Operator: 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 2013 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 call over to Chris Stavros. Please go ahead.
Christopher G. Stavros - VP, IR: Thank you Christie, and good morning and welcome everyone and thank you for participating in Occidental Petroleum's first quarter 2013 earnings conference call.
Joining us on the call this morning from Los Angeles are Steve Chazen, Oxy's President and Chief Executive Officer; Cynthia Walker, our Chief Financial Officer; Bill Albrecht, the President of Oxy's Oil & Gas Operations in the Americas; Sandy Lowe, President of our International Oil & Gas business and Willie Chiang, our EVP of Operations and Head of Oxy's Midstream businesses.
In just a moment, I'll turn the call over to our CFO, Cynthia Walker, who will review our financial and operating results for this year's first quarter. Steve Chazen will then follow with an update on the progress we are making toward our ongoing efforts to improve our oil and gas operating cost as well as our capital and drilling efficiencies and as part of our effort to improve our financial returns. Steve will conclude the call with some comments around guidance for the second quarter. A highlight of this quarter's conference call will be an in-depth discussion from Bill Albrecht focusing on our non-CO2 drilling program in the Permian Basin and additional details on our drive to improve capital and drilling efficiency and reduce our operating cost throughout the domestic oil and gas business.
As a reminder today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied in these statements and our filings. Our first quarter 2013 earnings conference call press release, investor relations supplemental schedules and conference call presentation slides which refer to our prepared remarks can be downloaded off of our website at www.oxy.com.
I'll now turn the call over to Cynthia Walker. Cynthia, please go ahead.
Cynthia Walker - EVP and CFO: Thank you, Chris, and good morning everyone. Core income for the quarter was $1.4 billion or $1.69 per diluted share in the first quarter of this year compared with $1.6 billion or $1.92 per diluted share in the first quarter of 2012 and $1.5 billion or $1.83per diluted share in the fourth quarter of 2012. Compared to the fourth quarter of 2012the current quarter results reflected higher realized oil prices, reduced operating expenses in the oil and gas business and higher earnings in the midstream segment. These were offset by lower volumes in the Middle East and North Africa region due to planned maintenance turnaround and higher DD&A rates.
I'll now discuss the segment breakdown; oil and gas core earnings for the first quarter of 2013 were $1.9 billion compared to $2.5 billion in the first quarter of 2012 and $2.3 billion in the fourth quarter of 2012. On a sequential quarter-over-quarter basis, higher realized oil prices and lower operating expenses were offset by lower Middle East/North Africa volumes and higher DD&A rates. Our sales volumes in the Middle East, North Africa were lower compared to the fourth quarter of 2012 due mostly to the timing of liftings as well as the effect of the maintenance turnaround in Qatar and full cost recovery under our contract in Oman. This reduced our 2013 first quarter earnings by about $200 million after-tax compared with the fourth quarter of 2012.
Costs associated with the turnarounds, pipeline disruptions in Colombia and other factors further reduced our earnings by about $30 million after-tax. Combined these factors reduced oil and gas segment earnings by approximately $450 million on a pre-tax basis. Oil and gas production costs were $13.93 per barrel for the first three months of 2013 compared to $14.99 per barrel for the full year of 2012. Production cost at this level already beats our previous full year 2013 guidance. The lower cost were attributable to our domestic operations where production costs were $3.37 per barrel lower in the first quarter of 2013 from the full year of 2012 and our Middle East/North Africa operations operating costs increased by about $2.50 per barrel on a sequential quarterly basis. This increase was due to the planned maintenance turnaround in our Qatar North Dome and South Dome fields and to a lesser extent the planned turnaround in Dolphin.
First quarter 2013 total daily production on a BOE basis was 763,000 barrels, which was 16,000 barrels per day lower than the fourth quarter of 2012 and 8,000 barrels per day higher than the first quarter of 2012. Approximately 13,000 barrels of the total sequential decrease in the quarterly production came from Qatar and Dolphin where the planned maintenance impacted production.
I'm pleased to say that turnarounds were executed successfully and production has returned to normal level. Our domestic production was 478,000 barrels per day, an increase of 3,000 barrels per day from the fourth quarter of 2012 and this now marks the 10th consecutive quarterly domestic volume record for the Company. Production was 5% higher than the first quarter of 2012. Almost all of the net sequential quarterly increase came from production in the Permian. Focusing on liquids production it was flat with the fourth quarter, reflecting a drop in production in our Long Beach operations resulting from the effect of lower spending under our production sharing contract there and slightly lower production elsewhere in California in the steam flood operations. This was offset by higher production in other areas, namely in the Permian and Williston.
Latin America volumes were 31,000 barrels per day, which was 1,000 barrels lower compared to the fourth quarter and 5,000 barrels higher than the same period in 2012. The reduction from last quarter was due to heightened level of insurgent activity in the region. In the Middle East/North Africa, production was 254,000 barrels per day, a decrease of 18,000 barrels from the fourth quarter of 2012 and 20,000 barrels from the first quarter of 2012. The planned maintenance turnarounds in Qatar reduced our production 13,000 barrels per day. The impact of full cost recovery and other factors affecting production sharing and similar contracts reduced first quarter production volumes by an additional 5,000 barrels per day compared to the fourth quarter of 2012. Details regarding other country-specific production levels are available in our Investor Relations supplemental schedules.
Middle East/North Africa volumes were further lower than production volumes in the first quarter due to the timing of liftings. First quarter realized prices were mixed for our products compared to the fourth quarter of 2012. Our worldwide crude oil realized price was $98.07 per barrel, a 2% increase from the fourth quarter, while worldwide NGLs were $40.27 per barrel, a decrease of about 11%, and domestic natural gas prices were about flat at $3.08 per million cubic feet.
First quarter 2013 realized prices were lower than the prior year first quarter prices for crude oil and NGLs. On a year-over-year basis, price decreases were 9% for worldwide crude oil and 23% for worldwide NGLs. Domestic natural gas prices were higher by about 8%. Realized oil prices for the quarter represented 104% of the average WTI price and 87% of the average Brent price. Realized NGL prices were 43% of the average WTI price and realized domestic gas prices were 91% of the average NYMEX price. For the first quarter of 2012, the comparable percentages were 105% of WTI, 91% of Brent for oil, and 51% of WTI for NGLs and 100% of NYMEX for gas.
At current global prices, $1 per barrel change in oil prices affects our quarterly earnings before income taxes by $37 million and $7 million for a $1 per barrel change in NGL prices. A change in domestic gas prices of $0.50 per million BTU affects quarterly pre-tax earnings by about $30 million. These price change sensitivities include the impact of production-sharing and similar contract volume changes.
Taxes other than on income, which are generally related to product prices, were $2.63 per barrel for the first quarter of 2013 compared to $2.39 per barrel for the full year of 2012. The 2013 amount includes California greenhouse gas expense of $0.05 per barrel. First quarter exploration expense with $50 million, we expect second quarter 2013 exploration expense to be about $100 million for seismic and drilling in our exploration programs.
Chemical segment earnings for the first quarter of 2013 were $159 million compared to $180 million in the fourth quarter of 2012 and $184 million in the first quarter of 2012. The sequential quarterly decrease was due to higher ethylene costs and increased competitive activity, particularly in the domestic caustic soda markets. This was partially offset by higher VCM and PVC prices.
The Chemical segment second quarter 2013 earnings are expected to improve to about $170 million, benefiting from higher seasonal demand in the construction and agricultural markets.
Midstream segment earnings were $215 million for the quarter compared to 2013 – for the first quarter of 2013 compared to $75 million in the (fourth) quarter of 2012 and $131 million in the first quarter of 2012. Over 70% of the 2013 sequential quarterly increase in earnings resulted from improved marketing and trading performance. The remainder of the increase came from improved margins in the gas processing and power generation businesses and higher earnings from foreign pipelines.
The worldwide effective tax rate on our core income was 38% for the quarter. This included a benefit resulting from the relinquishment of an international exploration block. Our first quarter U.S. and foreign tax rates are included in the Investor Relations Supplemental Schedules. We expect our combined worldwide tax rate in the second quarter to be approximately 41%. In the first three months of 2012, we generated $2.9 billion of cash flow from operations before changes in working capital. Working capital changes reduced our cash flow from operations by about $200 million to $2.7 billion.
Capital expenditures for the first quarter of 2013 were $2.1 billion. This capital spend was $440 million lower than the fourth quarter of 2012, about half of the decrease in the oil and gas business. First quarter capital expenditures by segment were 80% in the oil and gas business, 15% in midstream and the remainder in chemicals. These and other net cash flows resulted in a $2.1 billion cash balance at the end of March.
The weighted average basic shares outstanding for the three months of 2013 were 804.7 million and the weighted average diluted shares outstanding were 805.2 million. We had approximately 805.6 million shares outstanding at the end of the quarter. Our debt-to-capitalization ratio was 16% at the end of the quarter. Our annualized return on equity for the first three months of 2013 was 13.4% and return on capital employed was 11.4%.
I'll now turn the call over to Steve Chazen to discuss other aspects of our operations and provide guidance for the second quarter of the year.
Stephen I. Chazen - President and CEO: Thank you, Cynthia. Occidental's domestic oil and gas segment produced record volumes for the 10th consecutive quarter and continue to execute on our liquids production growth strategy. First quarter domestic production of 478,000 barrel equivalents per day consisting of 342,000 barrels of liquids, 817 million cubic feet of gas per day was an increase of 3,000 barrel equivalents per day compared to the fourth quarter of 2012.
We are executing a focused drilling program in our core areas and to date we are running ahead of our full-year objectives in our program to improve domestic operational capital efficiencies. For example, we have reduced both our domestic well and operating costs by about 19% relative to 2012. This is ahead of our previously stated targets of 15% well cost improvement and a total Oil and Gas operating cost below $14 a barrel for 2013. While we are still in the early stages of this process and making a longer-term projection is difficult, our goal is to sustain the benefits realized to date, achieve additional savings in our drilling costs and reach our 2011 operating cost level over time without a loss in production or sacrificing safety. Purpose of these initiatives is to improve our return on capital.
I will now turn the discussion over to Bill Albrecht who will provide details of our domestic drilling programs and of the capital and operational efficiencies initiatives that we have implemented.
William E. Albrecht - VP, President, Americas, Oxy Oil & Gas: Thank you, Steve. This morning, I'd like to share with you the three main objectives of our 2013 domestic program. First, delineate our core or anchor drilling areas in the Permian Basin. We've accumulated more than 1.7 million net acres covering both relatively established and emerging plays in the Permian. This year, we're focused on delineating incremental opportunities in established plays, as well as testing the potential of many emerging plays. Second, drive capital efficiency, particularly in our core drilling programs. We believe that the results of our capital efficiency improvement program are not only scalable across our core programs, but that these results are also sustainable. And third, enhance our cash margins through operating expense reductions.
Turning now to our first objective, our Permian Basin activity. As we've said in the past, under current market conditions, our growth will come largely from oil. The Permian will play a key role in that growth. In 2013, we expect to spend $1.9 billion in the Permian. Approximately two-thirds of this capital will be spent in our non-CO2 business. In this business, we'll drill approximately 300 wells, 90% of which will be focused in four plays, the Wolfberry, Yeso, Delware Sands, and Wolfbone.
The Wolfberry has been a solid core play for many years at Oxy and represents the largest proportion of our activity. In 2013, we’ll drill a mix of infill wells in already established core areas and step out wells in emerging areas of the play. We expect step out wells to pretty much mirror the solid results we've seen in drilling hundreds of Wolfberry wells in the last several years.
The Delaware will be about a quarter of our activity in 2013. We're seeing increased opportunity to enhance economics utilizing horizontal drilling and completions to develop established tight-sand reservoirs. We expect to drill 12 horizontal wells targeting the Delaware sands this year. Our emerging Yeso play in New Mexico has demonstrated encouraging results. As result in 2013, we expect to increase drilling activity by 30% from 2012 levels.
The Wolfbone play in Reeves County, Texas is the newest of the plays. Throughout 2012, we were able to acquire a meaningful mostly contiguous acreage position. We drilled a handful of wells in 2012 and we'll increase our activity this year as we further delineate our acreage position. Because of the multi-pay nature of the play, wells will be mostly vertical at this stage, although we'll drill a number of horizontal wells in sweet spots of this multi-pay interval. Early results are encouraging. 30 day IP rates are averaging between 170 and 235 barrels of oil equivalent per day depending on the area. The key to success is a low cost structure. We've been drilling for less than a year in the Wolfbone and have already seen substantial improvements in well costs. As we build infrastructure and establish a steady program, we expect to see further progress in our costs. In addition to these four core programs, we believe we have opportunities in several of other emerging plays. We plan to drill 20 to 25 wells testing horizontal potential in the Bone Spring, Wolfcamp and Cline across our acreage position.
I'll now turn to our second objective driving capital efficiency. There are essentially four elements of our overall capital efficiency strategy; these are locking in our drilling programs; modifying well objectives and designs; improving operational execution and improving our contracting strategies. We are measuring our progress by comparing our 2013 well cost to 2012 using the 2013 program attributes. In other words for our benchmark year of 2012 we are using cost that we incurred for the same mix of well locations and types being drilled in 2013. By implementing all four elements we've already achieved more than 19% reduction in our well costs relative to the 2012 benchmark across our domestic assets. The most important improvements were achieved in the Williston, the Wolfberry, and shale drilling at Elk Hills where costs have dropped by 32%, 20% and 22%, respectively.
Let me describe each of the four elements in more detail; first, we found that locking in our drilling programs for appropriate lead times results in significant efficiencies. This has allowed us to have fit-for-purpose drilling rigs in each core area, minimize the number of drill site contractors and minimize drilling and mobilization times as well as rig move distances. To this end as we developed our drilling programs for the year, we locked in our drilling plans for two to three months in advance depending on location across all our assets. Consequently we've reduced our rig downtimes by 20%. For example, in the Williston, our optimized drilling schedule designed to minimize rig mobilizations has reduced move cost by 33%. The second element is modification of well objectives and design; for example, in our Wolfberry program we now run only two strings of casing instead of three which has saved approximately $250,000 per well. We've also reduced costs by 47% per frac stage per Wolfberry well, without any degradation in production. At Elk Hills, in our anchor shale program, we are running mostly slotted liners instead of cemented liners, saving $1.5 million per well, again with no degradation in production. In a number of our programs, we've reduced the amount of gel loading and resin-coated sand thus reducing completion costs. In short, we are seeing the benefits in the form of reduced drilling and completion times and reduced and more efficient use of materials and supplies.
Let me now turn to the third element, improving operational execution. While we are making numerous incremental changes in our day-to-day activities everywhere, we've made significant improvements, specifically in the Permian and Williston business units. In both areas, we're optimizing our use of water in completion operations by using flowback and/or produced water in stimulations, which is generating substantial savings this year.
In the Williston, more of the wells we are drilling have been trouble free, particularly due to improved directional tool reliability. Finally, we've made a fundamental change in a way and the extent to which we use contractors and outside consultants to manage and supervise our drilling programs. A heavier reliance on our own personnel for these tasks has already resulted in efficiencies, while providing more growth opportunities for our people.
The last element of our capital efficiency effort is contracting strategies. In this regard, principally in the Permian, Williston and at Elk Hills, we have reduced our stimulation contract pricing. We've also reduced our fluid hauling costs by implementing a trucking cluster concept whereby a certain trucking fleets are dedicated to specific core areas. Overall, we've improved our completed well costs in the Williston from an average $10 million per well as recently as just four months ago to $8.2 million currently. We believe that we're now top quartile in well costs in the play. Our current goal is to bring average Williston well cost down to $7.5 million. We believe at this level we will have the flexibility to focus on continuing development of our Russian Creek acreage where we plan to drill 46 wells in 2013, concentrating on the sweet spot of our acreage there. Our development will be mainly in the Middle Bakken with other Wells testing both the Pronghorn and Three Forks formations. In another one of our anchor programs the Wolfberry, we've seen sustained reductions in completed well costs, where costs are down from $3.5 million to $2.6 million.
Lastly, I would like to discuss the third objective of our overall domestic strategy and that is, enhancing our cash margins through reductions in operating costs. While our operating costs have also benefited from some of the actions taken for capital efficiencies that I just described, we have taken additional steps specific to reducing our operating costs, especially in the areas of downhole maintenance and workovers, which together make up the bulk of our costs.
I would like to share a few examples with you of the actions we have taken toward achieving our goal. First, in order to optimize our well-servicing rig costs, we are eliminating inefficient workover rigs. While this has caused an overall decline in our workover rig count, we are finding that through better planning and scheduling, we are able to perform a similar number of well-servicing jobs as we did with a larger fleet. As a result, we've not seen any production falloff from these reductions.
Second, through a more rigorous review of wells that are repair and maintenance candidates, we've been able to reduce our workover needs by dropping uneconomical wells from our list. These wells will be subject to ongoing evaluations based on market conditions. Third, we are evaluating the efficiency of our maintenance crews and prioritizing the most efficient ones. Through more direct on-location supervision, more efficient crews, optimized maintenance scheduling to allow better planning, and tighter controls over spending limits and job approvals, we've already been able to reduce our well intervention times and maintenance and workover costs. Fourth, we are also focusing on our surface operations, which constitute another large cost driver, and we've been able to achieve efficiencies in our use of chemicals, water handling, and disposal activities.
Water handling and disposal is a major cost for the Company. Therefore, it's a key area of focus for us. In some locations, we've been able to find ways to recycle more of our produced water, reducing our sourcing as well as disposal costs, and as a result, handling water in a more environmentally conscious manner. We're also working with our suppliers to address the cost of these supplies and services.
In addition, we are working on optimizing our use of injectants and energy. For example, we are improving our CO2 and steam utilization through ongoing pattern surveillance and evaluation of injectant to oil recovery ratios and we are reducing our energy costs through maximizing the use of self-generated energy and rate renegotiations.
As a result of our efforts compared to the 2012 levels, our downhole maintenance and workover costs have dropped 36% and our overall surface operations costs by 16%, contributing to a 19% reduction in our operating costs on a BOE basis, across all of our domestic assets. Our total domestic operating cost per barrel dropped from $17.43 per barrel in 2012 to $14.06 per barrel in the first quarter of 2013. We believe our ongoing efforts will yield additional improvements going forward.
I'd like to add that the great success we've had to date in achieving our capital efficiency and operating expense reduction goals is the result of implementing literally thousands of small ideas, suggestions and decisions being made every day mainly at the field level. I'm extremely pleased that our personnel at every level have stepped up in a big way to achieve our stated goals of achieving 15% capital efficiency gains, and so far exceeding this goal, and reducing our annualized operating expenses by minimum of $450 million. While we made progress in both our capital efficiency and operating cost reduction efforts, we are still in the early stages of this process and therefore our data is based on a relatively small portion of our overall program. In addition, we executed a relatively trouble-free drilling program in the first quarter. Nonetheless, given our results to date and our people's efforts in this endeavor, we are optimistic we can sustain and further improve upon the results achieved to date. I'd like to emphasize that our overarching goal is to make sure we achieve these improvements without in any way compromising the safety of our operations and of our people and without impacting our growth plans.
I'll now turn the call back to Steve Chazen.
Stephen I. Chazen - President and CEO: Thank you, Bill. With regard to the total return to shareholders in February, we increased our dividend by 18.5% to an annual rate of $2.56 per share from the previous annual rate of $2.16. We've now increased our dividend every year for 11 years and totaled 12 time during that period. This 18.5% increase brings 11 year compounded dividend growth rate to 16% per year.
I will now turn to second quarter outlook. Production, domestically, we continue to expect solid growth in our oil production for the year as a result of the nature and timing of your drilling such as steam flood drilling in California. We expect second quarter liquids growth to be modest with higher growth coming in the second half of the year. We just received word today that we got permits for three new – for three new compressors for our steam flood program; one is already on. So, I think, we are doing well in California on this just a slow start this year.
In the first quarter of 2013, our base gas production did not decline as much as we had initially expected. Estimating the production for the rest the year still remains challenging. We expect to see modest declines in our gas production as a result of our reduced drilling on gas properties and natural decline as well as a number of gas plants turnarounds scheduled in our Permian business for the rest of the year.
Internationally, excluding Iraq, at current prices, we expect production to be higher in the second quarter back to around the fourth quarter 2012 levels; the increase coming mainly through resumption of production cutter. Iraq's production is directly correlated to quarterly spending levels, which continue to be volatile. We expect international sales volumes also to get back to about fourth quarter levels based on our current lifting schedule.
Our first quarter capital spend was $2.1 billion. We expect the second quarter rate to be higher. Our annual spending level is unchanged and expected to be in line with the $9.6 billion program, I discussed on the last call. As you can see the business is doing well and we are continuing to make progress on our operational and financial goals, I am very pleased that employees at all levels have stepped up to the challenges we presented to them and are focused on their jobs. We have not seen any significant negative turnover trends in our workforce. As I have stated before, I remain committed to staying through the succession process.
Now we're ready to take your questions about the performance of the business. However, we do
not have anything to add beyond our public announcements about the ongoing Board activities and the succession process.
Operator: Doug Terreson, ISI Group.
Doug Terreson - ISI Group: Congratulations on your results everybody.
Stephen I. Chazen - President and CEO: Thank you. The guys -- the people in the Company did a great job.
Doug Terreson - ISI Group: So, my question regards the sequential decline in earnings of $450 million, which was highlighted I think on Slide 3 and specifically whether you can provide any additional insight into the component, which is likely to be transitory meaning some of the elements were identified, but how much is sequential decline related to factors that are not normally recurring like maintenance and pipeline disruptions and lifting variances et cetera?
Stephen I. Chazen - President and CEO: I think Cynthia has that variance, so let her answer that.
Cynthia Walker - EVP and CFO: Really the only component of the quarter-over-quarter decline that we expect to be recurring is the Oman contract impact, which is about $50 million of the $450 million. The rest of it all relates to timing of liftings, as well as and cutter turnaround which you mentioned cutters turnarounds and the pipeline disruptions in Colombia.
Operator: Doug Leggate, Bank of America Merrill Lynch.
Doug Leggate - Bank of America Merrill Lynch: I've a couple if I may Steve. On the cost, Steve, if I look at the costs on the U.S., you obviously broke that out for us and I take your commentary about the total Company, that looks to me at least that the international costs were up a couple of maybe $2 to $3 a barrel.
Stephen I. Chazen - President and CEO: That's right.
Doug Leggate - Bank of America Merrill Lynch: So I’m wondering so that sounds about right. So basically, when the production comes back on in the second quarter, does that mean your run rate is now below $13? And if you could help us with where you think the stretch goal gets to on your operating cost, and I’ve got a follow-up please.
Stephen I. Chazen - President and CEO: We'll let Cynthia give you the first part and I'll answer the second part. So where does that put our run rate?
Cynthia Walker - EVP and CFO: Yeah. In the second quarter, there will be some other factors likely offsetting things, but we wouldn't expect to get substantially below the levels that we are currently. We won't be below $13 a barrel in the second quarter. Some of the activity that we didn't do in the first quarter will come into the second quarter.
Doug Leggate - Bank of America Merrill Lynch: In terms of stretch goals?
Stephen I. Chazen - President and CEO: We expect that the U.S. business – let me maybe simplify a little bit for you. We expect the U.S. to – we're going to be cautious on the operating cost here to make sure we're not affecting safety and production. So, we expect those costs continue to go down, but obviously not as quickly as it did in this quarter. But the international costs will come back into line. They were up this past quarter, but we think they'll be down next quarter. And by putting money into the – what we've done – the turnarounds will increase the reliability and we should actually do better on a gross basis or maybe some turnaround costs and stuff that'll roll through I think was what Cynthia was referring to. The fundamental numbers will be lower. Again, there might be some additional turnarounds out in the Middle East, but in the U.S., Sandy, you want to comment on the Middle East?
Edward A. Lowe - VP, President, Oxy Oil & Gas, International Production: In Qatar, we are actually producing at record levels since the past few years 118,000-119,000 gross and the extra money we spent on the turnaround that we got much higher reliability. We have records in Oman right now of 235,000 barrels a day gross and we actually are reducing OpEx per barrel there still paying attention to production reliability and safety issues.
Doug Leggate - Bank of America Merrill Lynch: Steve, my follow up and I hope you are going to forgive me for this one ahead of time. My question relates to you – in terms of your intention. When we followed in the past you've always stated that you saw yourself being in position for quite a while in executing a strategy that ultimately took you towards 1 million barrels a day. Should we rule out the possibility of you staying around a bit longer as the Board, for example, (indiscernible) and what is your strategic vision for the Company longer-term?
Stephen I. Chazen - President and CEO: I am not going to answer the first question. That's really outside the purview of what we want to talk about. On the strategy issue the Company as we get – the Company is really executing well. Every day I am sort of happy to talk about the operations. I think the Company is doing really well. I think we'll continue to grow nicely. We have little bumps in the road in the quarter, but fundamentally I really couldn't be happier about the progress we are making as a company. The million barrels a day, I think, is a reasonable objective. What we are going to do from call-to-call is, Bill got to talk this time, we'll let somebody else talk next quarter and maybe we'll talk about California next quarter and I have (Vicki) come and talk. So, we'll try to give you more detail one call at a time rather than try to flood you with it. So, I think you'll see that the strategy of building a large domestic business together with a highly profitable international business will work for us. So, I think the vision right now is sort of that one. So, as you want to ask the same question in other way.
Doug Leggate - Bank of America Merrill Lynch: Well, I'm just saying, would you ever see that there has been a lot of speculation about structural changes whether it was separating one part or another whether it would be MLPs or whether it would be California getting split off. Is that something that you are going to enter into the discussion right now or is it just not on the table?
Stephen I. Chazen - President and CEO: I think we always are looking for ways to improve the return to the shareholders, and I think we and I mean everybody in the company is committed to that and whatever actions, if we can find actions that are meaningful and are accretive to value, we'll do those things.
Operator: Leo Mariani, RBC.
Leo Mariani - RBC Capital Markets: It looks like you've certainly kind of gotten more optimistic on some of these new plays here in the Permian. I want to get a sense of how much of that is attributable to your recent cost reductions and how much maybe attributable just to better well performance.
Stephen I. Chazen - President and CEO: I think the key to Permian in my view is cost, repeatable low drilling cost. The change in the returns by these reductions is market. Bill you want to comment on the returns.
William E. Albrecht - VP, President, Americas, Oxy Oil & Gas: Across the plays that I've mentioned we're seeing solid 15%, 20% plus returns. As Steve said what's really been a big enhancing factor is what we've done to take dollars out of our cost structure there.
Stephen I. Chazen - President and CEO: The barrel, the IPs, the ultimate recoveries are same as our experience. But I think by driving the cost down, by returns we're not doing the IRR sort of returns to sort of more sustainable kind of returns, IRR has to do how fast you get your money back. So, I think, we're doing real well, we're very pleased with the progress in the Permian.
Leo Mariani - RBC Capital Markets: So just to clarify on the return, that's more of an after-tax corporate…
Stephen I. Chazen - President and CEO: Absolutely. Unfortunately, when you make a lot of money you pay a lot of taxes.
Leo Mariani - RBC Capital Markets: Okay. I guess just a question on California, you mentioned being able to reduce some of the cost by about $1.5 million per well, I think you said in Elk Hills and the shale program, sounds very substantial. Just trying to get a sense of how much that can improve your economic there?
Stephen I. Chazen - President and CEO: California, we're doing well. We've got more to go here in California. I think we're in the early phases of cost reduction in California. Again, people who work there are doing a fabulous job. So, I think we're trying to get the cost down to even lower sustainable levels before we boost the number of rigs that work, so we need to get our costs down to what we think is sustainable levels and which will be lower than we're showing here, and then we'll build the program up from there. But I think there's more room here. I am very optimistic about the capital, the well cost program, the 19% it would be disappointing if that's all it turned out of this.
Leo Mariani - RBC Capital Markets: In terms of your first quarter, you guys talked about 5,000 barrels a day internationally that you lost due to I guess production sharing contract payout. Just curious to whether or not there's going to be any further impact during 2013 from PSCs and projects that you have?
Stephen I. Chazen - President and CEO: I don't think much. I think we're probably at – for this year where we need to be – where we will be. Because you know, you got to go to another level of payouts. Pretty much the programs are – the big programs are pretty stable.
Operator: Arjun Murti, Goldman Sachs.
Arjun Murti - Goldman Sachs: Steve, just a follow-up on some of the California unconventional comments. I know the plan is to get some of the well costs down. I guess if we look back a few years ago and some of the early results, that relationship between costs and what look like could be the EURs and production per well was very, very favorable. Maybe the cost got a little bit higher and now you're trying to bring them back down. Can comment on what the well results look like and whether part of the issue here is just, maybe the geology is obviously different or not as robust as before – really any color around, again, I’m talking about the unconventional in California?
Stephen I. Chazen - President and CEO: I think – we haven't been able to drill where we wanted to drill all the time, and so some of its related to that and that has created some inefficiencies. The well cost got markedly higher than we would like. While didn't make them terrible, certainly sort (wasteful). So, I think, as far as results are concerned I think they are in line to what we said before IPs those sorts of things. We have shifted the focus to more conventional drilling to get more – less decline in the program was underlying decline because I think the decline is what we are trying to the fight against.
Arjun Murti - Goldman Sachs: The decline is unexpected. I mean, usually unconventional does come with quick declines or is it just…
Stephen I. Chazen - President and CEO: It has been, I think, more than we originally thought.
Arjun Murti - Goldman Sachs: Any update on the permitting process in California. I know it is always a challenge, but any improvement there at all?
Stephen I. Chazen - President and CEO: The permitting – I don't think this is North Dakota so I think the permitting process here continues to be – we've made a lot of progress in the last year or so and what also continues to be hard to predict from quarter-to-quarter basis so you get some good news, you get lots of good news. I think that we've built a program this year that doesn't rely on the permitting process to deliver the results. So, we'll be able to a deliver good set of results this year. I think low finding costs and reasonable growth. Hopefully, we'll build a backlog of permit so we can do the same thing next year, but at a higher level (indiscernible).
Arjun Murti - Goldman Sachs: And then just finally on the Bakken. It looks like the well cost have come down quite a bit this has always been an area for you guys where you've kind of been on the bubble of whether you are kind of in or out. It sounds like you are little more optimistic on the Bakken just now on kind of the right side of the return threshold or still more work to do in the Bakken?
Stephen I. Chazen - President and CEO: More work to be done.
Arjun Murti - Goldman Sachs: What kind of rig count you are looking at this year, Steve?
William E. Albrecht - VP, President, Americas, Oxy Oil & Gas: Arjun, this is Bill, it's 6. It should be between 6 and 7.
Arjun Murti - Goldman Sachs: Then…
Stephen I. Chazen - President and CEO: We are going to be able to obviously do more work with 6 or 7 rigs and we might have done last year with 9 or 10. So, the goal is to get the organization and the people to get more efficient with the rigs before you add more rigs because part of this gain or lot of this gain is having the best crews on the rigs. So, as you add the new – another rig, you may diminish the quality of the crew. So, the goal here is we are trying to make the company as efficient as possible before we do any major increase in spending.
Arjun Murti - Goldman Sachs: Then just lastly and I apologize for all the questions. With the stock cheaper than it once was, what is either your thought or your CFO's thought on stock buybacks and how excited or unexcited you are to do those at this point?
Stephen I. Chazen - President and CEO: Stock obviously is cheaper than it once was. We think that some stock buybacks are probably in our future.
Arjun Murti - Goldman Sachs: Can you quantify?
Stephen I. Chazen - President and CEO: No.
Operator: Paul Sankey, Deutsche Bank.
Paul Sankey - Deutsche Bank: Steve, in the past you've spoken about the difficulty in finding value from for example splitting the Company. Is that still the way you view things, that essentially with the stock having traded off and relatively cheaper. Could you now see the benefit of a Middle East/North America split?
Stephen I. Chazen - President and CEO: I think that's something that we consider all the time. Obviously the cheaper the stock, the more you have to look at other alternatives. So, valuing each pieces, maybe fairly straightforward to do the U.S., valuing the international standalone is really more complicated because there is not a lot of good comps. So I think that we'll look at everything, but obviously with the lower stock price things that might have not worked before might work now. There isn't many kind of forecast or anything, it's just sort of the tautology.
Paul Sankey - Deutsche Bank: I guess the other issue at the Middle East is it would politically somewhat difficult I imagine to for example sell the whole business?
Stephen I. Chazen - President and CEO: I think that generally if you went and sold individual countries, you would have to gain the consent of individual country, so if you want to sell -- some country, generally the contract requires somebody else to – the country to approve the sale. However, if the business was split off or something -- may not take so much effort.
Paul Sankey - Deutsche Bank: There's a lot of speculation around the potential for an MLP of the Midstream. Can you just talk a little bit how you see that?
Stephen I. Chazen - President and CEO: I think we look at virtually everything and we know shortage of suggestions. I think you start looking for things that move the needle a lot rather things to fine tune.
Paul Sankey - Deutsche Bank: What you mean, an MLP would be a fine tuning or would be…
Stephen I. Chazen - President and CEO: I think an MLP would be a fine tuning rather than a major mover. That's something one can think about over time. But MLP is hopefully low cost capital. So I mean presumably the play would be sell the MLP, take the proceeds and buy the shares. So, I – but we also can borrow 2.5%. So, you're looking for things that at least initially are things that move the needle a lot rather than we tweaking things. A tweak for example, we are selling our joint venture in Brazil and we'll get like $250 million or something like that for that, and so that will close here in a few weeks and we can use some of that money to reduce the share count. There's a lots of tweaky that one can talk about. First of all our focus is on things that really change value.
Paul Sankey - Deutsche Bank: I guess that would be selling the whole of oxy, while expensing it, right?
Stephen I. Chazen - President and CEO: While selling the whole of oxy that won't take many phone calls to find out if they are buyers. We don't want to hire a lot of investment bankers to study the call. So, I think that's an improbable outcome.
Paul Sankey - Deutsche Bank: What else is there needle moving, other than splitting?
Stephen I. Chazen - President and CEO: Well, I don't know but there may be other things. There may be assets we can sell that aren't contributing much to the business. I mean there are lots of things we could do that are different than just splitting and maybe even splitting doesn't move the needle, but first thing you need to focus on is what really matters and then you can focus on things to improve it slightly. But I think you don't want to go down the path of sort of delicate test and approach to this slice of piece of (indiscernible) and you throw it to the (indiscernible).
Paul Sankey - Deutsche Bank: The biggest risk on the stock no question is your future you really have to address this question of how long do you think is going to take to find us (indiscernible) and how much longer you are going to be doing this job?
Stephen I. Chazen - President and CEO: We are not going to answer that, I think the press releases and the board and our statements speak for themselves.
Paul Sankey - Deutsche Bank: A technical question if the Chairman and certain board members are not reelected how long is (indiscernible) place and how does that process work technically speaking?
Stephen I. Chazen - President and CEO: It's really a decision for the board to make it isn't something that you can read the proxy (indiscernible), but it's really a board decision.
Operator: Matt Portillo, Tudor Pickering Holt
Matthew Portillo - Tudor Pickering Holt: Just one additional question in terms of the potential for share repurchase. Could you talk a little bit about your capital structure and how you think about kind of the appropriate leverage for your balance sheet today? Just trying to get a better sense of how much capital you have to access on a potential share repurchase or other opportunities you are looking at to enhance shareholder value?
Stephen I. Chazen - President and CEO: I don't think we probably want to wander in the exact capital structure. For a commodity-based company, you need a strong balance sheet to withstand the ups and downs, so that you can react to opportunities that occur in an ugly market and then there are operations in the Middle East. It's very important, if you are going to sign for a long-term project 30 years or something like that, you have a solid balance sheet they believe you are going to around. That's sort of a qualitative view, what the exact number is I just don't know, but we have a lot of financial flexibility. We've got the very strong balance sheets for that.
Matthew Portillo - Tudor Pickering Holt: Then just two quick asset level questions. I was wondering if you could give us some color the Wolfbone sounds like a new player focusing on. If you could give us a little bit of color on how you are seeing well cost and potentially return the EURs there and then I have one quick follow-up on the Midstream side.
William E. Albrecht - VP, President, Americas, Oxy Oil & Gas: Matt, on the Wolfbone what we're seeing for at least for completed well cost including hook-up. We're in the $3 million to $3.5 million range in completed well costs.
Matthew Portillo - Tudor Pickering Holt: Then just the last question on the Midstream side of the business, you obviously saw a pretty significant uptick in operating profit for the quarter. Just trying to get a little bit better sense of how we should think about that that midstream and marketing and trading part of that business to $100 million you guys generated there and how that should trend over the rest of the year? Or how volatile that may be as we move into the second and third quarter?
Stephen I. Chazen - President and CEO: We'll start with what we're saying. Willy will answer the question, but you should view it as volatile. Go ahead Willy.
William E. Albrecht - VP, President, Americas, Oxy Oil & Gas: I think you saw last year's number we were kind of in the low 400s. And as Steve said a lot of wells for the whole year and a lot of what we do rides on arbitrage opportunities and market prices. We keep reinforcing that one of our key roles is to make sure everything that we produce gets access to the highest markets. So we've done things like renegotiate contracts to uncouple them from things like WTI. You'll see us take a lot more capacity and pipelines to get out of constrained areas, particularly the Permian. If you look at our first quarter results, a lot of that was due to the arbitrage opportunity between Permian and the Gulf Coast, it's because of our storage capacity that we had as well as transport capacity allowed us to capture that. So, we hope we can maintain that pace going forward, but again a lot of is (marketing based).
Stephen I. Chazen - President and CEO: Very little of it was from the Phibro operation. Almost all of the gain was from gas plants and arbitrage between -- with our capacity to move oil around. So instead of showing up in the Oil segment because it wasn't our oil, it shows up in the segment.
Operator: Faisel Khan, Citigroup.
Faisel Khan - Citigroup: I was wondering if you could go back in the California a little bit and discuss the CapEx trends there. So I guess in the middle of the year, you were trending at about $550 million in CapEx a quarter and now you're down to close to $300 million in CapEx. Is this the new trend through the year?
Stephen I. Chazen - President and CEO: I think we're budgeting $1.5 billion in California this year.
Faisel Khan - Citigroup: So then, we should see that number sort of pick up as we get into end of the year…
Stephen I. Chazen - President and CEO: That's right, actually all of the capital. We had a slow start in spending this year, not all bad by the way. So we had a slow start everywhere. The costs are coming down and you'll see the capital spending go to the 9.6-ish level for the year for the whole Company. So we'll start to see a pick-up of it in the second and third quarters.
Faisel Khan - Citigroup: Then, I want to go back to also a comment you made earlier. You said that some of the declines you were seeing in California were higher than what you expected initially. Is that what resulted in the reserve revision you guys took in the 10-K?
William E. Albrecht - VP, President, Americas, Oxy Oil & Gas: The reserve revision largely was a single, old -- a conventional oil part of Elk Hills field, and it has a different kind of production driver. The wells there have declined more than we thought, but it's not conventional. So it fell off the curves, so we took the write-down on the reserves, but it's not unconventional, it's not really a shale it's a reservoir that's probably been producing almost 100 years, and will probably produce for another 100 years.
Faisel Khan - Citigroup: And then just if you could do on the rig count, it's been kind of bouncing around the last year or two. You were at kind of 50 rigs on average in '11 and then you were at 60 somewhat rigs on average for 12 and then by the end of the year you were at 41 rigs. So what's the trend for this year?
Stephen I. Chazen - President and CEO: We believe 55 rigs.
William E. Albrecht - VP, President, Americas, Oxy Oil & Gas: Yeah, in the Americas, 50 to 55, pretty stable.
Faisel Khan - Citigroup: So I’m just trying to reconcile that with the 10-K where you talk about 41 rigs at the end of the year, so you were seeing…
Stephen I. Chazen - President and CEO: At any time, these rig numbers, how many you have. We answered it almost too truthfully. And so it's exactly what it is that day or the day before, and it could be three rigs or four rigs higher or lower the next day. So, I wouldn't make too much of the exact number.
Faisel Khan - Citigroup: The last question in terms of – if I look at the year-over-year growth in volumes in the lower 48, how much would you say the volume growth was attributed to the acquisitions you made last year?
Stephen I. Chazen - President and CEO: A little bit. We made a gas acquisition in California at the end of the last year. So I think some of that was California and then a little bit elsewhere, but it's very hard, most of what we acquired was spud locations.
Operator: Sven del Pozzo, HIS.
Sven del Pozzo - HIS: I'm trying to quantify – I know it's hard question to answer because it's driven by third-party operators, but how much do you budget for right at the $1.9 billion and you said two-thirds of $1.9 billion in CapEx in the Permian in non-CO2 businesses?
Stephen I. Chazen - President and CEO: That's right.
Sven del Pozzo - HIS: How much…
Stephen I. Chazen - President and CEO: 600 and 1.3, as I remember.
Sven del Pozzo - HIS: That would be operated versus non-operated, but…
Stephen I. Chazen - President and CEO: No, that's total. The CO2 business is almost all are operated. The 1.3 include some of the non-operated ones. We have to estimate that number. Obviously, it's not our choice.
Sven del Pozzo - HIS: So, in relation to that non-operated estimate, I was wondering what kind of exposure you have to non-operated wells and I would imagine with cost-cutting efforts going on that perhaps you might decline to participate in third-party wells and how much exposure do you have to third-party business in the Permian?
Stephen I. Chazen - President and CEO: We clearly have some. It might decline. Generally the result what I'd I like to have from them is the results they told the Street, rather than the (AFEs) we see.
Sven del Pozzo - HIS: Would it be possible to quantify of your 1.7 million net acres that you consider prospective for these emerging plays. How much of that is non-operated acreage and how much is operated?
Stephen I. Chazen - President and CEO: I don't think we could do that here on the phone. You can see the gross and net. We show you gross and net, so you get some idea of our percentage. So, that may help you some, but we don't actually keep our records that way.
Sven del Pozzo - HIS: I saw 2.5 million net acres in the Permian on your website for the total acreage number. Does that include what you acquired in Reeves County? Was that last year for the Wolfbone stuff?
Stephen I. Chazen - President and CEO: Whatever they are on 12/31.
Sven del Pozzo - HIS: Then there were just some comments, I'm just looking over the fourth quarter call that talked about CO2 maintenance might that, is that on the horizon or has it already -- have we already seen the mains in the first quarter?
Stephen I. Chazen - President and CEO: Bill will answer that.
William E. Albrecht - VP, President, Americas, Oxy Oil & Gas: Yes. We've got one of our major CO2 recycling plants getting ready to undergo turnarounds. It's going to start I think next Saturday, last about two weeks.
Operator: Pavel Molchanov, Raymond James.
Pavel Molchanov - Raymond James & Associates: Just one more on the cost side. I mean clearly you are running ahead of schedule on your cost reductions, but since the end of the quarter, we've seen WTI and Brent both coming down about $10. What would it take for you to accelerate or let's say upsize your cost reduction target for the year?
Stephen I. Chazen - President and CEO: We might to do it internally, but it will be -- we'll show you actuals.
Pavel Molchanov - Raymond James & Associates: Anecdotally, have you seen some softening across the value chain in the last let's say four-weeks?
Stephen I. Chazen - President and CEO: You are talking about costs?
Pavel Molchanov - Raymond James & Associates: Yes.
Stephen I. Chazen - President and CEO: We contract on a longer basis on that. Certainly, the cost from suppliers is -- what their charging has come down, but we don't do a lot of daily sorts of activities. Most of our stuff is contracted for a period. So it's really hard for us to tell about the last month.
Pavel Molchanov - Raymond James & Associates: Okay. Fair enough. I'll take that offline. Thanks.
Stephen I. Chazen - President and CEO: Thank you. Chris?
Christopher G. Stavros - VP, IR: Thanks very much for joining us today. If you further questions, please call us here in New York. Thanks again. Have a good day.
Operator: Thank you. This does conclude today's conference call. You may now disconnect.