Earnings Call: Q1 2010

Apr 29, 2010

Good morning. My name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Occidental Petroleum First Quarter 20 10 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. You. Mr. Stavros, you may begin your conference. Thank you, Christy, and good morning, everyone. I'd like to welcome you to Occidental Petroleum's Q1 2010 earnings conference call. With us this morning from Los Angeles are Doctor. Ray Arani, Oxy's Chairman and CEO Steve Chasen, our President and CFO Bill Albright, President of Oxy's U. S. Oil and Gas Operations and Sandy Lowe, President of International Oil and Gas Business. In just a moment, I'll turn the call over to Doctor. Ronny, who will give you an early glimpse of some of the topics we're planning to address at our upcoming Analyst Meeting on May 19 in New York. Steve Chasen will then review our Q1 20 10 financial and operating results. Our Q1 earnings press release, Investor Relations supplemental schedules and the conference call presentation slides, which refer to Steve's remarks, can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Doctor. Ronny. Doctor. Ronny, please go ahead. Thank you, Chris, and good morning, ladies and gentlemen. As Steve Chasen will provide details on our financial results for the Q1 in a moment. But I want to give you a brief preview of our meeting with all of you in the financial community in New York on May 19. Both Steve and I will present at the meeting, but so will 4 of our senior executives who are responsible for international oil and gas operations, U. S. Oil and gas operations, the California Oil and Gas Operations and also the 4th edition will be the worldwide exploration preview. We will give you details on development and numerous key areas of our operations, which we know are of keen interest to you. Among the areas we will cover at the May 19 meeting are: 1, we will provide you a multiyear production outlook and buildup from our asset base, which will provide considerable detail about the continued growth of the company. We will also outline significant and exciting new opportunities in California, including both conventional and unconventional prospects in the state. We will present details on our continuing growth and success in Oxy's existing Middle East production and also insight into new project potential. And we will provide you our anticipated capital spending program over the next 5 years. My colleagues and I look forward to meeting with you in 3 weeks to give you a thorough presentation on these and the numerous other outstanding growth areas of Oxy. I will now turn the call over to Steve Chasen for the details on our Q1 performance. Thank you, Ray. Net income was $1,100,000,000 or $1.31 per diluted share in the Q1 of 20 10 income from continuing operations and core income were $1.32 per diluted share. 2,009 Q1 core income was $0.50 per diluted share. For comparability purposes, all of our prior period volumes as well as volume based statistics such as operating cost per barrel are being stated on a pre tax basis as we previously discussed with you. Please see the Investor Relations supplemental schedule for the previous 5 year and the 2,009 quarterly sales volumes presented on a pre tax basis. Here's a segment breakdown for the Q1. Oil and Gas Q1 20 10 core earnings were 1.8 $1,000,000,000 compared to $553,000,000 for the Q1 of 2019. The improvement in 20 10 was driven by significantly higher and domestic natural gas prices improved 59% from the Q1 of last year. Partially offsetting these gains were higher operating expenses, largely resulting from fully expensing CO2 costs in 20.10 as well as higher DD and A rates and the effects of foreign exchange. The year over year production was negatively impacted by 38,000 BOE per day in the Middle East, North Africa, Long Beach and Colombia, which are a result of the higher oil prices affecting our production sharing and similar contracts. Oil and Gas Q1 2010 core earnings of $1,800,000 was essentially the same as the Q4 of 2,009. Compared to the Q4 of 2,009, the 20 10 Q1 earnings reflected higher crude oil and natural gas prices, partially offset by increased DD and A rates, effective fully expensing CO2 costs in 20 10, lower total volumes resulting from 2 fewer days in the Q1 of 2010 and the timing of liftings I will discuss shortly. Oxy's average realized crude price in the 20 10 Q1 was $71.88 per barrel, an increase of about 3.5 percent to $69.39 per barrel in the Q4 of 2,009. Oxy's domestic average realized gas prices for the quarter was 5.6 $2 per Mcf compared with $4.37 per Mcf for the Q4 of last year. Worldwide oil and gas production for the Q1 of 2010 was 743,000 barrels equivalent per day, an increase of over 3.5% compared with 717,000 BOE in the Q4 of last year. Daily volumes increased in Bahrain by 2,000 barrels of oil and 126,000,000 cubic feet of gas. Our domestic operations added 5,000 BOE, largely in the Kern County discovery area. Partially offsetting these increases were 4,000 BOE of lower volumes resulting in the Dolphin Gas Plant maintenance, which was shut in for 50% of the production for approximately 2 weeks. Sales volumes for the Q1 of 2010 were 726,000 BOE a day compared to 722,000 BOE a day in the Q4 of last year. Sales volumes were lower than the production volumes I just mentioned due to the timing of liftings of 13,000 barrels of oil equivalent a day in the Middle East, North Africa and Latin America, of which 11,000 BOE a day were in Libya. Please see the Investor Relations supplemental schedules for net sales volumes per day and the net production per day by asset. Exploration expense was $56,000,000 in the quarter. Oil and Gas cash production costs excluding production and property taxes were $10.05 a barrel for the Q1 of 2010 compared to last year's 12 month cost of $9.37 a barrel. The increase reflects $0.32 a barrel, higher CO2 cost due to our decision to expense 100 percent of CO2 injected in the beginning of this year and higher field support, operations and maintenance costs. Taxes other than non income were $1.82 a barrel for the Q1 of 20.10 10 compared to $1.60 for all of 2,009. These costs which are sensitive to product prices reflect the effect of higher crude and natural gas prices. As a result of factors discussed above, the Q1 of 2010 compared to the Q4 of 2019 benefited by 100 $74,000,000 from higher prices, dollars 43,000,000 lower exploration expense, dollars 62,000,000 dollars of lower cash operating costs and G and A expense. These gains were offset by the lower listings of $102,000,000 effective 2 fewer sales days of $77,000,000 higher DD and A rates of $69,000,000 and higher CO2 costs being expensed of $25,000,000 Chemical segment earnings for the Q1 of 20 10 were $30,000,000 compared to $33,000,000 in the Q4 of 2,009. The Q1 of 2010 results reflect the continued weakness in domestic market, particularly in the housing and construction area sectors and the significant margin erosion that was experienced through 2,009 that carried in the Q1 of this year. Midstream segment earnings for the Q1 of 2010 were $94,000,000 compared to 81 dollars 1,000,000 in the Q4 of 2019. The increase in earnings was due to improved margins in the marketing and trading business, partially offset by lower pipeline income from Dolphin resulting from a 2 week partial shutdown of the gas plant for maintenance. Fibro's earnings for the Q1 of 20 10 were not significant. The worldwide effective tax rate was 41% for the Q1 of 2010. Capital spending for the Q1 of 2010 was about $850,000,000 Capital expenditures by segment were 80% in oil and gas, 15% in mid stream with the rest in chemicals. The spending run rate will increase throughout the year as we ramp up in California, Bahrain and Iraq. Our total year forecast has been increased by $200,000,000 to $4,500,000,000 Cash flow from operations in the Q1 of 2010 was $2,200,000,000 We used $850,000,000 of the company's cash flow to fund capital expenditures, dollars 250,000,000 on largely Permian acquisitions and Mid Continent, I'm sorry, acquisitions and $50,000,000 on foreign contract commitments. These items amounted to $1,200,000,000 of cash use. We property acquisition activity to continue during this quarter as there is a sizable buildup of opportunity. We also used $270,000,000 to pay dividends and $225,000,000 to retire debt. These and other net cash flows increased our $1,200,000,000 cash balance at the end of last year by $700,000,000 to $1,900,000,000 at the end of the quarter. The Q1 free cash flow after capital spending and dividends, but before acquisition activity and debt retirements was about $1,100,000,000 The weighted average basic shares outstanding for 3 months of 2010 were 812,100,000 and the weighted average diluted shares outstanding were 813 0.5000000. As we look ahead in the current quarter, we expect oil and gas sales volumes to be in the range of 700 and 50,000 to 760,000 BOEs a day at about current prices with production slightly above these levels. Production volume increased in the 2nd quarter expected to come from the following sources. Domestically, the Kerncon discovery area expect to show modest improvement during the Q2. The production continues to be constrained by the lack of additional processing capacity. More significant increases are expected to occur late in the Q2 when we add the skid mounted gas processing facilities. We're continuing with drilling and completed a number of wells. Have sufficient completed wells to fill the entire capacity of the skid mounted processing facilities. Our oil production is also constrained by the lack of gas processing capacity since these wells also produce natural gas. The Mid Continent gas region we are currently drilling shallow gas wells, shallow oil wells is also expected to show production growth. In the Middle East, increases are expected in Oman, Mohisena field and Dolphin. The Q1 plant maintenance downtime is not expected to repeat. In Latin America, assuming no labor related stoppages, increases are expected in Argentina with the current run rate is about 2,000 BOE a day higher than the Q1, which was negatively affected by a short strike. The Argentine provincial legislature passed enabling legislation in the Q1 that will allow a 10 year extension for hydrocarbon extensions. We are now negotiating specific contract terms with 10 year extension of our concession. With regard to prices, the current market price is $1 per barrel change in oil prices impacts oil and gas quarterly earnings before income taxes by about $36,000,000 average Q1 WTI oil price was $78.71 per barrel. A swing of $0.50 per 1,000,000 BTUs in domestic gas prices has a 31,000,000 dollars impact on quarterly earnings before income taxes. The current NYMEX gas price is around $4 per Mcf. Additionally, we expect exploration expense to be about $80,000,000 for seismic and drilling for our exploration programs. For the Chemical segment, demand for caustic soda and vinyls is expected to continue to improve both the United States and international markets. Moving caustic soda pricing and low natural gas price will contribute to margin improvement. The Chemical segment is expected to provide about $80,000,000 of earnings in the 2nd quarter. We expect our combined worldwide tax rate in the second quarter be about 42% depending on the split between domestic and foreign sourced income. Our Q1 U. S. And foreign tax rates are included in the Investor Relations supplemental schedule. Copies of the press release announcing our results and the schedules are available at our website, www.oxy.com or through the SEC's EDGAR system. We will provide additional details on May 19 meeting with the financial community in New York City. We request that you limit your questions today, specifically the quarter results as opposed to strategic matters such as Iraq, Bahrain and California operations, which will be discussed in detail at the meeting. We're now ready to take your questions. And your first question comes from the line of David Heikkinen of Tudor, Pickering, Holt. Good morning. As I think about one of your future sources for CO2 that has made a strategic shift towards more oil activity, can you talk about any of the specific terms of your contract regarding deliverability, any penalties around that deliverability? That would be helpful for us. Yes. We're going to cover this really in a lot more detail in the May meeting. But there's a sizable penalty for failure to deliver if for some reason they don't deliver. But our current we currently anticipate that they'll make their early numbers based on what they told us. So but there is a sizable penalty, which would allow us to buy new CO2 elsewhere at an attractive net price. So I hope we're going to cover this in a lot of detail in May. Okay. And specifically on Q2 guidance and liftings, you mentioned growth in specific areas and no expected downtime. How much of the delayed liftings in Q1 come into that Q2 number? And then how much volume would you expect to come into Q3? Actually what we said in the remarks was that we expect that production will exceed sales again in the 2nd quarter. The numbers I gave you are sales numbers and we expect currently that production would be higher than that. So the answer to your question is none of effectively none of the liftings will show up. Traditionally what happens is that they lag just a little bit and it catches up by the Q4 because it's just off a little bit. It seems like a lot, but just off a little bit. Okay. I look forward to the March meeting. Thanks. Thank you. Our next question comes from the line of Brian Todd of Morgan Stanley. Hi. Good morning, gentlemen. Just a quick question on cash flow. You obviously generated a lot of free cash flow this quarter and I realized that the CapEx spend was going to be a bit more back end loaded throughout the year. But as we look at commodity prices and we look at relative levels of free cash flow, I realize you bumped up your CapEx a little bit, but how can we expect you to think about your uses of cash in terms of more aggressive deployment of organic capital versus cash return to shareholders? And also the increase in CapEx, can you tell us was that in any particular area or is just inflation across the board? No. We're going to talk about the use of cash. I view that strategic question as opposed to quarterly question. So we'll talk about the use of cash in much more detail in May. But the Q1 tends to be very strong quarter for cash. There's no tax payments. So there's more tax payments in the Q2. So it will be a little different. The $200,000,000 of capital is largely going to California. Great. And is that of increased activity from what you originally anticipated or is that just higher cost? No, that's increased activity. Great. I appreciate the help. Thanks. And your next question comes from the line of Paul Sankey of Deutsche Bank. Hey, Steve. Tough to limit it to non strategic. Just on the tax rate, was there anything wacky or unusual other than your standard line, which obviously is it's a question of the mix between international and domestic. Was there anything other that you would highlight as being particularly unusual about the lower than guidance tax rate for the quarter? It's tax department likes to always be a little more aggressive on what they think they're going to tax rate is going to be. But it is what I think what happened was the lesser liftings out of Qatar and Libya made the tax rate appear a little lower because those are high tax rate areas. Right. So it really just does go back to this international noise. On kind of news flow in the quarter, if you like, Conoco notably backed out of a project that you had expressed interest in. Is there any change now to the way you were looking at that project? Obviously, I'm referring to an Abu Dhabi. And generally, Steve, any comments you could make about the M and A environment that we're seeing? I'll leave it there. Thanks. Ray Roni here. We have consistently said over the last 2 years that the terms of the contract that was negotiated between Conoco, Phillips and Abu Dhabi, the terms economically are not attractive to us. However, if the government wishes to approach us with different terms, we'll look at them. Nobody's called us yet and that's our position. With regards to M and Steve, and Steve will give you more detail. Steve? Yes. I think activity clearly has picked up and we're seeing a good flow of mostly Permian opportunities and we expect to have a pretty good year for acquisitions in the Permian. Okay. And would you expect just going back to the Abu Dhabi thing, would you expect the government to potentially pursue that project alone or is it your understanding that they will? No, definitely. I was in Abu Dhabi recently. The government plans to proceed with that project either alone or inviting partners, but the project will go ahead. I understand. And then just back to the M and A question, much less internationally, It's just the flow from quarter to quarter. I don't think I'd read much into any of this. A lot of individual sellers in the Permian as they fear the rising tax rates. So we've seen quite a flood of a lot of small oil deals that people want to cash out before the tax rates go up. Thank you, everyone. Thanks. The line of Doug Leggate of Bank of America. Thank you. Good morning, gentlemen. Good morning. A couple of things. Steve, in Argentina, if I could just ask you for a little bit of clarification as to what's going on down there. Have you now actually got the extension on your contract then? It's a 3 step process. You start with the government, the legislature passing a law which enables the and the parameters of any extension. So there's a law which says these are the parameters of any extension. That's talking about the provincial legislature. The government of Argentina then negotiates with us about the detailed terms complying with the underlying legislation. And that's where we are now. Then they will have to submit the final contract to the legislature when that's all negotiated. So the answer to your question is we've made progress, but we have not crossed the finish line. That's 10 years from when it expires and I think it expires in about 3 years. So talking about 13 more years of production on average. Okay. So the ramifications, if you get the extension, I'm guessing you would have reasonably substantial reserve bookings and so on along with that, but it's too early to make that kind of assessment or Well, I think we'll tell you the numbers in a few weeks. But clearly, you're going to have a significant amount of reserve bookings just from the not cutting the decline curve off in 3 years and a fairly sizable decline in the DD and A rate in Argentina. Okay, great. A couple of other quick ones, if I may. I don't know if I missed this earlier. I apologize you had a competing call going on, you probably know. The jump in DD and A, anything specific there that you can point to? I think the two areas that are the major increases are. When we took the gas down, the amount of gas in the Piansoo, the $4 using the $4 gas results in less gas reserves and a higher DD and A rate in the Rockies. And the second area is Argentina. As we continue to spend in anticipation of the contract being extended, but it hasn't been extended yet and therefore you boost your DD and A rate. The second one will once the contract extend will clearly go down. And the first one, we hope goes down if the natural gas prices were to cooperate, which I guess they're not doing today. Okay. And a couple of very quick final ones. Can you quantify the lost opportunity costs from the underlift in the quarter? No, I really don't. I can't quantify it. It's a sizable number though. You could on an after tax basis, you could probably take that number and use somewhere around $20 a barrel. Right. Okay. And the final one, I don't know if you've prepared to answer this one, but you've given us end of quarter run rates or production rates out of the Kern County discovery. Would you care to share what they were at the end of the Q1? No, because we want to have some story here for 2 weeks from now. All right. I'll leave it there. Thanks, Steve. Thanks. Question comes from Monroe Helm of Farrow Hanley. Thanks a lot guys. Actually my question, I think the answer is to unless you want to amplify as to why you are seeing these opportunities to buy oil reserves in the Permian. I guess you said it's basically because small operators are worried about tax rates going up. And royalty owners too. Okay. Small working interest royalty owners. It's spigots really a lot of small deals. Okay. You may not want to say this, but can you tell us what the processing capacity was in California in the Q1 and where you expect it to be when you get the additional capacity on? Bill, why don't Bill answer the capacity question? Yes. Monroe, our current infrastructure capacity at Elk Hills is 420,000,000 a day. And the Skid Mountain gas plant is name plated for an additional $90,000,000 a day. Okay. Okay, thanks a lot. We'll see you at your meeting. At this time, there are no further questions. Are there any closing remarks? Thank you very much for dialing in today. And I'm in New York for any further questions and we certainly look forward to seeing you in New York at our May 19 meeting. Thanks very much. Thank you.