Earnings Call: Q2 2010

Jul 27, 2010

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 2010 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. Mr. Stavros, you may begin your conference. Thanks, Christy, and good morning, everyone. Welcome to Occidental Petroleum's Q2 2010 earnings conference call. Joining us on the call this morning from Los Angeles are Doctor. Ray Irani, Oxy's Chairman and CEO Steve Chasen, our President and CFO Bill Albright, President of Occidental's U. S. Oil and Gas Operations and Sandy Lowe, Lowe, President of our International Oil and Gas Business. Our 2nd quarter earnings press release, Investor Relations supplemental schedules and the conference call presentation slides, which refer to Steve Jason's commentary, can be downloaded off of our Web site at www.oxy.com. I'm now going to turn the call over to Steve, who will review our Q2 and first half twenty ten financial and operating results. Steve, please go ahead. Thank you, Chris. Net income was $1,100,000,000 or $1.31 per diluted share in the Q2 of 2010 compared to 6 $82,000,000 or $0.84 per diluted share in the Q2 of last year. Here's a segment breakdown for the 2nd quarter. Oil and Gas 2nd quarter 20 ten segment earnings were $1,900,000,000 compared to $1,100,000,000 for the Q2 of 2,009. Improvement in 2010 was driven mostly by higher commodity prices with additional contributions from higher volumes. Realized crude oil prices increased 36% in 20 10 and domestic natural gas prices improved 46% in the Q2 of 2019. Partially offsetting these gains were higher DD and A rates and higher operating expenses, partly resulting from fully expensing CO2 costs in 2010. Worldwide oil and gas production for the Q2 of 20 10 was 743,000 barrels of oil equivalent per day, an increase of 3.5% compared to 717,000 BOE a day in the Q2 of last year. Q2 of 2010 production was lower than our guidance due primarily to shortfalls in California and adjustments resulting from the mechanics production sharing contracts in the Middle East. Our production in California continues to be affected by the gas plants and related infrastructure's inability to process all the gas that could be produced. Also this affects the liquids that are associated with this production. Year over year production was negatively impacted by 29,000 BOE a day in the Middle East, North Africa, Long Beach and Colombia as a result of higher oil price affecting our production sharing and similar contracts. 2nd quarter 2010 production includes volumes in Bahrain of 3,000 barrels of oil and 161,000,000 cubic feet of gas and 16,000 BOE a day higher volumes were high in the field of Oman. Our domestic operations added 11,000 BOE. Volume gains in the Kerncon discovery area were moderated by production declines in Elk Hills, which was caused by gas gathering and processing issues. Exploration expense was $73,000,000 in the quarter. Oil and gas and property taxes were $9.90 a barrel for the 1st 6 months of 20 10. 2nd quarter Last year's 12 month costs were $9.37 per barrel. The increase reflects $0.30 a barrel higher CO2 costs due to our decision to expense a 100% of injected CO2 beginning in 2010 and somewhat higher field support operations and maintenance costs. Taxes other than income were $1.80 a barrel for the 1st 6 months of 2010 compared to $1.60 per barrel for all of 2,009. These costs are sensitive to product prices reflect the effect of the higher crude and gas prices this year. Chemical segment earnings for Q2 of 2010 were $108,000,000 2nd quarter results reflect improvement from the Q1 in 2019 in margins and volumes across most product lines. Midstream segment earnings for the Q2 of 2010 were $13,000,000 compared to $63,000,000 last year. The decrease in earnings was mainly due to a pre tax 100 and $1,000,000 $0.07 per share after taxes. Boot loss at Fibro, the bulk of which results from marking its quarter and open positions to market. This was partially offset by higher margins in the marketing gas processing and pipeline business. The worldwide effective tax rate was 43% for the Q2 of 2010. Now let us turn briefly to our first 6 months results. The net income was $2,100,000,000 or $2.61 per diluted share for the 1st 6 months of 2010 compared to 1 $100,000,000 or $1.29 per diluted share for the 1st 6 months of 2,009. Capital spending for the Q2 of 2010 was about $865,000,000 $1,700,000,000 for the 1st 6 months. The year to date capital expenditures were segment by segment were estimated to be about $4,500,000,000 The capital spending estimated to be about $4,500,000,000 The capital spending rate will increase in the second half of the year largely from Iraq, Bahrain and California. Cash flow from operations for the 6 months 1st 6 months of 2010 was $4,300,000,000 We used $1,700,000,000 of the company's cash flow to fund capital expenditures, dollars 460,000,000 on acquisitions, and three $100,000,000 on foreign contracts. These investing cash flow uses amounted to $2,500,000,000 We also used $540,000,000 to pay dividends and $300,000,000 to retire debt. These cash flows increased our $1,200,000,000 cash balance at the end of last year by $1,100,000,000 to $2,300,000,000 at June 30. The 1st 6 months free cash flow after capital spending and dividends, but before acquisition activity and debt retirements about $2,100,000,000 The weighted average basic shares outstanding for the 6 months of 2010 were 812,300,000 and weighted average diluted shares outstanding was 813,700,000. Our debt to capitalization ratio was 8 percent at the end of the 2nd quarter. As we look ahead to the current quarter, we expect oil and gas production sales volumes to be in the range of 750 Boe to 760 Boe a day at about current oil prices. Volume increases in the 3rd quarter are expected to come from California, Omaha's, the Hygiene field and Dolphin. With regard to prices of current market prices, dollars 1 per barrel change in oil prices impacts oil and gas earnings before income taxes by about $37,000,000 The average second quarter WTI oil price was $78.03 per barrel. A swing of $0.50 per 1,000,000 BTUs in domestic gas prices had a $30,000,000 impact on quarterly earnings before income taxes. The current NYMEX gas price is around $4 an Mcf $4.80 an Mcf. Additionally, we expect exploration expense to be about $90,000,000 for seismic and drilling for exploration programs. For the Chemical segment, modest volume and margin improvement is expected over 2nd quarter levels for chlor alkali and vinyl products. The Chemical segment is expected to provide earnings for the Q3 of about $125,000,000 While the domestic market continues to be lackluster, export volumes are up about 13% compared to 2,009. Chlorine exports are averaging about 42% of total production. We have successfully renegotiated and extended our hydro concessions in Santa Cruz province of Argentina, increasing our oil and gas reserves from 129,000,000 barrels to 202,000,000 barrels. The current quarter DD and A expense reflects the resulting decrease in the DD and A rate. We have recently A rate. We have recently negotiated a number of asset acquisitions in the oil and gas business that in aggregate would be about $1,500,000,000 We expect these acquisitions are mainly from private individuals, largely in the gassier parts of the Permian Basin where there have been several much more expensive deals recently announced. When the acquisitions are concluded, they will add to production mostly in the Mid Continent business unit, which include these parts of the Permian Basin. Virtually all the improvement in the production rate will be in subsequent years. We expect our combined worldwide tax rate in the Q3 to be about 42%. Our 2nd quarter U. S. And foreign tax rates are included in our supplemental schedules. During the first half of the year, we drilled 6 conventional exploration extension wells in California. Of these, 5 were outside of the Kern County discovery area. 2 of these new areas are currently being tested. In the second half of the year, we are planning to drill 2 conventional exploration wells to Kern County discovery area and 1 exploration well outside this area. We also drilled 7 unconventional exploration wells in the first half of the year, of which 2 were successful and 2 are being tested. We plan to drill 15 additional unconventional exploration wells in the second half. In addition, we have drilled 10 conventional exploitation wells in the Kern County discovery area in the first half of the year and plan to drill 23 more in the second half. We've also drilled 10 unconventional exploitation wells in California in the first half with 25 more expected to be drilled in the second half of the year. The skid mounted gas processing plant came online at the end of the second quarter. The existing main processing plant and related infrastructure continue to have operating issues, which are constraining Elk Hill's production. We are in the process of upgrading the infrastructure to alleviate these issues until the new gas plant comes online. We believe these upgrades will be in place by the end of the Q3. Construction of the new gas plant has started and is expected to come online in early 2012. Copies of the press release announcing our earnings and the supplemental schedules are available on our website at www.opsi. Com or through the SEC's EDGAR system. We're now ready to take your questions. And your first question comes from Doug Leggate of Bank of America. Thanks. Good morning, Steve. Good morning, everybody. Good morning. I'm going to try a couple, Steve. I don't want to hog the line here, but FEBRO appears to have been really attending for the bulk of at least the miss compared to what the Street was expecting. For a company which is generally quite conservative and having that kind of volatility in your earnings, can you speak to what is the danger of us overreacting to this versus what is your intentions in terms of perhaps trying to manage that risk a little tighter? And I have a follow-up please. Yes. We've reduced the amount of their exposure and reduce the bar, if you will, in hopes of reducing the volatility. Some of it was he buys long term contracts and some of it simply was mark to market, but some of it was realized to you can't say that this trading results in the quarter were anything but lousy. Okay. I appreciate that. The other one I have is it really relates to acquisitions. You've talked about $1,500,000,000 Just to be clear, I assume that means there's no current production with these assets. No, I didn't say that. No. So what is the production associated with those assets? We haven't said because we haven't signed it, completed the deals, but there's some current production of fairly compared to the whole business, not a sizable amount. But certainly in the Permian, a fair size amount. Okay. Well, I guess what I was driving at here was we're starting to hear about Occidental perhaps getting involved in structured acquisitions over time in places like the Marcellus and perhaps the Montney shales. Could you maybe offer us some color as to what your thought process there and the likely scale and maybe timing of us seeing something you getting involved in those areas? We have a modest position in the Marcellus, which we've had for a while. And compared to the size of the enterprise, fairly small. And it's out of the way some and we're basically on the edges of the play. And we'll just see how it evolves over time, but compared to the size of the enterprise, fairly small total, I would expect. We'll see how the drilling progresses over the next year or so there to see if what we want to do. Steve, forgive me. I'm going to risk one very last quick one. Sure. CapEx was a bit light. I'm just curious as to how that into volumes as it relates to cost recovery, because I'm wondering if that's one of the reasons your guidance was a little some of the adjustments in the production sharing contracts result of not quite spending it quite as quickly and therefore putting into cost recovery as quick and that's at least some of it. The bulk of it was that they really get at not talking about foreign, didn't get at the drilling in the Q2 at the pace that we had planned. And so it's a little more back end loaded, so because the wells come on pretty quickly. So I see some of it was related to production sharing contract capital effects and some of it was related to domestically not getting the drilling done as quickly as one might have hoped. There is nothing terminal in here that you're concerned about? I'm always concerned. You shouldn't view that we're not concerned, but I think ultimately as the work itself also matter of timing and I think a little more focus on the short term results are needed. Got it. Thanks, Steve. I'll leave it there. Our next question comes from David Heikkinen of Tudor, Pickering, Holt. Good morning, Steve. As I think about your Analyst Day and providing the primary and secondary opportunity in the Permian versus these acquisitions, can you talk about how will you update the number of locations and kind of that inventory? Or will you give us some idea of what do you think about the inventory of what you're buying given that you haven't closed any of those deals? Yes. We'll provide aggregate numbers in the next after the things are closed. And I can talk about each acquisition because these are private individuals and these aren't public companies selling or something like that. These are private individuals who just may not want their neighbors to know they're rich. So I think we'll provide aggregate numbers rather than what each one did. But the mix is if you look at them in aggregate and compare to some of the announced deals, these are more reasonably priced. And the comment of in the gassier parts of the Permian, does that also imply kind of more liquids rich or? They look like the deals that have been announced recently in the mix of around half gas, around a quarter NGLs, which are related to the gas and around a quarter of oil. That's useful. And then shifting over to California exploration and kind of the combination of conventional and unconventional tests. As you think about, remember some horizontal drilling plans and some testing of horizontals in the conventional side, can you give us any update on that activity? Bill, do you want to do that? David, we have 2 horizontals planned in and around the Kern County discovery area, have those planned to be drilled and down before the end of the year, testing some of the tighter parts of that particular structure. Okay. So those are still towards the back half of the year? They are. And then as you think about the five drills outside of the discovery area, you kind of broke down the types of prospects that you're drilling at your Analyst Day. Can you talk about that distribution of or categorize those 5 within the buckets that you described at your Analyst Day of what types of prospects those are? I think I broke them down between conventional and unconventional. Yes, meaning more specifically kind of getting into the details of how you had the larger concepts down to the smaller concepts. Well, concepts always start large, just sometimes they turn out small. Okay, fair enough. Not going to get the high potential versus discovery type? No. These are we're shooting for the high potential ones, but sometimes sometimes when you drill them, they turn out to be a lot smaller. So the plan is that they're high potential, but how they turn out, we'll see as the year progresses. If we find something sizable, we'll tell you about it. And then just back of the envelope on your acquisitions, a 10% adder to your Permian Basin production in the acquisition size, is that a reasonable type plus or minus a couple percentage? If you give us 2 or 3 years, yes. But buying production, upfront production is generally the most expensive way to acquire because it's sort of easy to but we also try to buy drilling potential, because the returns are a lot better. But we also try to buy drilling potential because the returns are a lot better. If you pay 10 times current EBITDA for something the way some people have, it's very hard to make the numbers work. The returns have to come from the development drilling or whatever you want. So the assets here are a mix of some current production, but a fairly sizable backlog of future drilling, which will add to the numbers. Thanks for the perspective. Next from Robert Kessler of Simmons and Company. Good morning, Steve. Good morning. Any chance I could ask you for given the volatility in fibro earnings this quarter, I could ask you for the net book value at quarter end and confirm that it's essentially a long only book? It's essentially a long only book. As far as he didn't short anything. But he had some initially in the beginning of the second quarter, he had some he used some a basket of stocks and ETF or something like that to track oil prices. And for obvious reasons, the stocks didn't track the oil prices too well for the stocks that were in the ETF, kind of accident somewhere. And so he sort of backed out of that. But the book is our net investments somewhere under $200,000,000 at this point. Okay. That helps. He the management there owns a tracking instrument in this. So relative to his net worth, even though it's sizable, he's feeling the pain disproportionately. All right. Okay. Well that thanks for giving some order of magnitude on that exposure then going forward. In California at the risk of sort of splitting hairs quarter to quarter when you're in the midst of working out some kinks on midstream and adding the capacity, any guidance on the degree of uplift in California outlook and California production in 3Q versus 2Q? We're We expect We're expecting some of the kinks are already sort of worked out as we go into this month. But I'm willing to predict an exact number because the old gas plant, it will work real good for a couple of hours and then it won't work so good. So and we've had a lot of problem getting it to work the way we would like it to. So maybe excusing the unexpected hiccups in the old plant, the new Skid Mountain plant you expect to ramp up to full capacity fairly quickly or has it already? It's essentially there now. Okay. Thank you very much. Next question comes from Arjun Murti of Goldman Sachs. Hey, Steve. Just a follow-up on some of the language on the conventional California exploration. Of the, I guess, Kern County discovery, which 2 are testing. Just to be clear, those are I realize they're outside of the Kern County discovery area, but they completely different sort of objectives and targets? Yes. Okay. And then the 2 that you'll be drilling in the second half within the discovery area, those are also separate prospects or they could be part of the existing discovery? Well, we hope they're an extension, but they could be separate. It looks like they're separate. But one can hope that it just makes the whole I think they're you could call them either exploration or exploitation depending on your choice of words. Great. And any update on how some of the oilier drilling within the Kern County discovery area has been going? Bill? Yes. Arjun, it's going just fine. We're continuing to drill bread and butter oil wells in the discovery area. These are generally shallower shales and those wells are anywhere 200 to 300 barrel a day kind of wells on average. That's terrific. If I missed in your remarks, I can read the transcript, but any comments on Columbia production, which has been trending down here a little bit? Some of it's a production sharing contract. We put a new we had a new deal starting this year, so some of it's production sharing contract. But some of it is the Canyon Limon field, which is in probably its last decade or so. Yes. Okay. And then just lastly, any update on Iraq and spending there this year? Andy? Yes. Good morning. Our rehabilitation plan has been approved and we're moving ahead with drilling completions workovers. Remediating some of the facilities to get the production up to the 10% target increase for this year. Do you have a CapEx in Iraq for this year for you all? It's uncertain, but it's because the schedules aren't down, but it's in the order of $100,000,000 or so. That's terrific. Thank you very much. Probably in the Q4. It is back end loaded. Terrific. Thank you. Our next question comes from Paul Sankey of Deutsche Bank. Hi, guys. Hi. Steve, did you break out, forgive me if I missed this, but you mentioned that 2Q production was lower than guidance. Did you split how much was California and how much was PSCs in the Middle East? Well, we actually didn't because I probably I started when I estimated the guidance, I started with a different number than I gave you. I started with essentially a higher number. So I can't really tell you how much was this and how much was that. I think through the PSC effects, we lost $8,000 to $10,000 a day. And that's the Middle East and PSCs, not the California ones obviously? The California one is pretty small. These are really not caused by the price as much as just a contract recalculation of our cost pools. Yes. Okay. And again, I'm not sure if you mentioned in response to an earlier question, but have the infrastructure issues had a knock on impact on the activity levels, which obviously you are ramping up quite aggressively. But I was just wondering if there was effectively a knock on slowdown that occurs because of the problems you're having with the infrastructure. We're not. We're planning if the infrastructure is going to be fixed and therefore the drilling will move forward. Right. So you're just continuing to drill. Does that mean you're going to have essentially stranded production the infrastructure is fixed or how will that work out? Well, the hope is and the belief is that that won't happen, that the infrastructure will be fixed, but it's possible you could have shut in production for short periods of time and that's where we are now effectively. Great. Thanks. And then just a follow-up on Iraq. There was some word that you might be pursuing further opportunities there in the relatively short term. Is there anything more to say about that beyond what you've already signed? And I'll leave it there. Thanks. I think it's in the very early stages if anything happens. Thanks, Steve. Your next question comes from Monroe Helm of Bairo Hanley. Thanks a lot. But my questions have been already answered. Thank Monroe. Your next question comes from Vedula Murti of CDP U. S. Hello? Vedula, your line is open. I can't hear her. Your next question comes from David Neuhauser of Livermore Partners. Hey, good morning, gentlemen. Good morning. Hey, with price being relatively stable now in this band $60 to $80 What's the biggest issue here as far as how you're going to ramp up production growth going forward? Is that the biggest hurdle? Product French? Production. With the pricing stable, are you focusing more on production and looking for growth there? Is that going to come more still from organic? Or are you still focused on some areas of acquisition? The company has always followed a balanced approach. You buy stuff when you can buy it at a reasonable price and when you can't, you can't. So, we have plenty of financial flexibility. But most of the growth will come organically over the next few years. You might pick up something, but it's pretty hard to tell. Yes. Is the difficulty just like is it valuation, valuation is still relatively pretty high? I mean, we're seeing some sort of carve out of some assets of some other companies. And does that potentially present an opportunity or are you really still focused on sort of the smaller private players? We're focused on generating value for the shareholders. If you do a dilutive value deal, you're going to destroy value. So and somebody else may have different stock with different kinds of value in it. So if you pay 10 times EBITDA for production, you have a high hurdle to generate future growth in order to pay for that kind of acquisition. If you pay 50% more than the next guy is willing to pay for some asset, you probably have an added value to the company unless you have some special insight. So we look for opportunities where there's some reason why we can have a competitive advantage. Some of it we have in the Permian because of costs and such. But the purpose of the exercise to make the an acquisition is to make the company better not worse. So we're not trying to dumb down the company. We're trying to strengthen the business. Of course. But with some of the private companies that are you seeing you're seeing better value as far as multiples, as far as what you're willing to pay, you're seeing those with the smaller? That's right. Sometimes it works the other way where the large deals are more are better. And sometimes it works the other way. For example, in the Arco Permian assets, we bought out of Arco Permian over the last 7 or 8 years, 2 packages out of there, basically buying out virtually all the true oil out of the packages. So what's left is sort of the residual after it's been picked over. Nothing wrong with the properties, but the price paid was a full price. Okay. And then my last question really is more on looking at more of a macro question. Looking into 2011 potentially even 2012. I mean, again, price being stable, if it stays in the stand, what are some of the biggest challenges for a company like Oxy here? Efficiently spending our capital. It's a matter of remember that while we're pretty oily, there's a fairly sizable gas component and whatever it is $4 and change, we would hope that the price of gas would be less stable and more. Okay. All right. Thanks a lot guys. Appreciate it. Thanks. And your next question comes from John Herrlin of Societe Generale. Yes. Hi, Steve. You're back. Yes, yes, I'm back. Feature? Is it diagenetic? Or can you just tell us what you found so far? I think define a technique to figure it out before we drill a well. And some of the times it works okay and sometimes it doesn't. It's a fundamental truth that the natural fracking process is God is cheaper than Halliburton. And so our natural we're looking for the flow from natural fractures and we're trying to figure out what the amount of acreage we have. We should have plenty opportunities to find that rather than spending a boatload of money to do a large scale frac. We'll probably try some large scale fracs because there's a lot of pay here. But the goal in the unconventional is to find areas with natural fracturing so that it's more economical to produce. You can always come back and try something more exotic later. What's the orientation of the beds? And also are you looking at say noses or crests of folds, things like that to get more fracture? We're looking for things around the fields that have been flexed, cleverly figuring that it's been flexed or there might be some fracturing. Okay, great. Next one, what's reasonably priced? What's your definition of reasonably priced given the recent transaction prices? It's accretive to the company's value. Okay. You won't specify. All right. That's fine. Anything going on in the Yigatin with respect to the oil drilling? Yigatin oil drilling, Bill? Yes, John. We've got 2 rigs running, drilling mainly these higher rate of return oil opportunities as opposed to the traditional shallow gas that you've generally seen in the past in the Huguenen. But we've got a 2 rig program going there and we expect to continue that throughout the rest of this year. Okay. Last one for me. With respect to acquisitions, you've already opined a little bit of that, Steve. What about Argentina? Which work more there since there's acreage available and production available? We'll be cautious in Argentina. I think that's the best way to say it. Great. Thank you. Thanks. No further questions. I'll turn the call back to management for closing remarks. Thanks very much for dialing in. If there's no further questions, please feel free to give us a call here in New York. Thanks