Herold.

A quick question just on macro natural gas in the Ruby pipeline, is that on schedule to still start up in the spring? And what's your view of its effect on your overall gas price in California?

We don't. We market our own gas here in California. California gas prices have been strong recently, above NYMEX. I think California gas prices will stay fairly strong.

And regarding the unconventional development program, is most of that on -- it's already on your vast acreage position. So I'm trying to assess what political risk might be? I mean is it just less because you're not going out and leasing new areas so the State Lands Commission can't come in and really tell you what to do? Offshore, maybe that's more of a risk, but onshore, I'm just wondering if you could give me a global statement regarding political risk of development of the unconventional resource base?

I don't think it's -- most of the acreage is in parts of the state which are away from the coast and in areas that are basically oil and gas-producing areas. So it's not really a particularly great risk where we operate. If you're talking about the frac fluids and stuff, we don't think that's an issue where we are.

Very low risk.

[Operator Instructions] And your next question comes from Joe Stewart of KeyBanc Capital.

Can you talk about potentially testing horizontal targets in the Permian basin, please?

Yes, Joe, we're currently drilling a number of Bone Springs locations, deeper Bone Springs, which, as you know, is just below the Avalon Shale. And we're testing those with horizontals and seeing some pretty encouraging results.

So you're just testing the Bone Springs. Any other formations at this point?

With horizontals?

Correct.

We also have scheduled to drill several deeper Devonian locations and test those with horizontals as well.

And any chance you could tell us how many Bone Springs wells you're planning to drill in 2011?

Yes, it's a small number. I'd say less than 10.

He's answering for our operated interest, not for how many wells we have an interest in. We have interests in almost all the wells in the area from our acreage position, so he's answering for what his operations are going to do. I think we're done now.

If there's any further questions, please call us here in New York. Thanks very much for joining us today

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