Earnings Call: Q2 2012

Jul 26, 2012

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 Second Quarter 2012 Earnings Release 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. I would now like to turn the conference over to Christopher Stavros. Please go ahead sir. Thanks, Christy. Good morning, everyone and welcome to OXIENNELL Petroleum's Q2 2012 earnings conference call. Joining us on the call this morning from Los Angeles are Stephen Chasen, Oxy's President and Chief Executive Officer Jim Leonard, Oxy's Chief Financial Officer Bill Albright, President of Oxy's Oil and Gas Business in the Americas and Sandy Lowe, President of our International Oil and Gas Operations. In just a moment, I'll turn the call over to our CFO, Jim Leonard, who will review our financial and operating results for this year's Q2. Steve Chasen will then follow with comments on our performance, an update on our capital program and production for 2012 and including our outlook for the second half of this year. Our Q2 2012 earnings press release, Investor Relations supplemental schedule, conference call presentation slides which to both Jim's and Steve's remarks can be downloaded off of our website at www.oxi.com. I'll now turn the call over to Jim Leonard. Jim, please go ahead. Thank you, Chris. Net income was $1,300,000,000 or 1 point 6 $4 per diluted share in the Q2 of 2012 compared to $1,800,000,000 or $2.23 per diluted share in the Q2 of 2011 and $1,600,000,000 or $1.92 per diluted share in the Q1 of 2012. All the drop in the 2nd quarter earnings compared to the Q1 of 2012 was attributable to the decline in commodity prices. Worldwide oil oil and domestic gas and NGL prices were significantly lower during the quarter. Here's a segment breakdown for the 2nd quarter. Oil and Gas segment earnings for the Q2 of 2012 were $2,000,000,000 compared with $2,500,000,000 in the Q1 of 2012 and $2,600,000,000 in the Q2 of 2011. In the oil and gas segment, the Q2 2012 daily production was 766,000 barrels, the highest volume in the company's history for the 2nd consecutive quarter and was up 7% from the same period of 2011. Our total domestic production was 462,000 barrels per day, the 7th consecutive domestic quarterly volume record for the company. Our total domestic production was 9% higher than the Q2 of 2011. Latin America volumes were 33,000 barrels per day. Colombia's production of 31,000 barrels a day improved 7,000 barrels a day from the Q1 of 2012 due to significantly lower levels of insurgent activity in the Q2. In the Middle East region, volumes were 271,000 barrels per day. In Oman, the 2nd quarter production was 72,000 barrels per day, 2,000 barrels lower than the 1st quarter volumes. In Qatar, the 2nd quarter production was 74,000 barrels per day, 2,000 barrels higher than the 1st quarter volumes. For Dolphin and Bahrain combined, daily production increased 7,000 barrels from the Q1, which include planned plant shutdowns in Dolphin. The rest of the Middle East, North Africa production decreased by 10,000 barrels per day. Oil prices and production sharing and similar contract factors did not significantly impact this quarter's production volumes compared to quarter or the Q2 of 2011. Our 2nd quarter sales volumes were 759,000 barrels per day, slightly lower than our production volumes due to the timing of liftings in the Middle East and North Africa. 2nd quarter 2012 realized prices were lower for our products compared to the Q1 of the year. Our worldwide crude oil realized price was $99.34 per barrel, a decrease of about 8%. Worldwide NGLs were $42.06 per barrel, a decrease of about 20 percent and domestic natural gas prices were $2.09 per Mcf, a decline of 26%. 2nd quarter 2012 realized prices were also lower than the Q2 2011 prices for all our products. On a year over year basis, price decreases were 4% for the worldwide crude oil, 27% for worldwide NGLs and 51% for domestic natural gas. Realized oil prices for the quarter represented 106% of the average WTI and 91% of the average Brent price. Realized NGL prices were 45 percent of WTI and realized domestic gas prices were 92% of the average NYMEX price. Price changes at current global prices affect our quarterly earnings before income taxes by $38,000,000 for a $1 per barrel change in oil prices and $8,000,000 for a $1 per barrel change in NGL prices. A swing of $0.50 per 1,000,000 BTUs in domestic gas prices affects quarterly pretax earnings by about $35,000,000 These price change sensitivities include the impact of production sharing contract volume changes on income. Oil and Gas Gas cash production costs were $14.50 a barrel for the 1st 6 months of 2012 compared with last year's 12 month cost of $12.84 a barrel. The cost increase reflects higher well maintenance activity in part reflecting our higher well count, higher workover activity and higher support and injection costs. Taxes other than on income, which are directly related to product prices were $2.46 per barrel for the 1st 6 months of 2012 similar to last year's comparable period. 2nd quarter exploration expense was $96,000,000 Chemical segment earnings for the Q2 of 2012 were $194,000,000 compared to $184,000,000 in the Q1 of 2012 $253,000,000 for the Q2 of 2011. The sequential quarterly improvement was due to improved PVC and DCM margins driven primarily by lower ethylene costs. The year over year decrease was the result of lower domestic and export caustic volumes, lower VCM export demand and lower PVC and VCM export prices, partially offset by lower natural gas and ethylene costs. Midstream segment earnings were $77,000,000 for the Q2 of 2012 compared to $131,000,000 in the Q1 of 2012 $187,000,000 in the Q2 of 2011. The decline in earnings was mostly in the marketing and trading businesses and to a lesser degree in the gas plants, reflecting lower NGL prices, partially offset by improvements in the pipeline businesses. The worldwide effective tax rate was 40% for the Q2 of 2012. Our Q2 U. S. And foreign tax rates are included in the Investor Relations supplemental schedules. Cash flow from operations for the 1st 6 months of 2012 was $6,000,000,000 We used $5,100,000,000 of the company's total cash flow to fund capital expenditures and $1,000,000,000 for acquisitions. Financial activities, which included dividends paid, stock buybacks and a $1,750,000,000 borrowing during the quarter provided a net $800,000,000 of cash flow. These and other net cash flows resulted in a $4,400,000,000 cash balance at June 30. Capital expenditures for the 1st 6 months of 2012 were $5,100,000,000 of which $2,700,000,000 was spent in the 2nd quarter. Year to date capital expenditures by segment were 82% in oil and gas, 15% in midstream and the remainder in chemicals. The Alhos and Shaw gas project made up about 11% of the total capital spending for the 1st 6 months of 2012. Our acquisitions for the 1st 6 months of 2012 were $1,000,000,000 mostly consisting of bolt on acquisitions in the Williston Basin, South Texas and the Permian. The weighted average basic shares outstanding for the 1st 6 months of 2012 were 810,400,000 and the weighted average diluted shares outstanding were 811,200,000. Fully diluted shares outstanding at the end of quarter were approximately 810,000,000. Our debt to capitalization ratio was 16%. And at the end of the second quarter, we issued $1,750,000,000 of senior notes at a weighted average interest rate of 2.4%, which brought the company's average effective borrowing rate down to 3%. Copies of the press release announcing our 2nd quarter earnings and the Investor Relations supplemental schedules are available on our website or through the SEC's EDGAR system. I will now turn the call over to Steve Chazen, who will provide guidance for the second half of the year. Thank you, Jim. Occidental's 2nd quarter 2012 production set an all time record for the company for the 2nd consecutive quarter. The domestic oil and gas segment produced record volumes for the 7th consecutive quarter. 2nd quarter domestic production of 462,000 barrel equivalents per day consisted of 322,000 barrels of liquids and 840,000,000 cubic feet of gas per day. This was an increase of 7,000 barrel equivalents per day compared to the Q1 of 2012. About 86% of the domestic production growth of the first quarter of 2012, which was in liquids, which grew from 316,000 barrels a day to 322,000. Compared to the Q2 of 2011, our domestic production grew by 9% or 38,000 barrels a day, of which 25,000 barrels a day was liquids production growth and 79,000,000 cubic feet a day was gas. Our annualized return on equity for the 1st 6 months of 2012 was 15% and our return on capital employed was 13%. For our capital program, we are raising our estimate of the total year capital program to $9,200,000,000 from our previous announced level of $8,300,000,000 Of the increase about $600,000,000 for the Elhos and Shaw gas project, the remainder of the increase going to the rest of the oil and gas segment, primarily to non operated properties where our forecasting ability is limited. Expect our capital spend rate to slow down modestly from the current levels during the back half of the year and stabilize in the 4th quarter. The El Hozan Gas project is approximately 49% complete and is progressing as planned. This project made up about 11% of our capital program for 6 months of this year. Spending continuing at current levels, we are increasing our anticipated spending for the remainder of 2012 as I just mentioned. However, total development capital for the project is expected to be in line with previous estimates. In our domestic operations, we expect our total average rig count at current levels of about 75 to go down to an average of 70 by the end of the year. However, with the mix of rigs, we'll shift among very different regions related to changes in gas and NGL prices. With our production growth wedge firmly in place for the back half of the year, we will focus our efforts on improving our profitability. This includes an increased oil program rather than drilling gas NGL wells. We are releasing and will continue to release underperforming rigs and crews. We will also work on improving our operating costs. These things are well within our ability to achieve. We expect to do more with less money in the rest of the year. California, we continue to see improvement with respect to permitting issues relative to last year. We received approved field level rules and new permits for both injection wells and drilling locations. The regulatory agency continues to be responsive and committed to working through the backlog of permits. Our new Elk Hills gas plant, which went into operation early July, will positively affect our operational efficiency and production in the back half of the year. Turning to production expectations in the back half of the year. Over past year, we have generally achieved our 6,000 to 8,000 barrel a day quarter over quarter domestic production increase. We expect that we will achieve the high end of this range increase throughout the rest of the year, which should give us an entry rate into the New Year of at least 480,000 barrels a day. The increase will be spread among all of the domestic operations. Internationally at current prices, we expect production to increase modestly for the rest of the year depending on spending levels in Iraq. This includes the effect of a drop in production at Dolphin to about 40,000 barrels a day starting in the Q3 resulting from the full cost recovery of the free startup capital over the 1st 5 years of production, which commenced in July 2007. We expect international sales volume in the Q3 of 2012 to be 20 incorporated in the product price sensitivities that Jim provided you. Additionally, we expect exploration expense to be about $85,000,000 for seismic and drilling for exploration program in the Q3. The Chemical segment earnings are expected to be about $175,000,000 Weakness in export demand conditions in Europe and China, slowdown in U. S. Demand and rising U. S. Natural gas costs will keep some pressure on margins. We expect our combined worldwide tax rate in the Q3 of 2012 to increase to about 42%. To summarize, we closed the quarter with our 2nd consecutive all time company production and the 7th consecutive record domestic oil and gas production. We increased our total domestic production by 7,000 barrels a day over the Q1 and by 38,000 barrels a day for the Q2 of 2011. Domestically, where we are the largest onshore liquids produced in Lower forty eight, our production increased by 9% in the Q2 of last year. Our total production increased by 7% in the 2nd quarter on a year over year basis. We are increasing our estimated total year capital program to $9,200,000,000 from our previously announced $8,300,000,000 Of the increase about $600,000,000 is for the Elhos and Shaw Gas project, the remainder of the increase going to the rest of the oil and gas segment. Our business generated cash flow from operations of $6,000,000,000 in the 1st 6 months of 2012. We spent about $5,100,000,000 of our cash flow on our capital program. I think at this point, we're ready to take your your questions. Thank you. And your first question comes from Mariani of RBC. Hey, guys. Just a quick question on your Permian Basin production. It looked like it was down a tiny bit in the Q2. Just wanted to see if there's anything unusual in terms of interruptions or maybe just timing of completions there? Bill can answer that. Bill? Yes. Leo really it's all around gas plants. We had several significant gas plant turnarounds in the quarter as well as some third party gas plant outages. We think most of these turnarounds are behind us for the rest of the year, but it was all attributable strictly to gas plants both third party and company operated. Okay, great. And you guys talked about going from 75 to 70 rigs and really deemphasizing NGLs and gas and adding some crude rigs. Can you just give us a little bit more color in terms of where the rigs are going to be dropped and where you're going to add some on the crude side as you reshuffle? Not really, but we talked about reducing our count in the Williston last quarter and not the Williston last quarter and that's continuing. There's some quite rigs nationally that we have that are less than at the bottom eighth of efficiency. And so we're basically releasing those rigs. We expect that the with a higher concentration of better quality rigs and crews that we'll do better in the quarter. And I expect that we'll drill as many wells in the back half of the year as we did in the first half of the year for the fewer rigs. Okay. So what the shift is we're not quite through shifting yet. Okay. Got you. In terms of acquisitions, you guys talked about doing $1,000,000,000 kind of in the first half of the year. Do you guys still continue to be very active on the acquisition side in the second half? And is there any type of certain area that you guys have focused on at all in there? It looks pretty slow here in the Q3. We don't have very little if anything in the hopper in the Q3. So I don't expect to see much in the Q3. There's a fair bid ask spread I think right now between what we would be willing to pay and what somebody would be willing to accept. So we're not in any hurry. We don't really need to do anything. You shouldn't expect to see any large scale M and A from us. Okay. Thanks guys. Your next question comes from Arjun Murti of Goldman Sachs. Thanks. Steve, you did mention some bolt on acreage acquisitions in the Williston. Can you just talk about where your position is now? I know you dropped some rigs and I think you've been less enthusiastic. But where are you acreage wise now in the Williston? I think we're north of 300,000 acres. And the bolt on I don't know exactly because they never tell me this. That's great. So, give me a bit on California exploration. It's something you highlighted a couple of years ago. I know there's some small stuff and some bigger stuff, but where is that program now? It's actually doing pretty well. We have some moderate successes in some oil and we've got some things that are working. They're a little bit off the mainstream, off the main plan that we had as far as where they're located. And there's still some acreage to be acquired that other people have. So I just don't want to go into details. But I think it's doing pretty well and we're doing we have some nice adds in a few million barrels a year maybe 10,000,000, 12,000,000 barrel adds. That's great. And then just lastly, I know you've started increasing the drilling some of the Permian unconventional stuff. How any comments on how that's going? Well, obviously the gassy NGL stuff, while it may be interesting towards New Mexico and towards New Mexico and people call them liquids rich, I call them gas rich. So they're just not that exciting right now. And but the oil stuff is doing pretty well. And really we're doing just fine. And I think if we there's another area where there's some poor performing rigs and crews that we're going to upgrade the quality of that. So my focus is as I said in the back half of the year, I think the production wedge will be fine maybe even more than fine in the back half of the year, because I think we got a pretty good sized backlog. But I'm really focused cost. That's great. And look forward to seeing you new CSR cost. That's great. And look forward to seeing your new CFO at some point here. Congrats on that. Thank you. Thank you, Arjun. She'll be pleased to hear that. Our next question comes from Doug Terreson of ISI Group. Good morning, Steve. How are you? Hi, Doug. How are you? I'm doing fine. You guys are obviously a leader in the Permian and this Rig Tex pipeline looks likely to debottleneck that area to some extent that is if it were to materialize. So my question is whether or not you could provide us an update on your expectations and any time line that you feel is reasonable for that situation? Yes. I think I'd rather defer that let Magellan talk about it since they're a pipeline company. But should you understand that we could give enough crude to make any pipeline go Right. Out of the basin. Next is maybe even more than one pipeline to go. But not only do we have our work our net production, but we also have the royalty production in 3rd party barrels. And so the plan in the basin is to expand our gathering system, hook it into these pipelines and maybe make 1 or 2 lines that go maybe into whether it goes to the Houston or Corpus and into Houston and put as much of our stuff through there as we can. And again, we're not trying to fix the problem in the basin. We're just trying to fix our problem. I understand. Let me ask you another question. And Abu Dhabi, can you tell us whether or not you guys are still under consideration on the onshore development phase with the SPC? And if not, do you think that you could be brought in at a later date? So No. We're actively involved. Actively involved. Okay, great. Thanks a lot. Thank you. Your next question comes from Doug Leggate of Bank of America. Thanks. Good morning, Steve. Good morning. The gas plant in California, I guess, we've been kind of waiting for this for a while. My understanding is you've also gone ahead and ordered a second gas plant. Can you help us understand that? I think we're in the study phase in the second gas plant. Okay. So the Remember gas isn't such a high commodity right now. Yes. Look, the new gas plant having started up and can you just walk us through how does that help? Because I seem to recall the capacity was fairly significant, but what should we anticipate in terms of a volume response as a result of that? I don't know yet. When we ordered the plant, we thought we would drill more gas wells. And obviously, we're a little ways away from that yet. So you'll get I think maybe 3 effects. The most significant one is an increase in reliability. And so there's a significant loss every quarter due to some something that's blamed on some third party. So we'll have to take the blame ourselves now I guess instead of blaming it on somebody else. 2nd, there's a much deeper cut and so there'll be more NGLs or whatever they're worth coming out of the plant. And finally, there's clearly more capacity. And I'd like to defer the discussion about the capacity response from the rest of the field until we get at least a quarter of actual results rather than just a few weeks. Got it. And my follow-up if I may is also on California. So a few I guess a bunch of quarters ago, you kind of laid out the running room you had there, but the permitting seems to have gotten an awful lot better. I guess what I'm curious on is what is it going to take for you to get after what you have acknowledged are some of the highest IRR opportunities in the portfolio because it seems that with your guidance on rigs, you're not planning to do that anytime soon. I'm waiting for them to reduce their cost per well. I mean it's simply they can make step changes sizable step changes in their cost per well. And my experience over the last however long is giving them more money does not cause that. And so a little diet for a little while will have significant reductions in their cost per well. I'm talking not 10%, not 20%, but a third. And once they get to the point where their well costs are in line with what they ought to achieve then we'll pick up the pace. But if I can reduce the cost, I'll get more wells for the same money. And that's really what I'm after. I'm not after volume per se. I'm actually after money. And right now they can do a lot better and they will. But the only way to do it is to ensure that they feel pressed. Forgive me Steve. You dominate the play. How do you benchmark what's achievable when you're, I guess, competing with yourself? Competing with myself. And I know we can tell what's achievable. We've experimented and we know. So it isn't it's not a theoretical it's not a theoretical discussion. We changed some things and we had step changes in it and this is just the beginning. So they can do better. All right. I'll leave it there. Thanks, Steve. Thanks. Your next question comes from Jason Gammel of Macquarie. Thank you. Steve, I wanted to ask you first of all about your transportation capacity out of the Permian Basin. And really my question is really more around what we've seen as a building differential between Cushing and Midland. And I know that with the pipeline that you acquired a few years back that you should have the ability to avoid any differentials there on at least some volumes. I wanted to see how much you're actually covered on transportation there. And then my second question is really more housekeeping on the acquisitions. Should we look at the $1,000,000,000 of acquisitions year to date as incremental to the new CapEx guidance that you've given? And is there any associated production figure with those acquisitions for the Q2 and then for the rest of the year? Starting with the Midland. There was a small problem that somebody had in Midland early sometime this quarter last quarter and that's really gone away. So I think some of this difference is pretty much gone. So you don't really see that anymore. There was some somebody had a problem there. I can't remember who. The capital, I've included in the capital additional for the back half of the year the additional spending on the acquisitions that came in the first half. And then there was no production effect from the acquisitions in the Q2 because most of them were done late in the quarter. And there might be 1,000 or 2,000 barrels a day all liquids in the Q3. Okay. And just a follow-up on the differential again Steve. It may have been a relatively temporary issue in the 2Q, but does it indicate that you're starting to experience pretty tight infrastructure in the Permian in general, so it could be another issue that crops up periodically over time? Yes. I think that maybe just take a long view the basin was the pipeline system was built for very large amount of oil years ago and was allowed to degrade because and everybody thought it was going to deplete away. And the ownership of the pipelines changed from integrated producers to generally speaking cash flow driven organizations who get paid on increased distributions rather than maintenance. And so what's happened is that the system is not in particularly great shape, which is why we bought the pipeline systems. And we're going to invest some money to improve our results in that. But the system is tight right now and it does not take much to create a modest disruption. And we're in better shape than most people because we control our own destiny largely. But I think this is something not just in the Permian, but everywhere where everybody assumed the United States was going out of business in the oil industry even if you don't buy some of the more ridiculous things that people have put out. As far as growth, a modest amount of growth will tax the system nationwide, because the infrastructure is basically designed currently for as a cash cow rather than something that you need to keep up. Does that answer your question? Yes. That's helpful. Thank you, Steve. Thanks. Our next question comes from Matt Portillo of Tudor, Pickering, Holt. Good morning, guys. Two quick questions for me. Just on the acquisition side for the Q2, could you give us an idea of the $2,700,000,000 what the approximate has been on acquisitions? And then just a quick second question here. In relation to Colombia, obviously, you guys had a nice uptick back to kind of normalized volumes. There seems to have been a continued frequency of pipeline I think our capital I mean, just the acquisition money in the second quarter was like 700,000,000 dollars It was $1,000,000,000 for the back half for the first half of the year. Capital was $2,700,000,000 but the acquisition was I think $700,000,000 or so. Okay, great. That's very helpful. Yes. So it's $1,000,000,000 for the 1st 6 months in acquisitions. I got lost in the rest of the question. So if you could repeat it. Sure. And just in terms of Colombia, you obviously had a nice uptick in production in the Q2, I think as Ken Almon pipelines kind of normalized. Are you guys seeing kind of similar levels of production heading into the Q3? And are there any improvements that you're seeing on the security side down in Colombia? We'll let Bill answer that. Matt, so far in the Q3, we've had about 1,000 barrels a day outage is all. We obviously have had more insurgent activity in the Q3 so far. Who knows what it's going to be like for the rest of the quarter. But so far, there has not been a material effect on production. It's capable producing 32,000, 33,000. So there was some loss even in the 2nd quarter. So all he's really saying is it's sort of like the 2nd quarter. Yes. Thanks guys. Appreciate it. Your next question comes from Elliot Delvonmarty of Capital One Southcoast. Good morning guys. Just a question for you. Do you still see the Williston Basin as a potential longer term resource play for the company? And the reason I ask that is, you obviously get great returns in California and the Permian plays. I'm just trying to understand what kind of scenario would you actually be willing to put your dollars at work in the Williston? And I think you've addressed some of potentially on a well cost front. But what scenario would you envision that even if it is the number 3 play you would invest in, for example, in the U. S, How would you assess that situation as to when you feel good about putting dollars to work there? Definitely number 3. It's really a cost issue. I think that the service companies are getting rich as pigs there. And I think until the costs come down and the efficiency improves, we'll continue to focus on the best wells and the most efficient wells and improving our learning curve. We're still on I think in a learning curve phase, but there's that. And then there's a differential issue, which I think could be fixed over time. But I'm in no hurry to put capital there. We still continue to put capital there, but not to the level that we were. We're still making it's clearly assets for the future rather than a big driver for today. Excellent. Thank you for the color. Sure. Your next question comes from Edward Westlake of Credit Suisse. Hey, good morning. So just a question. You mentioned last quarter when you were looking at the increase in California rig counts sort of 5 rigs every 6 months that some were going into steam flood as well as I guess the shale in comments. Can you give us an update in terms of how many rigs you're in steam flood versus other opportunities? I actually don't know. 3. I think we have 3 rigs in the steam sludge right now. Right. And we'll boost that as the year progresses. So but still incremental rigs going in against your guidance then into the That's right. Okay. Shale and into the steam plus. Yes. And just on this is more of a longer term question, but obviously in the central part of San Joaquin Valley, financial geologist that I am, you have a potentially thicker part of the shale, but it's deep and the rock quality may not be as good. But is there any technology that you think could work there to turn that into sort of a repeatable shale play? Well, it's maybe someday, but right now we try to do easy stuff before hard stuff. And so we're focused on what's easy right now. And what's easiest right now is to drill low cost shale wells in easy places. We've monkeyed with what you've said. And I think we're still in the early phases of thinking about that. Is it fair to say that you're putting some R and D dollars into that type of monkey? Yes. Yes, we do. Right. Okay. Thanks very much. Thank you. Our next question comes from Sven Del Pozo of IHS Harold. Yes. Good afternoon. Hi. Good morning, Harold. How are you doing? Good morning. Your prospective savings on completion costs in California for the for your unconventional wells. What kind of timeframe do you think we'll have we'll start to see some CapEx? It's actually happening now. It's happening now. Okay. So you'll see it as it will be clear as the year progresses. Okay. And same type of question regarding CapEx for the midstream. When do you think we'll start to see the CapEx deployment in the midstream slowdown? Well, a lot of that is Elhos gas plant. And so the domestic capital is not probably not going to slow down for a little while till I get the pipeline system up and running better. But the hose and stuff that part of it should start to roll off into the 4th and first quarters. But the drilling portion the part that's chart goes to E and P will pick up that slack and more into the 4th and Q1 next year. So all you're seeing so I wouldn't be too confused about where this midstream capital is going. A fair amount of it except for a little bit right now is going into the Holozin project. Okay. And your production growth sequentially from the Q1 to the Q2 in the Mid Continent region, which also includes the Bakken. If it's not the Bakken where the production growth is coming from for on the oil side, What regions or yes? It is from there. I mean some of the bulk of it is from there. We started I remember 3000 or 4000 day last year early last year and we're 17 running now. So I mean somewhere in there it's there. There's improvement in South Texas and the rest of the Rockies. But I mean fundamentally that segment is the large increases are Bakken production. Okay. Spike in Bahraini gas production, could you just help me to understand what's going on there? Sandy can probably answer that. Yes. The gas production is paid for on a capacity basis and we've recently installed a lot of equipment that the capacity to what the kingdom thinks they'll need over the next few years. And is there any way to quantify the profitability change associated with this increase in gas production? Pretty modest. I mean the profits there will be made off the oil production and the gas serves as a sort of a base to give us a base return I think is the way to think about the project. So the gas since it's sort of a captive gas market is basically what pays for the thing. Then the upside, the higher returns will come from proved oil prices or oil production. Okay. And lastly, view on chemicals just you announced for sometime after 2015 announcement of 1,100,000,000 pound ethylene cracker. I don't know if it's an expansion or a brand new plant. There's no I think the announcement is that we're studying it. We're not committed to the cracker. We are going to build a fractionator, but not but we're not committed to a cracker. Okay. And for working capital component of your cash flow in the first 6 months of the year that would if you'd like to e mail it to me later that's fine. If you have it right there that's great. Chris can deal with that. I don't think you'll find it a big deal. Okay. Thank you very much. Thank you. Our next question comes from Katherine Vineyard of JPMorgan. Hi, gentlemen. Thanks for taking my question. Just looking at 2Q2012 production for the U. S, how much of that It's probably a more complicated question than you probably thought. I don't think we you have to go basin by basin. I don't we don't know. We'll try to have why don't you contact Chris and maybe we can reconstruct that over the next yes, we don't have it with us. Okay. All right. And then when you talk about cost reduction of about a third in your drilling. Are you looking at California we talked about. Right. So are you looking at achieving that? Is it lower drill times? Is it different completion techniques? I mean, what would be the main factors driving the bulk of that type of reduction? Bill can answer that because he's responsible. Catherine, it's really both, okay? On the drilling side, it's a lot of little things that add up to cost reductions. And then on the completion side, it's primarily reductions in pressure pumping costs. Okay. All right. Great. Thanks a lot, gentlemen. Your next question comes from Alex Morris of Raymond James. Hey, thanks for taking my question. Following up on the Colombia insurgency question from earlier. Could you give an update maybe on Libya and whether production is back at pre war levels there? And I guess if not what needs to happen to get there? Andy can answer that. Yes. We're just about at prewar levels right now. We've just putting new teams into the country to work on new projects and we will be doing seismic work later this year. So we're pretty much back to normal in Libya. Thanks. Your next question comes from John Herrlin of Societe Generale. Yes. Hi, it's Steve. Hi. Are you seeing any discounts to price booked by the services companies in the Permian? Some of your peers have been mentioning that. Are you seeing that at all? Bill can answer that. Yes. John, yes, we're seeing some modest price reduction off of the price book. What's that 10% or less? It's 7% to 10%. Okay. Yes. We tend to contract longer term than somebody else who might go to monthly contracts. Okay. Yes. And so we don't we're not quite as sensitive to the somebody who might be drilling 6 wells or something. Okay. That's fine Steve. With the Elk Hills plant, is there just a commissioning startup phase before you get it fully on? It's gone through that. Okay. And so we're like all plants that are designed by engineers, They always they never seem to work just exactly right the first day. So but we've actually gone through that because we started the process more than a month ago. So right now, I think we're okay. Okay. And then I probably missed this because I got on late. What was your cash position at quarter's end? A little over $4,000,000,000 Okay. Thank you very much. Thank you. Thank you. I will now turn the floor back over to Mr. Stavros for any closing remarks. Thanks very much for joining us today. And if you have further questions on the conference call or earnings release today, please call us in New York. Thanks very much.