Earnings Call: Q3 2010

Oct 19, 2010

Good morning. My name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Occidental Petroleum Third Quarter 2010 Earnings Release Conference Call. 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 3rd quarter 20 10 earnings conference call. Joining us on the call this morning from Los Angeles are Doctor. Ray Irani, Oxy's Chairman and Chief Executive Officer Steve Chasen, our President and Chief Operating Officer Business. In a moment, I'll turn the call over to Doctor. Gas Business. In a moment, I'll turn the call over to Doctor. Ronny for some opening remarks and comments regarding the new management structure we've announced recently. Steve Chasen will then review our Q3 and year to date 20 10 financial and operating results. Our Q3 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 about the new management structure we announced last week, both for myself and for Oxy. The new structure would assure Oxy of continuity of a winning team, both in terms of our experience and effective management and in terms of our emphasis on a highly successful business strategy. To recap the new structure, I informed our Board of Directors of my desire to relinquish the position of Chief Executive Officer effective at the May 2011 Annual Meeting of Stockholders and to continue as full time Executive Chairman. I recommended to the Board that Steve Chasen replace me as CEO. The Board agreed with this new structure. Steve is a proven leader. He has been an integral member of our senior management team for many years. Steve joined OXY in 1994 as Executive VP, Corporate Development, became Chief Financial Officer in 1999, President in 2007 and Chief Operating Officer earlier this year. He was also elected to the Board of Directors in 2010. He has made and will continue to make significant contributions to Occidental's ongoing success and development. This is a carefully developed and long anticipated senior management transition. Steve and I have had an extraordinary productive maintaining this partnership is in the best interest of OXY and its stockholders, and I look forward to continuing this partnership in future years. During the 20 years that I have been CEO, our management team has transformed Oxy from a conglomerate of unrelated business entities with a market capitalization of $5,000,000,000 into the 4th largest oil and gas company in the United States with a market capitalization today of $67,000,000,000 Oxy has led its proxy peer group in total stockholder return with cumulative returns of 76% over the past 3 years, 2 0 4% over the past 5 years and 8 70% over the past 10 years. I'm very proud of these accomplishments. Our management team is strong and cohesive and would be ready, willing and able under this new structure to take Oxy to new heights in performance and excellence. I'll now turn the call over to Steve Jayson for the details on our 3rd quarter performance. Thank you, Ray. Net income was 1 point $1,000,000,000 or $1.46 per diluted share in the Q3 of 2010 compared to 927,000,000 dollars or $1.14 per diluted share in the Q3 of 2,009. Income from continuing operations was $1.47 per diluted share in the Q3 of this year compared to $1.14 per diluted share in Q3 of last year. Here is a segment breakdown for the Q3. Oil and Gas 3rd quarter ten segment earnings were $1,700,000,000 compared to $1,500,000,000 for Q3 of last year. The improvement in 20 10 was driven mostly by higher commodity prices, additional contributions from higher volumes. Realized crude oil prices increased 13% in 20.10 and domestic natural gas prices improved 38% in the Q3 of 2,009. Partially offsetting these gains were higher DD and 2,009. Partially offsetting these gains were higher DD and A rates and higher operating expenses, partly resulting from fully expensing CO2 costs in 2010. Production for the Q3 of 2010 were 751,000 BOE a day, 6 5% increase compared to 705 BOE a day in the Q3 of 2009. Most of the year over year production increases came from the Middle East, North Africa with smaller increases in Argentina and the United States. The worldwide oil and gas sales volume for Q3 of 2010 were 740 9,000 barrels of oil equivalent per day, an increase of over 6.5% compared with 702,000 BOE a day in the Q3 of last year. Sales volume differs from the production volumes due mainly to the timing of a lifting in Argentina. Exploration expense was $83,000,000 in the quarter. Oil and gas cash production costs excluding production and property taxes were $10.25 a barrel for 1st 9 months of 2010. Last year's 12 months costs were $9.37 a barrel. The 9 month increase reflects a $0.35 a barrel higher CO2 cost due to our decision to expense 100 percent of injected CO2 beginning in 20 10 and higher field support operations, workovers and maintenance costs. The higher domestic workover activities mostly in the Permian. Taxes other than and on income were $1.76 per barrel for the 9 months of 2010 compared to $1.60 per barrel for all of 2,000 and These costs which are sensitive to product prices reflect the effect of higher crude oil and natural gas prices in 2010. Chemical segment earnings for Q3 of 2010 were $189,000,000 compared with $108,000,000 in the Q2 of 2010. 3rd quarter results reflect improvement for the Q2 in 2010, both volumes and margins across most product lines. Export markets have improved more rapidly than domestic markets due in part to favorable feedstock costs in North America versus Europe and Asia. Midstream segment earnings for Q3 of 2010 were $163,000,000 compared to $77,000,000 in the Q3 of 2,009. The increase in earnings was mainly due to trading 2010. Let's now turn to our performance for the 1st 9 months of this year. The net income was $3,300,000,000 or $4.07 per diluted share for the first 9 months of 2010 compared with $2,000,000,000 or $2.43 per diluted share for the 1st 9 months of 2,009. Core income was $3,300,000,000 or 4 point $1,000,000,000 or $2.48 per diluted share for the year to date 2,009 period. The weighted average basic shares outstanding for the 9 months of 2009 were 812,400,000 and the weighted average diluted shares outstanding were 813,800,000. Our debt to cap ratio was 7% at the end of the 3rd quarter. Capital spending for the Q3 of 2010 was about 1 point $1,000,000,000 $2,800,000,000 for the 1st 9 months. Year to date capital expenditures by segment were 82% in oil and gas, 13% in midstream with the remainder in chemicals. Cash flow from operations in the 1st 9 months of 2010 was $6,600,000,000 We used $2,800,000,000 the company's cash flow to fund capital expenditures, $1,600,000,000 on acquisitions and $340,000,000 on foreign contracts. These investing cash flow uses amounted to 4 point $7,000,000,000 We also used $850,000,000 to pay dividends and $310,000,000 to retire debt. These and other net cash flows increased our $1,200,000,000 cash balance at the end of last year by $900,000,000 to 2.1 $1,000,000,000 at September 30. The 1st 9 months free cash flow after capital spending and dividends before acquisition activity and debt retirements was about $3,100,000,000 Our acquisition costs in the 3rd quarter were 1.1 $1,000,000,000 and we expect to spend about $300,000,000 in the 1st part of the 4th quarter. For these acquisitions, we expect to add about 10,000 BOE a day in average production in the Q4. These acquisitions have a run rate of about 12,000 BOE a day. Of this production, about a third will be liquids and balance will be natural gas. Over the medium term, we expect these acquisitions to add at least 25,000 BOE a day of production. This increase will come largely from oil production. In addition to these acquisitions, we expect to add an additional 300,000 380,000 acres to our California acreage position and interest in 100,000 acres in other producing areas. Our California acreage will now reach 1,600,000 acres, an overwhelming portion of which consists of mineral interests. We currently don't contemplate any more sizable acquisitions of acreage in California. Our total year capital spending is expected to be about $4,400,000,000 The capital spending rate will increase in the Q4 of the year largely in our domestic operations and in Iraq. Beginning of the year, we were running 11 development rigs in California and 5 rigs in the Permian. We're currently running 16 rigs in California and 9 in the Permian and expect our year end exit rig count to reach 19 rigs in California and 14 in the Permian. Next year, we anticipate working 21 rigs in California and 15 rigs in the Permian. In the current environment, we are cautious about natural gas drilling and may reevaluate our 20 11 U. S. Natural gas drilling program. In the Permian, we are currently running 94 workover rigs compared with the 50 7 rigs we had at the beginning of the year. We currently expect to be operating 110 rigs by the end of this year. Due to higher workover activity to $10.94 per barrel in the Q3 of 2010 and further increases are expected range of 760,000 Boe to 770,000 Boe a day at 3rd quarter average oil prices. Volume increases in the 4th quarter are expected to come from California, Oman's Magna field and the acquisitions. Increase in oil prices of $5 a barrel from the Q3 of 2010 levels would result in about 4,000 BOE a day of lower production due to the impact of higher prices affecting our production sharing and similar contracts. Based on the development plan at the Zubair field in Iraq, we believe that we should have a small amount of production in the Q4. We do not expect to report any sales from Iraq until the Q1 of 2011. Field development plan is on target for us to meet next year's production targets. With regard to prices, at current market prices, a dollar per barrel change in oil prices quarterly earnings before income taxes by about $39,000,000 Average third quarter WTI oil price was 76.2 $0 per barrel. For gas, a swing of $0.50 per 1,000,000 BTUs in domestic gas prices has a $27,000,000 impact on quarterly earnings before income taxes. Approximately the current NYMEX gas price is under $3.90 per Mcf. Additionally, we expect exploration expense to be about $110,000,000 for seismic and drilling for our exploration programs. Chemical segment is expected to provide earnings for the quarter of about $100,000,000 to $120,000,000 The 4th quarter is usually the weakest for the business. We expect the continued margin improvement will be offset by the typical seasonal slowdown in the housing construction, bleach and fertilizer markets. Expect our combined worldwide tax rate for the in the 4th quarter to be about 41%. Our 3rd quarter U. S. And foreign tax rates are included in our supplemental schedules. The Century plant in the Permian has just started operations and providing additional CO2 to support growth in our Permian operations. We expect that the plant will yield about 180,000,000 cubic feet a day of CO2 next year to support our Permian EOR operations. We are in the process of contracting additional CO2 from other sources and California. In the 1st 9 months of the year, we drilled 7 conventional exploration extension wells in California. Of these, 5 were outside the Kern County discovery area. 2 of these wells are currently being tested. We also drilled 12 unconventional exploration wells in the 1st 9 months of this year, of which 3 are successful and 5 are being tested. In the Q4, we expect to drill 10 exploration wells of which 2 be conventional, the remaining 8 wells non conventional. In the Q4, our exploration program will target smaller prospects until permits are obtained for the larger ones. We've also drilled 13 conventional exploitation wells in the Kern County discovery area and 15 unconventional exploitation wells in California in the 1st 9 months. Due to delays in permitting, we've reduced our exploitation plans for the second half of the year by about 10 wells. We are continuing to have problems with our gas processing and gathering infrastructure at Elk Hills. As a result, we expect our gas related NGL production to be about flat in the 4th quarter. We have ordered construction of the 1st new processing plant, we'll order the 2nd plant shortly. Once complete, the new processing plants will increase productive capacity, improve yields, enhance netbacks and lower operating costs. We are also working actively to optimize and debottleneck our existing facility to improve performance. Additionally, we are shifting our drilling to oil wells, which we expect will result in higher oil production in the 4th quarter. Copies of the press release announcing our 3rd quarter earnings Investor Relations supplemental schedules are available at our website or through the SEC's EDGAR system. We're now ready to take your questions. And your first question comes from David Heikkinen of Tudor, Pickering. Good morning, Steve. Good morning. Just a quick question. As you think about the acquisitions in the quarter and then the medium term run rate of adding Medium term is 3 years or less. So it will fall clearly within the plan. As we look at where we are right this minute, it's likely we'll slow up our gas drilling in the Rockies next year. And so we view this as sort of an offset for that. If that's what turns out, gas prices are higher, we'll spend more money. But I think that's the way I think about it is that we're shifting to an oilier base on the intermediate term as long as we have these not very attractive natural gas prices. And then as you think about you mentioned that you'll be buying CO2 and using I guess the penalty payments for that. Can you give us an idea of what the purchase price of CO2 is on a per Mcf basis today just so I can start thinking about how you fulfill those volumes And of course, we also have the option to throttle up our drilling in the Oxy owned Bravo Dome field, which is up in Northeast New Mexico? So as I think about that, CO2 volume is still on track. So the acceleration in rig activity is more primary production in the Permian. Any particular regions that you're increasing rig count would be helpful. Yes, David, one of the regions is in the Wolfberry trend, where we currently have a couple of rigs working and you could probably see some throttle up there in particular. Any horizontal drilling there yet? No. Are not drilling horizontal wells there yet. Okay. Thanks, Ken. Your next question from Robert Kessler of Simmons and Company. Good morning, gentlemen. Can I ask you to put a range around your 2011 CapEx at this point? It seems like you've got a number of offsetting factors. You mentioned your prudent caution with respect to natural gas prices, the ramp up in activity in California and the Permian and that kind of offsetting the conservatism on gas. Your pie charts from the analyst meeting would seemingly imply a pretty good uptick next year somewhere in the order of $5,500,000,000 to $6,000,000,000 in CapEx versus this year's $4,500,000,000 But qualitatively it seems you might be on the lower end of that range. Is that the right way to think about it or can you put something around next year's capital program at this point? We're still developing it to be fair, but the estimate we made in May wasn't that far wasn't that long ago. So if you subtract the 4.4 from the 5 year total and divide by 4, it give you at least a feel for it. We don't have any way to micro analyze whether it's going to be $200,000,000 less or $200,000,000 more, obviously not all that accurate anyway. How do you think about your exploitation CapEx for 2011 in California as you continue to since sort of stranded temporarily while you wait on the additional processing capacity and why not taper back a little bit since you're not really at risk of losing this acreage next year if you don't drill it up more aggressively? Yes, we're shifting to more oil production. And so we think we'll be okay, but we're being cautious about not just the capacity, but not very exciting natural gas prices. Got you. And then a quick point of clarification for me. I think Bill responded to David's question about CO2 incremental acquisition cost of $1,000 $1.15 per annum. I'm assuming that's a gross cost. And can you remind us what the net would be after subtracting the fee for non delivery of gas? It depends on how much they non deliver. But to the extent that it's making up for shortfalls, it's $0.25 Got you. Thanks very much. Our next question comes from Paul Sankey of Deutsche Bank. Hi, Steve. Good morning, Greg. Or afternoon or whatever it is. If we could just if I could have a specific one on acquisitions and then a more general one. Could you talk a little bit more about the location of the acquisitions you made in the quarter because I guess the gas oil split would indicate that they're slightly off your usual beaten The bulk of the acquisitions are in the Permian. And they may show up partially in the Mid Continent gas unit because they're in the New Mexico oilier natural oilier natural gas and Mid Continent gas up a little bit. So the split may be off, but the overwhelming majority is in the Permian. I've got you. And by extension, there's no sort of step out acquisitions that you might be doing. I don't answer the Mar sellers or wherever. No, we did a small acquisition in I thought I think I've told the story about that. We had a small interest in Bakken, 25 percent interest. The sellers wanted to monetize it. So we looked at the numbers and bought them out. And that will show up also in the Mid Continent unit. But that's pretty small in the total. Great. And then if I could extend that into the wider question, if I'm not wrong, the volume targets that you set at the analyst meeting were ex disposals, ex acquisitions. I know there's been a lot of moving parts here obviously with California and other stuff, but do we need to reset the target outlook allowing for the fact that I guess we didn't meet the full year target here without acquisitions or can you reiterate the numbers that we had at the Analyst Meeting for future growth ex acquisitions? I the big change is that the gas price hasn't met so far in what we'd hope for where we'd be at this point. So I would view the acquisitions as a replacement for the gas production that we're probably not going to get next year from the Rockies. So I think next year guidance is probably pretty good. Right. So without acquisitions, we can still assume that you'll meet that 6.2% base acquisitions, we can still assume that you'll meet that 6.2% base that you talked about with the That's what we're looking for. And right now, don't have a reason to change that. But I'd caution you about the gas. The gas in the Rockies is the only place where I'm feeling a little seasick right now. Yes. How much should a step down could we could you envision seeing there? I mean, how much is at risk if you like? I don't know. But we have 2 rigs running currently and we had planned to go to double that next year and I don't think we'll do that. So it's whatever growth we've shown there, I think is probably at least some risk. And so I think from my perspective, the acquisitions are just like drilling money, you move the money around and I think the acquisitions will cover that. Right. But then find it a different way. I've got you. And then finally to California performance, is there simple math that we can do in terms of the number of rigs running relative to the was? I don't think there's no simple math because I've been unsuccessful in doing the simple math. So even complicated math is difficult. It just depends on how fast they get the wells down and where they drill them and how they get their permits. So and where they get them. So I wouldn't right now I'm being fairly cautious about it in our outlooking process. Is it possible sorry? Pardon me? Excuse me, you go ahead. I'm just being cautious about our outlooking process right now. I'm always hopeful that they'll do better, but right now we'll stay with the fairly cautious view of it in the short term. But we could expect an acceleration in permitting or is it Yes, no, eventually the permits come through. It's just a matter of when. I think we were a little optimistic about or maybe a lot optimistic about how fast we get them. Right. Okay. Thanks. And let me congratulate Ray and yourself for the management changes and the success of the past. Thank you. I hope so too. And your next And your next question comes from Arjun Murti of Goldman Sachs. Thanks. Sorry if I missed it in all the previous CO2 questions, but how does the penalty compare to your purchase price of CO2 if it's outside of the Well, we said that for the purchase gas, we're running $1.10 to $1.15 area and the assuming you'd want to sell assuming you'd want to sell into it taking your volume, your ability to produce volumes out there too? Yes, but basically about to bring us back on track for where we said we'd be in California. Got it. Thanks. And then just on the Bakken comment, should we take this as your entry into the play and you'll look to expand or it's a test case and we'll see where you go with it? It started as an experiment and experiment 3 quarters was attractive. So we'll drill this out. If we can enter cheaply, we will, certainly not an area where we're heavily focused. Got it. Thank you very much. Thanks. Your next question comes from Jason Gammel of Macquarie. Thanks very much. And I would also extend my congratulations to Doctor. Ronny and to Steve. I had a couple of questions on California. First of all, the acreage that's being added, a pretty big swath of acreage. I was wondering if you could comment on how such a large amount of acreage is still being pulled together. Is this private companies, public companies that are selling or is this actually organic leasing with landholders? Not leasing. Okay. And then also just on some of the comments you made about volumes, increasing overall California volumes, but flat natural gas and NGL volumes, I was trying to reconcile how you could be increasing the oil volumes without associated gas. Does this mean you're able to actually reinject at Elk Hills or something along those lines? No. I mean some of the wells are oil wells, legitimate oil wells. Said flattish. So that's what I would look for given the outlook right now is that we actually are drilling real oil wells, not condensate wells. Okay, thanks. I was probably trying to read too much into the semantics there. Yes, right. In fact, I'm trying to be too clever. I'm rarely accused of being too clever. And final question if I could. You've mentioned the 7 conventional exploration wells that you've drilled in California. Would you be able and 2, obviously testing, but would you be able to comment on how many of the wells that you've drilled so far would be you'd be able to classify as either successful or unsuccessful? About a third of the wells are successful of exploration. Your next question comes from Doug Leggate of Merrill Lynch. Thanks, fellas. Good morning, I think, and congratulations to both of you guys. I look forward to working more with you in the future. Couple of questions, Dave, please. On the increase in the rigs, can you help us understand a little bit what exactly are you going after here on these incremental rigs, particularly in California? Is this the shale play getting some attention now? And if so, can you give us a little bit more color please on reverting back to what you said in your conference about what the kind of IP rates were indicatively, what the kind of down spacing was, all that kind of good stuff. Basically, what are we looking at in terms of shale drilling activity as we look forward? No, there's clearly a step up in shale drilling activities in the numbers for a sizable increase. The rest of it is sort of stuff we had planned, but the shale drilling has picked up and the wells are still running 300, 400 a day on average, some a lot higher. So I would go 300 to 4 barrels a day sort of per well. And that's like a 30 day IP type of indicator? It's our 30 day or maybe a little longer. It's not an IP number. IP number is a little misleading. Okay. Forgive me for probing a little bit on this because clearly if you're drilling these things, I'm guessing 20, 25 days because they're verticals if I'm not mistaken? Yes, about a month, yes. Okay. So, basically, your drilling campaign on this, should I assume maybe 10 of these rigs are drilling on the shales looking at the step up? Yes, a little less than that probably. Okay. So net net, we're looking at a fairly substantial acceleration in that program. So basically, what did you have baked into your guidance when you gave your strategy presentation in May by way of rig programs compared to what you're now telling us? Maybe a little more in what we're now telling you than we told you in May, maybe a couple more rigs. Okay. And the shift is over to oil rather than gas as you said? That's right. Okay, got it. Thank you. Just jumping to exploration very quickly, you said 1 in 3 was your success rate. But again, at your strategy presentation, you said you were going to drill 30 exploration wells starting next year. And I guess it kind of like a third, a third, a third between the different types of play, the big plays and the bread and butter as you call them. How many of the wells you've drilled this year are in that sort of big category versus the bread and butter, let's say? No big ones. So they're all sort of 1,000,000 to 10,000,000 barrel targets? They're small targets. Yes, smaller targets. And I guess the final thing would be just as it relates to the Elk Hills gas plant, can you be a little more specific on the new plants for a 2012 startup, but as I understand that the gas gathering system has been the problem, can you be a little bit more specific as to what the issues have been, what you're doing about it and what the current status is in the early part of Q4? And I'll leave it there. Thanks. We don't really our ability to predict this has not been all exciting. So our goal is to get everything working. As we try to run the plant, there's some problems on the gathering system at the traditional Elk Hills. And we're working on trying to see if we can make that better. So I've taken a cautious view right now to improvements. Okay. All right. Thanks, Steve. Thank you. Your next question comes from Doug Terreson of ISI. Congratulations to both of you guys on your success, first of all. Thank you, Doug. You're welcome. And then second, my question is on corporate could provide a little clarity on what the new total shareholder return incentives are, which I think you guys call TSRIs and whether they are different from the previous plan and if so in what way are they similar? Well, total shareholder return is rather simple. You take the stock price at the time these awards are put in place and 3 years later, you see how you compare with the 12 companies that are in the peer group, you include dividends in those calculations. Okay. That's how you get at the end looking at whether you're number 1, 2, etcetera. Sure. There's a table in the disclosures, which will show you how it works. But it's basically more the old plan had was done in quartiles essentially. And this plan is done incrementally. So if you were in the if you're the top one in this plan is the only way to get for 3 years out of the 12, it's the only way to get 2 times. So the plan is a lot steeper, and more difficult to achieve than the old one. Okay. Okay. Just wanted to double check. Thanks a lot. Thank you. Your next question comes from Kate Vineyard of JPMorgan. Hi, good morning, gentlemen. Good morning. Just a question regarding your decision not to pursue additional sizable acquisitions in California. Is this just an issue of portfolio balance or have you exhausted the more lucrative acreage options or are prices too lofty or is this a combination of multiple factors? What we said was no more acreage acquisitions not production acquisitions just to make the distinction clear. There really isn't any sizable acreage to acquire. Okay. We're pretty much done. Okay, great. And then just in terms of your CapEx for the Q4, it looks like you'll be spending about $1,600,000,000 How much of that is related to activity in your newly acquired acreage or your newly acquired your asset acquisitions? Very small number. Your asset acquisitions? Very small number. Okay. All right, great. Thanks very much. Your next question comes from Philip Dodge of Tuohy Brothers. Yes, thank you. If I've done the arithmetic correctly, your recent acquisitions, natural gas or did you have to accept some natural gas to get the oil that you wanted? We view all these things as sort of money, not whether it's natural gas or oil. And if you could buy natural in our view, if you could buy natural gas at essentially a discount the present worth based on current prices, we wouldn't view that as an unattractive thing to do. If you got to pay 6 dollars an AM baked into it, we view that as sort of unattractive. So buying gas with the current market discounted, we're basically sort of $4 discounted for present worth. We don't view as an unattractive thing to do. We produce a fair amount of gas. I mean, while we're oily and not a pure oil company and especially in the Permian and there's a lot of opportunities we think in the Permian for gas. We're a big processor of gas in the basin. So yes, you'd prefer to buy oil real cheap, but if we can buy gas cheap, we'll do that too in our operating areas. Other question unrelated, I want to understand the permitting in California. I believe you said that there's more of a delay in permitting on the large prospects than on the small prospects. Is that just chance or is there No, it's not chance. It's where the large ones are located. Which makes it a more complicated process, is that correct? Which makes it longer. It's in an area maybe it hadn't been drilled before. And so it takes a little longer to get the permits. Okay. Thank you. And your next question comes from John Herrlin of Societe Generale. Yes. Hi, Steve. Hi, John. Three questions for you. For the shales that you're producing from your Wildcat program in California, are you fracking them or is that natural flow? No, John. They're all fracture stimulated. Okay. Or acidized, one or the other. Okay. That's fine. Not the don't get confused. It's not we're talking about small fracs jobs, not multi phase fracs. They're traditional You commented that you didn't want to transfer all the cash flow to the services companies at all. And I think with this kind of fracking, we're not transferring the cash to the fracking, we're not transferring the cash to the service company. Okay. That's fine. Regarding the acquisitions market, you guys are generating a lot of free cash. What are you seeing? Obviously, you passed on some integrated packages. Is it still small that you're targeting or you're pretty much open for anything? We're always open for anything if the price is appropriate. Anything within our own scenario. Last one for me. You're carrying about 50% to 100 percent less PUDs than your peers. Do you think you get penalized perhaps for being too conservative with regards to reserve booking? I don't know. We booked the reserves deliberately conservatively because that's what the rules require. And in the end, it all works out. And we don't see where whatever the right politically correct phrase for book cooking would be is a sensible procedure for us. Your next question is from David Heikkinen of Tudor Pickering. Just a follow-up on your unconventional drilling in some of the Monterey Shale in California. I heard comments and understanding that there's a decent amount of water production. How do you handle water disposal and kind of the permitting process for that as you think about ramping activity? And are there any bottlenecks in that system that we ought to think about heading into next year and the year after? Bill will answer that. Yes, David, have a good many of those on the books to be drilled here in 2011. Traditionally permitting has not been a problem, although I think it's fair to say that it has slowed down some. So as you think about a 3 100 barrel a day well, what type of water rates are you actually seeing? Generally, 1,000 to 15 100 barrels a day once the load is recovered and production has stabilized. Okay. That's in Thanks. That's what I need. Your next question comes from Monroe Helm of Barrow Hanley. Just had a quick question. Can you give us a sense for how the cost of the barrels and the acreage you acquired relates to what your traditional finding costs would be in those similar areas? Well, the future finding it'll be very comparable when we're done, maybe a little less than what we've been doing. Okay, thanks. Thanks. At this time, there are no further questions. Are there any closing remarks? Thank you. Well, thank you very much for joining us today. If you have any further questions, feel free to please call us in the evening. Thanks again for joining us. Thank you. This does conclude today's conference call.