Earnings Call: Q4 2010

Jan 26, 2011

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 4th Quarter 2010 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session. Thank you. Mr. Stavros, you may begin your conference. Thank you, Christy, and good morning, everyone. Welcome to Occidental Petroleum's 4th quarter 20 10 earnings conference call. Joining us on the call this morning from Los Angeles are Doctor. Ray Arani, Oxy's Chairman and Chief Executive Officer Steve Chasen, our President and Chief Operating Officer and Bill Albright, 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 Doctor. Ronny for some opening remarks and comments regarding some of our recent transactions and new project announcements. Steve Chasen will then review our Q4 and full year 20 10 financial and operating results. 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 Doctor. Ranney. Doctor. Ranney, please go ahead. Thank you, Chris, and good morning, ladies and gentlemen. In a few minutes, Steve Chasen will provide details on our financial results for the Q4 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 beyond. Last week, we announced that the government of Abu Dhabi selected Oxy to participate in the development of the Shah gas field, one of the largest natural gas fields in the Middle East. AGSI 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 Oksy 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 to 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 Shaw field. Project is anticipated to produce approximately 500,000,000 cubic feet per day of sales gas, providing net to Oxy in the range of 200,000,000 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 Oxygen. ADNOC is already in the process of developing the field and the majority of its engineering and procurement 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 $10,000,000,000 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 at Argentina, which have not performed to our expectations, they're a subsidiary of Sinopec and expect after tax proceeds to be about $2,500,000,000 We have made acquisitions in 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. 2 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 $1,400,000,000 We expect to grow our production in the Williston Basin from these properties to about 30,000 BOE per day over the next 5 years. The South Texas acquisition from Shell for about $1,800,000,000 gives us properties which have over 320,000,000,000 cubic feet of gas equivalent in proven developed reservoirs and are liquid rich with a solid inventory of drilling opportunities. Oxy is already a major producer in Texas and these 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 S. Acquisitions together with those we made in the Q3 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 Chasen to report on Oxy's financial performance during the past quarter and full year. Thank you, Ray. Core income was 1.3 $1,000,000,000 or $1.58 per diluted share in the Q4 of this year compared to $1,100,000,000 or $1.35 per diluted share in the Q4 of last year. Net income was $1,200,000,000 or $1.49 per diluted share in the Q4 of 2010 compared to $938,000,000 or 1 point $5 per diluted share in the Q4 of 2,009. 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 2009 and by quarters in 2010 are included in the Investor Relations supplemental schedules. Argentina has not been profitable for the last 4 years. The 20 10 Q4 also included after tax non core charges of $175,000,000 for impairments predominantly of gas properties in the Rockies and $80,000,000 benefit related to foreign tax credit carry forwards. The 4th quarter 2010 core income included $110,000,000 higher pretax expense compared to the Q3 or $70,000,000 after tax or $0.09 per diluted share from equity and related compensation programs, mostly due to the effect of steep rise in the company's stock during the final quarter. Here's the segment breakdown for the Q4. Oil and Gas segment earnings for the Q4 of 2010 were $1,700,000,000 realized crude oil prices increased 11.5% in 20 10, but domestic natural gas prices declined 5.5% in the Q4 of 2,009. Production volumes for the Q4 of 2010 were 750,000 BOE a day, 5% increase compared to the 717,000 BOE a day in the Q4 of 2,009. 4th quarter production of 7.53 per day was slightly higher than 3rd quarter's production of 751,000 BOE per day. 4th quarter volumes compared to the 3rd quarter were negatively impacted by 10,000 BOE a day from the effects of our production sharing contract, 6,000 BOE a day due strikes in Argentina and inclement weather in December, which impacted our California production. In California, oil affecting the production sharing contracts at our Thoms 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 4th quarter was 714,000 BOE a day. The 3rd quarter production would have been 716,000 BOE a day if Argentina were excluded. The 4th quarter sales volume were 7 51,000 BOE a day. Sales volumes different from production volumes due mainly to the 4th quarter lifting in Argentina, which slipped from the Q3 partially offset by Iraq production, which will be sold in 2011 and a lifting in Colombia, which was sold in the beginning of this year. Exploration expense was $54,000,000 in the quarter. Chemical segment earnings for the Q4 of 2010 were $111,000,000 and in line with our earlier guidance. Midstream segment earnings for the Q4 of 2010 were $210,000,000 compared to $163,000,000 in the Q3 of 2010 $81,000,000 in the Q4 of last year. Increase in earnings was mainly due to higher trading and marketing income. Worldwide effective tax rate was 38% for the 4th quarter. Now let me turn to Oxy's performance during the last year. Core income was $4,700,000,000 or 5.72 dollars per diluted share for the 12 months of this year compared to $3,200,000,000 or $3.92 per diluted share for the full year of 2,009. Net income was $4,500,000,000 or $5.50 per diluted share for the 12 months of $2.10 compared with 2.9 $1,000,000,000 or $3.58 per diluted share for the same period of 2,009. Income for the 12 months of and 9 included 2010 included $134,000,000 of charges net of tax and 2,009 included 2.77 $7,000,000 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 20.10, 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 work over and maintenance costs. Taxes other than non income were $1.83 a barrel for 20.10 compared to $1.67 per barrel for all of 2,009. These costs which are sensitive to product prices reflect the effect of higher crude oil and gas prices in 2010. Capital spending for the 4th quarter was about $1,400,000,000 3,900,000,000 dollars 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 $9,100,000,000 excluding Argentina. We used $3,900,000,000 of the company's cash flow to fund capital expenditures, dollars 4,700,000,000 on acquisitions and 2.20 $5,000,000 on foreign contracts. These investing cash flow uses amounted to $8,800,000,000 We issued 2 point $6,000,000,000 of debt in the 4th quarter. We also used $1,200,000,000 to pay dividends and $310,000,000 to retire debt. Argentina's net cash flow for the year was a negative $125,000,000 after spending $415,000,000 for capital expenditures and contract extension payments. These and other net cash flows increased our $1,200,000,000 cash balance at the end of last year by $1,400,000,000 to $2,600,000,000 at December 31. Free cash flow from continuing operations after capital spending and dividends, but before acquisition activity and debt retirements was about $4,300,000,000 Our acquisition costs in the Q4 were $3,100,000,000 which included the previous announced purchases of oil and gas bolt on properties mainly in Permian. We expect to close the purchase of several addition properties in the sale of Argentina in the Q1 of During the year, we spent $4,100,000,000 on oil and gas acquisitions, of which about 50% was on unproved properties. On a preliminary basis, our 20 10 reserve replacement ratio was about 150%. Approximately 1 third 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 $812,500,000 and the weighted average diluted shares outstanding were 813,800,000. Our debt to capitalization ratio was 14% at the end of the year. Our 2010 return on equity was 14.7 percent, the return on capital employed of 13.2%. As we look ahead in the current quarter, our Q1 2011 production will be impacted by the following factors. 1st, we will no longer report Argentina production. 2nd, the timing of completion of the new acquisitions, while the acquisition of 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 1 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 Q1 of 2011. The impact of Dolphin shutdown will be about 5,000 BOE a day for the quarter. We expect the Q1 oil and gas production volumes to be between 740,000 750,000 BOE a day at 4th 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 Q1's results and 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 the end of the second half of the year by at least by the end of the second half by the 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 current with regard to current to prices at current market prices, dollars 1 per barrel change in oil prices impacts quarterly earnings before income taxes by about 41 $1,000,000 The average 4th quarter WTI price was $85.17 per barrel. A swing of $0.50 per 1,000,000 BTUs in domestic gas prices has a $36,000,000 impact on quarterly earnings before income taxes. This is a significant increase in price sensitivities from what we have told you in the past. The current NYMEX gas price is around $4.5 per Mcf. Additionally, we expect exploration expense to be about $85,000,000 for seismic and drilling for our exploration programs. The Chemical segment is expected to provide earnings for the Q1 of about $125,000,000 We expect margins and volumes to continue to improve as the economy strengthens. We expect our combined worldwide tax rate in the Q1 of 2011 to be about 40%. Our Q4 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 $6,100,000,000 compared to the 2010 total of $3,900,000,000 Both amounts exclude Argentina 2019 capital is close Our 2011 capital is close to our 4th quarter annualized run rate of $5,500,000,000 and in line with the 5 year capital program we gave in the May investor presentation, plus the capital was deferred from 2010. The breakdown of the 20102011 10 and 20 11 capital by area and segment is included in the supplemental schedules. Our oil and gas DD and A expense for 20.11 should be approximately $11.75 per BOE. Appreciation for the other two segments should be about $500,000,000 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 and 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 supplemental schedules are available on our website or on the SEC system. We're now ready to take your questions. And your first question comes from David Heikkinen of Tudor Pickering. Good morning, Steve. As we think about the industry and then your operations, 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 both operationally and then that asset operationally and then also how you think about how and what your disclosure process will be heading forward? If we take the 2 U. S. Assets, start with the Permian, which in some ways is easiest. I think 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 in a meaningful way. We're not going to provide 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. As we switch to California, as the shale drilling program accelerates this year, it will be fairly obvious we think what the potential there is. We've got, I think I said, 2500 Shale locations. We don't think that the description of them is materially different from what we gave you in May. That is roughly how much the recoverable per well is the initial rates and the costs. So I think we have at least 500 that's on 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. Permitting But I But I think it will be pretty obvious when you look at production going forward and I think you will see some pretty decent results as the year progresses. 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 or? Almost all the Almost all the increase is in primary drilling. The numbers we're showing you as a percentage, you can multiply the percentage out almost all the increases 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 slug size. So the increase is overwhelmingly in prime what you would describe as primary drilling. We have a lot of acreage available. Several year we 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 in billions of barrels as opposed to 100 of millions of barrels. And then just kind of bigger picture and not trying to replace you, but have had the question about succession planning and thoughts at Oxy. Can you talk about kind of Board level and what the thoughts are around management and any I think we'd let the Chairman of the Board discuss it at the Board level. What is your specific question? Basically, as you go through the transition, people ask who is behind Steve and just want to understand kind of 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 say, have Steve take over first and we can also be looking at the placements. We have a bench, but we think we can execute our plans with our current manpower. That's it. Thanks guys. Your next question comes from the line of Paul Sankey of Deutsche Bank. Hi, good morning, guys. Good morning, Paul. 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're expecting volumes to be around $740,000,000 to $750,000,000 in Q1 and $725,000,000 of sales, but obviously that would be negatively impacted by the loss of Argentina? No, that's we've already done that. Okay. So that's all out. Yes, right. And then what you said was I think what you said was by second half, you would expect volume second half twenty eleven, you'd 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 8.37%, 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? I don't it's hard to say the variance is built because of our demonstrated ability to predict all that well. So somewhere in that range, but I think that run rate adjusted for the price, you got to take off the oil price change, so that would last year was down at $75 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 1,000 a day and that are 48,000 or something like that. But we basically replaced that with the other stuff. Okay. So the net difference is 0, let's say, and then That's 0 is around 0, except for the noise in the Q1 of the handoff. But then essentially what we're looking for is allowing for the change in price around the 6% growth rate being achieved by the second half of the year? I think that's right. Okay, great. That clarifies it. Sorry, I was getting a bit tangled up there. Yes. 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. Yes, got you. And then on the Q1 is a little noisy. 2nd quarter maybe a little noisy. But by the second last two quarters, we should be back in line at that rate. Great. 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 'nine to Q4 'ten despite whatever it is, dollars 10 increase in the oil price and with increased volumes. Can you just talk a little bit about what's going on there and some of the I think the 2 major factors. 1, some of this employee expense got rolled into that. And second, it's not really operating costs and stuff. And 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. Yes, that's right. Okay, I understand. So that kind of explains that. I'll leave it there. Thank you. Thanks. Your next question comes from the line of Arjun Murthy of Goldman Sachs. Steve, just a 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? Thank you. I'll let Bill answer that. Yes. Hello, Arjun. Good morning. 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 you still need procure some? No, we have the 12 right now. And how about completion crews? Well, a lot of these shale completions are acid ized as opposed to fracturing and we're in pretty good shape on our asset. Got it. So this is a situation where as you drill the wells, we 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 the shortage of services. We're running along pretty well right now. We track in the 1st 3 weeks of the month. We're right on. We gave you a number here for a number of wells drilled. The locations are permitted and the rigs are in place and the completion crews are in great place. Unlikely, except for a rainstorm or something like that, it's unlikely that there will be as much downside to this. Right. And in the analyst meeting, you gave a range of 400,000 to 700,000 BOEs per well. If you take 500,000 views a well times 100 wells, that's 500,000,000 barrels a year of opportunity. From a reserve booking standpoint, is that how we should think about it? Or there is some lag because you got to see production over time and that's obviously just 1 year drilling? No, I think what you 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 last 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 BUDS because a lot of these are very similar to each other. So the statistical approach gives you a pretty conservative result. We are working on our costs are coming down as a 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 a pretty conservative basis, but we are booking some puds. And then the last question on California, I mean 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? Yes. It is. Okay. Will Iraq be accretive to earnings when you actually sell the oil in the 1st or second quarter this year? Yes. Terrific. Thank you very much. Our next question comes from Doug Terreson of ISI Group. Good morning, guys. Good morning, Doug. In E and P, P, the growth outlook clearly appears to be improving with the new ventures. But Steve, my question regards to potential for return enhancements between better performance on the base, some of the divestitures that I think Ray talked about and or investment in some of the new ventures that were discussed, meaning 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 Fat Quarter Argentina, which I said hadn't made any money in 4 years. So without a lot of effort, I can improve returns. Okay. We have 40,000 barrels a day making no profit. Yes. So I think that was a fairly easy thing for us to compute. The rest of the the only drag on the base I think, the rest of the base ought to be improving. A little higher gas prices than they need a lot and a we the Permian, the CO2 remember CO2 didn'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 Shaw field. And so that investment will show up as investment and no production for 4 years. So it will be a drag, but I think the rest of it will easily overcome that. Okay, great. Thanks a lot. Thanks. Your next question comes from Doug Leggate of Merrill Lynch. Thanks. Hi, gentlemen. Good morning. Good morning. So a couple of things, I guess, I'm afraid. First one, California. Steve, you did mention this in one of your answers to all the questions. But just to be clear, I mean, the 5 20 locations that you derisked so far, approximately what we're talking about in terms of de risked acreage on your 1,600,000 acres? It wouldn't be material. So less than 10%? Oh, for sure. Okay. 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 higher oil price environment, which I'm guessing you didn't plan for how that might play into your opportunity set in terms of activity levels? On California, I think that once we get real clarity on the permitting, this thing could will accelerate rapidly. There's no reason except right around the current 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 out in the back half of the year, it would be a fairly sizable increase in the rig count. In the Permian, I think we're doing okay and we may excel 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 if the year progresses, if it does what we hope, the number of rigs will continue to build. So we would expect as we exit this year to be at a 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. Got it. So I'm trying to reconcile the 2, Steve, I'm sorry to labor the point, but so basically we've got 12 rigs running, I think is what Bill said before, in 5 20 locations. So let's assume you double the rig count in California. I mean, how much running room do you really believe that you have there in terms of the shale drilling program? The $520,000,000 is a small percentage of the total that we actually have. If you count our contingent locations and those sorts of things, you're right now we're triple less or something. Okay, great. And I guess the final one for me is just going back on the production guidance. I mean, the numbers you gave in May excuse me, the numbers you gave in May were had you north of 800,000 barrels a day as an average for this year, netting out Argentina adding back the acquisitions. Can you 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 the number you could provide? I don't really think of it that way. So 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 the following year's numbers, the 2012 numbers we've given you. So the 2012 guidance is still good? That's right. So until we we may have to redo it a little bit and raise it. But other than that, if you just look at the 2012 guidance, take out assume the Argentina and the acquisitions are awash just for this purpose. When you get through, I think your so your run rate as you enter at sort of December or late next year will lead you to the following year's numbers we've given you. Adjusted for oil prices? Adjusted for oil prices, right. I can't hopefully they continue to go up, so that will be all right. Okay. All right. I'll leave it there. Thanks. Thank you. Your next question comes from Philip Dodds of Tuohy Brothers. Good morning. Thanks. It looks like your U. S. Gas production increased quarter to quarter in the Q4, even though California was down. So if that's correct, can you fill us in on where some of the increases were place? We'll let Bill answer that while he's 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 2 primary areas where we're focusing on in terms of primary development. Okay. And then next, could you bring us up to date on the expansion of the processing capacity in the discovery area in Kern River both growth and depth? The plant has been ordered and we would expect it to be on in the Q1 of next year. Okay. 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 of Avaya? I can't. We expect the exit rate for Iraq in 2011, the exit rate to be over 300,000 a day. Okay. And then we just relate your ownership to that number and we're pretty far along? Well, it's hard to it's more complicated than you want. Can you say how much of that would be cost recovery oil? The cost recovery percentages is 50% of the excess over the base. So let's say it was I think the base is 100. The base was 180,000 barrels a day. Okay. Cost 50% over that and you're over that now obviously. So That's right. Okay. Thank you. Your next question comes from Faisal Khan of Citigroup. Hi, good morning. Good morning. Of the 107 shale wells outside of Elk Hills that you guys plan to drill. Are those all vertical wells or is any horizontal wells planned in that program? Phil 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 areas, is there sufficient infrastructure to move these volumes to market? That's why we're assuring that as we go. Okay. 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. Okay, got you. And then on the permitting side, what's the when you file a permit, how long does it take to when 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 file? It'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. Okay. 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 so many more permits to look at. But it just depends, very difficult to give a rule of thumb because it just depends. But you do have, you can think of it as 2 separate permitting processes, one for the facilities, which would include a tank battery that would be viewed as facility. Okay, got you. 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 if they speed up our permitting program as well as other things they could do, this leads 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'd 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 audits? Auctions? No. It's just paying attention. I mean, look, you're dealing with the government and 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. Okay. Understood. Thank you. And then one last question on the Shaw Gas project. Will the CapEx kind of be ratable over the next 4 years? Or is it going to will we see more upfront or more towards the back end? More towards the back end of the 4 years. Okay. Thank you. Your next question comes from Pavel of Raymond James. 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 7 rigs in total, we plan to ramp that to 12 by the end of the year. Okay. That's all I had. Thank you. Your next question comes from John Herrlin of Societe Generale. Yes. Hi. Steve, what's the average completed well cost estimate for the California wells? Shale wells? Yes. Right around $4,000,000 drill completed and hooked up. Okay. Great. In terms of your CapEx budget for this year, how much would you consider conventional? How much unconventional since you're getting at the Bakken and shales and all that? Bakken is going to be small in the total. So 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. Okay. What are you seeing A lot of the drilling on Elk Hills is shale wells, which is why we've excluded it from this. Okay. 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? 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. Okay. I'm not saying we wouldn't buy anything, but it's got to be something that's easy that doesn't stretch the organization. Okay. Last one for me. 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 seeing we're starting to see a little bit of cost pressure on the workover rig side in the Permian, but that's really the only place that we're seeing any kind of current cost pressure. Okay, great. Thank you. Your next question comes from Steve Marrs of Citizens Trust. Hi, thank you for taking my question. Speaking about your finances overall for this year as input costs, what do you folks are using for the price of for a barrel of oil for 2011? We generally don't provide outlooks for what we think. But I mean obviously oil sitting between $85 $90 So it's got to be something like that because we're not going to fork out something radically different than that for this year. Okay. All right. Thank you. Thanks. Our next question comes from Jeff Dieter of Simmons and Company. It's Jeff Dieter with Simmons. Good morning. Good morning. You talked about with the Shaw Gas field development you provided gas processing volumes and production gas volume expectations. Could you talk about associated condensate I think we provided that too. We said that the gross number is 50,000 barrels a day and our share will be 20,000. Okay. Thank you. Your next question comes from Sven Del Pozzo of IHS Harold. Yes, 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. And so we California gas prices have been strong recently, above NYMEX. I think California gas prices will stay fairly strong. Okay. And regarding the unconventional development program, is most of that on your already vast 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. I mean they might offshore maybe that's more a risk, but onshore, I'm just wondering if you can give me a global statement regarding political risk of development of the unconventional resource base? I don't think it's but 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, Rick. Okay. Thank you. And your next question comes from Joe Stewart of KeyBanc Capital. Joe, your line is open. Hello. Can you hear me? Yes. 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. Okay. So you're just testing the Bone Springs, any other formations at this point? With horizontals? Correct. Yes. We also have scheduled to drill several deeper Devonian locations and test those with horizontals as well. Okay. 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. Okay, great. Thank you very much. He's answering for our operated interest, not for how many wells we have an interest in. We have interest 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 see. Okay. Thank you for the clarification. I think we're gone now. If there is 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.