Occidental Petroleum Corporation (OXY) Q2 2012 Earnings Report, Transcript and Summary

Christopher G. Stavros - Treasurer and Vice President of Investor Relations James M. Lienert - Chief Financial Officer and Executive Vice President Stephen I. Chazen - Chief Executive Officer, President and Director William E. Albrecht - President Edward Arthur Lowe - Vice President and President of Oxy Oil and Gas -International Production

Leo P. Mariani - RBC Capital Markets, LLC, Research Division Arjun N. Murti - Goldman Sachs Group Inc., Research Division Douglas Terreson - ISI Group Inc., Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Jason Gammel - Macquarie Research Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Eliot Javanmardi - Capital One Southcoast, Inc., Research Division Edward Westlake - Crédit Suisse AG, Research Division Sven Del Pozzo - IHS Herold, Inc Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division John P. Herrlin - Societe Generale Cross Asset Research

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's Second Quarter 2012 Earnings Release Conference Call. [Operator Instructions] I would now like to turn the conference over to Christopher Stavros. Please go ahead, sir.

Thanks, Christie. Good morning, everyone, and welcome to Occidental Petroleum's Second Quarter 2012 Earnings Conference Call. Joining us on the call this morning from Los Angeles are Stephen Chazen, Oxy's President and Chief Executive Officer; Jim Lienert, Oxy's Chief Financial Officer; Bill Albrecht, 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 Lienert, who will review our financial and operating results for this year's second quarter. Steve Chazen will then follow with comments on our performance and update on our capital program and production for 2012 and including our outlook for the second half of this year. Our second quarter 2012 earnings press release, investor relations supplemental schedules, conference call presentation slides, which refer to both Jim's and Steve's remarks, can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Jim Lienert. Jim, please go ahead.

Thank you, Chris. Net income was $1.3 billion or $1.64 per diluted share in the second quarter of 2012 compared to $1.8 billion or $2.23 per diluted share in the second quarter of 2011 and $1.6 billion or $1.92 per diluted share in the first quarter of 2012. All the drop in the second quarter earnings compared to the first quarter of 2012 was attributable to the decline in commodity prices. Worldwide oil and domestic gas and NGL prices were significantly lower during the quarter. Here's a segment breakdown for the second quarter. Oil and gas segment earnings for the second quarter of 2012 were $2 billion compared with $2.5 billion in the first quarter of 2012 and $2.6 billion in the second quarter of 2011. In the oil and gas segment, the second quarter 2012 daily production was 766,000 barrels, the highest volume in the company's history for the second consecutive quarter and was up 7% from the same period of 2011. Our total domestic production was 462,000 barrels per day, the seventh consecutive domestic quarterly volume record for the company. Our total domestic production was 9% higher than the second quarter 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 first quarter of 2012 due to significantly lower levels of insurgent activity in the second quarter. In the Middle East region, volumes were 271,000 barrels per day. In Oman, the second quarter production was 72,000 barrels per day, 2,000 barrels lower than the first quarter volumes. In Qatar, the second quarter production was 74,000 barrels per day, 2,000 barrels higher than the first quarter volumes. For Dolphin and Bahrain combined, daily production increased 7,000 barrels from the first quarter, which included 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 the previous quarter or the second quarter of 2011. Our second 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/North Africa. Second quarter 2012 realized prices were lower for our products compared to the first quarter 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%. And domestic natural gas prices were $2.09 per MCF, a decline of 26%. Second quarter 2012 realized prices were also lower than the second quarter 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% 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 million for $1 per barrel change in oil prices and $8 million for $1 per barrel change in NGL prices. A swing of $0.50 per million BTUs in domestic gas prices affects quarterly pretax earnings by about $35 million. These price change sensitivities include the impact of production sharing contract volume changes on income. Oil and gas cash production costs were $14.50 a barrel for the first 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 work overactivity 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 first 6 months of 2012, similar to last year's comparable period. Second quarter exploration expense was $96 million. Chemical segment earnings for the second quarter of 2012 were $194 million compared to $184 million in the first quarter of 2012 and $253 million for the second quarter of 2011. The sequential quarterly improvement was due to improved PVC and VCM margins, driven primarily by lower ethylene cost. 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 million for the second quarter of 2012 compared to $131 million in the first quarter of 2012 and $187 million in the second quarter 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 second quarter of 2012. Our second quarter U.S. and foreign tax rates are included in the Investor Relations supplemental schedules. Cash flow from operations for the first 6 months of 2012 was $6 billion. We used $5.1 billion of the company's total cash flow to fund capital expenditures and $1 billion for acquisitions. Financial activities, which included dividends paid, stock buybacks and $1.75 billion borrowing during the quarter provided a net $800 million of cash flow. These and other net cash flows resulted in a $4.4 billion cash balance at June 30. Capital expenditures for the first 6 months of 2012 were $5.1 billion, of which $2.7 billion was spent in the second quarter. Year-to-date capital expenditures by segment were 82% in oil and gas, 15% in midstream and the remainder in chemicals. The Al Hosn Shah gas project made up about 11% of the total capital spending for the first 6 months of 2012. Our acquisitions for the first 6 months of 2012 were $1 billion, mostly consisting of bolt-on acquisitions in the Williston Basin, South Texas and the Permian. The weighted average basic shares outstanding for the first 6 months of 2012 were 810.4 million and the weighted average diluted shares outstanding were 811.2 million. Fully diluted shares outstanding at the end of the quarter were approximately 810 million. Our debt-to-capitalization ratio was 16%. And at the end of the second quarter, we issued $1.75 billion 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 second 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 second quarter 2012 production set an all-time record for the company for the second consecutive quarter. The domestic oil and gas segment produced record volumes for the seventh consecutive quarter. Second quarter domestic production of 462,000 barrel equivalents per day consisted of 322,000 barrels of liquids and 840 million cubic feet of gas per day. This was an increase of 7,000 barrel equivalents per day compared to the first quarter of 2012. About 86% of the domestic production growth of the first quarter of 2012, which was in -- was in liquids, which grew from 316,000 barrels a day to 322,000. Compared to the second quarter 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 million cubic feet a day was gas. Our annualized return on equity for the first 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 $9.2 billion from our previously announced level of $8.3 billion. Of the increase, about $600 million is for the Al Hosn Shah 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. We expect our capital spend rate to slow down modestly from the current levels during the back half of the year and stabilize in the fourth quarter. The Al Hosn 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. With 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 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 we'll 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're continuing 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. The 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 the 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 third quarter, resulting from the full cost recovery of the pre-startup capital over the first 5 years of production, which commenced in July 2007. We expect international sales volume in the third quarter of 2012 to be similar to the second quarter. A $5 change in global oil prices would impact our daily volumes by about 3,000 barrels a day. Financial impact of this volume change is incorporated in the product price sensitivities that Jim provided you. Additionally, we expect exploration expense to be about $85 million from seismic and drilling for exploration programs in the third quarter. Chemical segment earnings are expected to be about $175 million. 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 third quarter of 2012 to increase to about 42%. To summarize, we closed the quarter with our second consecutive all-time company production and seventh consecutive record domestic oil and gas production. We increased our total domestic production by 7,000 barrels a day over the first quarter and by 38,000 barrels a day for the second quarter of 2011. Domestically, where we are the largest onshore liquids producer in lower 48, our production increased by 9% the second quarter of last year. Our total production increased by 7% in the second quarter on a year-over-year basis. We are increasing our estimate of the total year capital program to $9.2 billion from our previously announced $8.3 billion. Of the increase, about $600 million is for the Al Hosn Shah 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 billion in the first 6 months of 2012. We spent about $5.1 billion of our cash flow on our capital program. I think at this point, we're ready to take your questions.

[Operator Instructions] And your first question comes from Leo Mariani of RBC.

Just quick question on your Permian basin production it looked like it was down a tiny bit in the second quarter. 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 de-emphasizing 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 that's continuing. There are some quite rigs nationally that we have that are less than -- at the bottom 1/8 of efficiency. And so we're basically releasing those rigs. We expect that with the higher concentration and 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 -- with the fewer rigs. What the shift is -- we're not quite through shifting yet.

Okay, got you. In terms of acquisitions, you guys talked about doing $1 billion kind of in the first 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 are focused on at all from there?

It looks pretty slow here in the third quarter. We're going to have very little, if anything, in the hopper in the third quarter. So I don't expect to see much in the third quarter. 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&A from us.

Your next question comes from Arjun Murti of Goldman Sachs.

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 stuff.

That's great. So give me a bit in California exploration. There'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 and 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. 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 and a few million barrels a year, maybe 10 million, 12 million barrel adds.

That's great. And then just lastly, I know you started increasing the drilling of 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 at some point, not real exciting right now. And a lot of these plays are 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 are doing just fine. And I can't complete -- there is another area where are there's some poor-performing rigs and crews that we're going to upgrade the quality of that. So my focus, 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. So I think we've got a pretty good sized backlog. But I'm really focused on improving the efficiency of the rigs and generating -- lowering the operating cost.

Your next question comes from Doug Terreson of ISI Group.

You guys are obviously later in the Permian and this BridgeTex 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 timeline that you feel is reasonable for that situation?

I think I'd rather defer that and let talk Magellan about it since they're a pipeline company but you should understand that we could give enough crude to make any pipeline go 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 and third-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 into Houston or Corpus and then into Houston. And put as much of our stuff through there as we can. And 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. In 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 are actively involved.

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

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 what...

I think we're in the study phase of the second gas line. Remember gas isn't such a high commodity right now.

Yes. The new gas plant that you started at Dolphin, 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 volume response as a result of that?

Yes. 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 is 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. Second, there's a much deeper cut and so there'll be more NGLs, for 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 I guess a bunch of quarters ago, you kind of laid out the run-ins that 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 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.

Yes. I'm waiting for them to further 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 our cost per well. I'm talking not 10%, not 20%, but 1/3. 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 and 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 discussion. We changed some things and we had step changes and this is just the beginning. So they can do better.

Your next question comes from Jason Gammel of Macquarie.

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 with the pipeline that you acquired a few years back, that you should have the ability to avoid any block in differentials there on at least some volumes. I wanted to see how much you are actually covered on transportation there. And then my second question is really more housekeeping on the acquisitions. Should we look at the $1 billion 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 second quarter 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 the differences is pretty much gone. So you don't really see that anymore. There was -- somebody had a problem there, I can't remember who. The capital, I've included in the capital additionals 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 second quarter because most of them were done late in the quarter. And there might be 1,000 or 2,000 barrels a day of liquids in the third quarter.

Okay. And just a follow-up on the differential again, Stephen. It may be or not relatively a 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 -- let me just take a long view of the basin -- the pipeline system was built for a very large amount of oil years ago and was allowed to degrade because everybody thought it was going to deplete away. And the ownership for the pipeline has 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, 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?

Your next question comes from Matt Portillo of Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Two quick questions for me. Just on the acquisition side for the second quarter, could give us an idea, of the $2.7 billion, what approximately is spent 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 -- just the acquisition money in the second quarter is like $700 million. It was $1 billion for the back half -- for the first half of the year. Capital was $2.7 billion, but the acquisition was, I think, $700 million or so. Yes, so it was $1 billion for the first 6 months in acquisitions. I got lost in the rest of the question, so if you could repeat it. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Sure. And just in terms of Colombia, you obviously had a nice uptick in production in the second quarter, I think, as Caño Limón pipelines kind of normalized. Are you guys are seeing kind of similar levels of production heading into the third quarter? And are there any improvements that you're seeing on the security side down in Colombia?

We'll let Bill answer that.

Yes, Matt. So far in the third quarter, we've had about 1,000 barrels a day outage is all. We obviously have had more insurgent activity in the third quarter 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 of producing 32,000, 33,000. So there was some loss even in the second quarter. So all he's really saying is it's sort of like the second quarter.

Yes.

Your next question comes from Eliot Javanmardi of Capital One Southcoast.

Just a quick question for you. Do you still see the Williston Basin as a potential longer-term resource play for the company? And the reason I asked that is, you obviously get great returns in California in the Permian plays. I'm just trying to understand what kind of scenario would you actually be willing to put to your dollars at work into Williston? And I think you've addressed some of it potentially on the well cost front. But what scenario would you envision that even if it is the #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 #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, I think, in the learning curve phase. But there's that and then there's the differential issue, which I think could be fixed over time. But I'm in no hurry to put capital there. We're still continuing to put capital there, but not to the level that we were. We're still making 16,000, 17,000 a day there. But it's clearly assets for the future rather than a big driver for today.

Your next question comes from Edward Westlake of Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: 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's some were going into steam flood, as well as the shale and vertical elements [ph]. 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 floods right now, and we'll boost that as the year progresses. Edward Westlake - Crédit Suisse AG, Research Division: So that's still incremental rigs going in against your guidance then into the shale?

Yes, shale and into the steam floods. Edward Westlake - Crédit Suisse AG, Research Division: 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 thickest -- thicker part of the shale but its deep and the rock quality may not be as good. But is there any technology that you think could work that, turn that into sort of a repeatable shale play?

Well, maybe someday. But right -- 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 just said and I think we're still on the early phases of thinking about that. Edward Westlake - Crédit Suisse AG, Research Division: Is it fair to say that you're putting some R&D dollars into that type of monkey guess?

Yes, we do.

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

Your perspective savings on completion costs in California for the -- for your unconventional wells, what kind of time frame do you think we'll have -- we'll start to see some CapEx?

It's actually happening now. It's happening now. 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 the Al Hosn gas plant. And so the domestic capital is not probably going to slow down for a little while until I get the pipeline system up and running better. But the Al Hosn stuff, that part of it should start to roll off into the fourth and first quarters. But the drilling portion, the part that is charged, that goes to E&P, will pick up that slack and more into the fourth and first quarter next year. So all you're seeing is -- 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 Al Hosn project.

Okay. And your production growth sequentially from the first quarter to the second quarter in the Midcontinent region, which also includes the Bakken, if it's not the Bakken where the production growth is coming from on the oil side, what regions or...

It is from there. I mean, some of -- the bulk of it is from there. We started, if I remember, 3,000 or 4,000 a day last year, early last year. And we're 17,000 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 Bahrain 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 increases 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 our captive gas market, is basically what pays for the thing. And then the upside of the higher returns will come from crude oil prices, oil production.

Okay, okay. And lastly, view on chemicals, just your announced -- sometime after 2015, announcement of 1.1 billion pound ethylene cracker. I don't know if it's an expansion or a brand-new plant.

No, there's no. I think the announcement is that we are studying it. We are not committed to the cracker. We are going to build a fractionator, but not -- we are 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 be -- if you'd like to e-mail it to me later, that's fine. If you have it right now, great.

Chris can deal with that. I don't think you'll find it a big deal.

Our next question comes from Katherine Minyard of JPMorgan. Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division: Just looking at 2Q 2012 production for the U.S. How much of that production came from wells that were brought online since the beginning of the year?

It's probably a more complicated question 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. Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division: Okay, all right. And then when you talk about cost reduction of about 1/3 in your drilling, are you looking at you...

California, we've talked about. Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division: Right. And so are you looking at achieving that? Is it lower drill times? Is it different completion techniques? And what would be the main factors driving the bulk of that type of reduction?

Bill can answer that because he's responsible.

Katherine, 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, its primarily reductions and pressure pumping costs.

[Operator Instructions] Your next question comes from Alec Morris [ph] of Raymond James.

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?

Sandy can answer that.

Yes. We're just at about pre-war 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.

Your next question comes from John Herrlin of Societe Generale.

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?

Its 7% to 10%.

We tend to contract longer term than somebody else who might go to monthly contracts. Yes, and so we don't -- we're not quite as sensitive to the -- somebody might be drilling 6 wells or something.

Okay, that's fine, Steve. With the Elk Hills plant, is there just a commissioning start-up phase before you get it fully on?

It's gone through that. 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 billion.

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.

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