Earnings Call: Q1 2013

Apr 25, 2013

Good afternoon. My name is Christie and I will be your conference operator today. At this time, I would like to welcome everyone to Occidental Petroleum's 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. Thank you, Christy, and good morning and welcome everyone and thank you for participating in Occidental Petroleum's Q1 2013 earnings conference call. Joining us on the call this morning from Los Angeles are Steve Chasen, OXY's President and Chief Executive Officer Cynthia Walker, our Chief Financial Officer Bill Albright, the President of Oxy's Oil and Gas Operation in the Americas Sandy Lowe, President of our International Oil and Gas Business and Willie Chang, our EVP of Operations and Head of Oxy's Midstream Business. 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 Q1. Steve Chasen will then follow with an update on the progress we're making toward our ongoing efforts to improve our oil and gas operating costs 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 Q2. A highlight of this quarter's conference call will be an in-depth discussion from Bill Albright focusing on our non TiO2 drilling program in the Permian Basin and additional details on our drive to improve capital and drilling efficiency and reduce our operating costs 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 Q1 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. Thank you, Chris, and good morning, everyone. Core income for the quarter was 1,400,000,000 dollars or $1.69 per diluted share in the Q4 of this year excuse me, the Q1 of this year, compared with 1,600,000,000 dollars or $1.92 per diluted share in the Q1 of 2012 and $1,500,000,000 or $1.83 per diluted share in the Q4 of 2012. Compared to the Q4 of 2012, the 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 turnarounds and higher DD and A rates. I'll now discuss the segment breakdown. Oil and Gas core earnings for the Q1 of 2013 were $1,900,000,000 compared to $2,500,000,000 in the Q1 of 2012 $2,300,000,000 in the Q4 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 and A rates. Our sales volumes in the Middle East North Africa were lower compared to the Q4 of 2012 due mostly to the timing of liftings as well as the effect of the maintenance turnarounds in Qatar and full cost recovery under a contract in Oman. This reduced our 2013 Q1 earnings by about $200,000,000 after tax compared with the Q4 of 2012. Costs associated with the turnarounds, pipeline disruptions in Colombia and other factors further reduced our earnings by about $30,000,000 after tax. Combined these factors reduced oil and gas segment earnings by approximately $450,000,000 on a pre tax basis. Oil and gas production costs were 13.93 dollars per barrel for the 1st 3 months of 2013 compared to $14.99 per barrel for the full year of 2012. Production costs at this level already beats our previous full year 2013 guidance. The lower costs were attributable to our domestic operations where production costs were $3.37 per barrel lower in the Q1 of 2013 from the full year of 2012. In 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 Cutter North Dome and South Dome fields and to a lesser extent the planned turnaround in Dolphin. Q1 2013 total daily production on a BOE basis was 763,000 barrels, which was 16,000 barrels per day lower than the Q4 of 2012 and 8,000 barrels per day higher than the Q1 of 2012. Approximately 13,000 barrels of the total sequential decrease in the quarterly production came from Cutter and Dolphin where the planned maintenance impacted production. I'm pleased to say the turnarounds were executed successfully and production has returned to normal levels. Our domestic production was 478,000 barrels per day, an increase of 3,000 barrels per day from the Q4 of 2012 and this now marks the 10th consecutive quarterly domestic volume record for the company. Production was 5% higher than the Q1 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 4th quarter reflecting the 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 mainly in the Permian and Williston. Latin America volumes were 31,000 barrels per day, which was 1,000 barrels lower compared to the 4th quarter 5,000 barrels higher than the same period in 2012. The reduction from last quarter was due to heightened level of 20,000 barrels from the Q1 of 2012. The planned maintenance turnarounds in cutter reduced our production 13,000 barrels per day. The impact of full cost recovery and other factors affecting production sharing and similar contracts reduced 1st quarter production volumes by an additional 5,000 barrels per day compared to the Q4 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 1st quarter due to the timing of liftings. 1st quarter realized prices were mixed for our products compared to the Q4 of 2012. Our worldwide crude oil realized price was $98.07 per barrel, a 2% increase from the 4th quarter, while worldwide NGLs were $40.27 per barrel, a decrease of about 11% and domestic natural gas prices were were lower than the prior year Q1 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 Q1 of 2012, the comparable percentages were 105 percent of WTI, 91% of Brent for oil and 51% of WTI for NGLs and 100 percent of NYMEX for gas. At current global prices, a dollar per barrel change in oil prices affects our quarterly earnings before income taxes by $37,000,000 $7,000,000 for $1 per barrel change in NGL prices. The change in domestic gas prices of $0.50 per 1,000,000 Btu affects quarterly pre tax earnings by about $30,000,000 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 Q1 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. 1st quarter exploration expense was 50,000,000 dollars We expect Q2 2013 exploration expense to be about $100,000,000 for seismic and drilling in our exploration programs. Chemical segment earnings for the Q1 of 2013 were $159,000,000 compared to $180,000,000 in Q4 of 2012 $184,000,000 in the Q1 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 Chemicals segment 2nd quarter 2013 earnings are expected to improve to about $170,000,000 benefiting from higher seasonal demand in the construction and agricultural markets. Midstream segment earnings were $215,000,000 for the quarter compared to 2013 excuse me for the Q1 of 2013 compared to $75,000,000 in the Q1 of 2012 $131,000,000 in the Q1 of 2012. Over 70% of the 2013 sequential quarterly increase in earnings resulted from improved marketing and training 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 Q1 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 40 1%. In the 1st 3 months of 2012, we generated $2,900,000,000 of cash flow from operations before changes in working capital. Working capital changes reduced our cash flow from operations by about $200,000,000 to $2,700,000,000 Capital expenditures for the Q1 of 20 13 were $2,100,000,000 This capital spend was $440,000,000 lower than the Q4 of 2012 with about half of the decrease in the oil and gas business. 1st 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 $2,100,000,000 cash balance at the end of March. The weighted average basic shares outstanding for the 3 months of 2013 were 804,700,000 and the weighted average diluted shares outstanding were 805,200,000. We had approximately 805,600,000 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 1st 3 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 Q2 of the year. Thank you, Cynthia. Occidental's domestic oil and gas segment produced record volumes for the 10th consecutive quarter and continued to execute on our liquids production growth strategy. 1st quarter domestic production of 478,000 barrel equivalents per day consisting of 342,000 barrels of liquids, 817,000,000 cubic feet of gas per day was an increase of 3,000 barrel equivalents per day compared to the Q4 of 2012. We are executing a focused drilling in our core areas and today 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 is difficult. Our goal is to sustain the benefits realized to date, achieve additional savings in our drilling costs and reach our 20 11 operating cost level over time without a loss in production or sacrificing safety. Purpose of these initiatives is to improve our return on the capital and operational efficiencies initiatives that we have implemented. Thank you, Steve. This morning, I'd like to share with you the 3 main objectives of our 2013 domestic program. 1st, delineate our core or anchor drilling areas in the Permian Basin. We've accumulated more than 1,700,000 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. 2nd, drive capital efficiency, particularly in our core drilling programs. We believe that the results of our capital efficiency And third, enhance our cash margins through operating expense reductions. Turning now to our first objective, our Permian Basin activity. As we 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 $1,900,000,000 in the Permian. Approximately 2 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 4 plays: the Wolfberry, Yeso, Delaware Sands and Wolf Bone. The Wolf Barry 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 100 of Wolf Ferry 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 Taishan 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 a result in 2013, we expect to increase drilling activity by 30% from 2012 levels. The Wolf Bone 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 will increase our activity this year as we further delineate our acreage position. Because of the multi pay nature of the play, wells will be vertical at this stage, although we'll drill a number of horizontal wells and 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 Wolf Bone 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 4 core programs, we believe we have opportunities in several 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 improving operational execution and improving our contracting strategies. We're measuring progress by comparing our 2013 well costs to 2012 using the 2013 program attributes. In other words, for our benchmark year of 2012, we're using costs 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 a 19 percent 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 4 elements in more detail. 1st, 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 2 to 3 months in advance depending on location across all our assets. Consequently, we've reduced our rig down times 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 2 strings of casing instead of 3, which has saved approximately $250,000 per well. We've also reduced costs by 47% per frac stage per Wolf Barry well without any degradation in production. At Elk Hills in our anchor shale program, we're running mostly slotted liners instead of cemented liners, saving $1,500,000 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're 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 3rd element improving operational execution. While we're 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're drilling have been trouble free, particularly due to improved directional tool reliability. And finally, we've made a fundamental change in the way and the extent to which we use contractors and outside consultants to manage and supervise our drilling 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've reduced our stimulation contract pricing. We've also reduced our fluid hauling costs by implementing a trucking cluster concept whereby certain trucking fleets are dedicated to specific core areas. Overall, we've improved our completed well costs in the Williston from an average $10,000,000 per well as recently as just 4 months ago to $8,200,000 currently. We believe that we're now top quartile in well costs in the play and our current goal is to bring average Williston well cost down to $7,500,000 We believe at this level we'll 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 $3,500,000 to $2,600,000 Lastly, I'd like to discuss the 3rd 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've 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'd like to share a few examples with you of the actions we've taken toward achieving our goal. First, in order to optimize our well servicing rig costs, we're eliminating inefficient workover rigs. While this has caused an overall decline in our workover rig count, we're finding that through better planning and scheduling, we're 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 fall off from these reductions. 2nd, 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. 3rd, we're 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. 4th, we're 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 costs of these supplies and services. In addition, we're working on optimizing our use of injectants in energy. For example, we're improving our CO2 and steam utilization through ongoing pattern surveillance and evaluation of injectant to oil recovery ratios and we're 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 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 Q1 of 2013. We believe our ongoing efforts will yield additional improvements 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 a minimum of $450,000,000 While we've made progress in both our capital efficiency and operating cost reduction efforts, we're 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 Q1. Nonetheless, given our results to date and our people's effort in this endeavor, we're optimistic we can sustain and further improve upon the results achieved today. 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. Thank you, Bill. With regard to the total return to shareholders in February, we increased our dividend by 18.5 percent 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, a total of 12 times during that period. This 18.5% increase brings 11 year compounded dividend growth rate to 16% per year. I will now turn to 2nd quarter outlook. Production domestically, we continue to expect solid growth in our oil production for the year as a result of nature and timing of our drilling such as steam flood drilling in California. We expect 2nd quarter liquids growth to be modest with higher growth coming in the second half of the year. We just received word today that we've got permits for 3 new compressors for our steam flood program. 1 is already on. So I think we're going doing well in California on this, just a slow start this year. In the Q1 of 2013, our base gas production did not decline as much as we had initially expected. Estimating production for the rest of the year still remains challenging. We expect to see modest declines in our gas 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 Q2 back to around the Q4 with the increase coming mainly from resumption of production in Qatar. 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 4th quarter levels based on our current lifting schedule. Our first quarter capital spend was $2,100,000,000 We expect the 2nd quarter rate to be higher. Our annual spending level is unchanged and expected to be in line with the $9,600,000,000 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 financial goals. I'm very pleased that employees at all levels have stepped up 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've stated before, I remain committed to staying through the succession process. We're now ready to take your questions about the performance of the business. However, we do not have anything to add announcements about the ongoing Board activities and succession process. Thank you. And your first question comes from Doug Tarson of ISI. Congratulations on your results everybody. Thank you. The people in the company did a great job. They sure did. So my question regards the sequential decline in earnings of $450,000,000 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 relates to factors that are not normally recurring like maintenance and pipeline disruptions and lifting variances etcetera? I think Cynthia has that variance. So let her answer. Yes, sure. Thanks, Doug. Really the only component of the quarter over quarter decline that we expect to be recurring is the Oman contract impact, which is about $50,000,000 of the $450,000,000 The rest of it all relates to timing of liftings as well as the cutter turnaround, which you mentioned cutter turnarounds and the pipeline disruptions in Colombia. Okay, great. Thanks a lot. Thank you, Doug. Your next question comes from Doug Leggate of Bank of America. Thanks. Good morning, everybody. I've got 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. It looks to me at least that the international costs were up a couple of maybe $2 to $3 a barrel. That's right. 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 the operating costs? And I've got a follow-up please. We'll let Cynthia give you the first part and I'll answer the second part. So where does that put our run rate? Yes. In the second quarter, there will be some 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 Q1 will come into the Q2. I think in terms of the In terms of the I think in terms of the Pardon me? Pardon me? Sorry? Sorry. We expect that the U. S. Business let me just maybe simplify it a little bit for you. We expect the U. S. Business to we're going to be cautious on the operating costs here to make sure we're not affecting safety and production. So we expect those costs to continue to go down, but obviously not as quickly as it did in this quarter. 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 in the turnarounds, we'll increase the reliability and we should actually do better on a gross basis. There may be some turnaround costs and stuff that will roll through I think was what Cynthia was referring to. The fundamental numbers will be lower. There might 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? Yes. Doug, the in Qatar, we are actually producing at record levels over the past since the past few years of $118,000 $119,000 gross and the actual extra money we've spent on the turnaround that we've got much higher reliability. We have records in Oman right now of 335, actually are reducing OpEx per barrel there, but still paying attention to production reliability and safety issues. We'll give you more answer than your thought I guess so. No. That's very helpful. Steve, my follow-up and I hope you're going to forgive me for this one ahead of time. I realize you don't I'm very I've become more and more forgiving in my old age. Okay. I realize you don't want to talk about the Board situation. However, my question really relates to you in terms of your intentions. When we've traveled in the past, you've always stated that you saw yourself being in position for quite a while and executing a strategy that ultimately took you towards 1,000,000 barrels a day. Should we rule out the possibility of you staying around a bit longer if the Board for example had a change of heart? And what is your strategic vision for the company longer term? I'm not going to answer the first question. I 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. I mean every day I'm sort of happy to talk about the operations. And I think the company is doing real well. I think we'll continue to grow nicely. You have little bumps in the road in the quarter, but fundamentally I really couldn't be happier about the progress we're making as a company. The 1,000,000 barrels a day, I think is a reasonable objective. What we're going to do from call to call is, while Bill got to talk this time, we'll let somebody else talk next quarter and maybe we'll talk about California next quarter and 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 is right now is sort of that one. So I if unless you want to ask the same question another way. Well, I'm just saying, would you ever see that there's been a lot of speculation about structural changes whether it was separating one part or another whether it be MLPs or whether it be California getting split off. Is that something that even enters into discussion right now? Or is it just not on the table? 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. All right. I'll leave it at that. Thanks, Steve. Thank you. Thank you. Your next question comes from Leo Mariani of RBC. Hey, guys. I mean, it looks like you've certainly kind of gotten more optimistic on some of these new plays here in the Permian. I to get a sense of how much that is attributable to your recent cost reductions and how much may be attributable just to better well performance? I think the key to the Permian in my view is cost, well repeatable low drilling costs. And the change in the returns by these reductions is marked. Bill, you want to comment on the returns? Yes. Leo, across the plays that I mentioned, we're seeing solid 15%, 20% plus returns. And 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. So the barrel, the IPs, the ultimate recoveries are the same as our experience. But I think by driving the cost down by returns, we're not doing the IRR sort of returns just sort of more sustainable kind of returns. IRRs have 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 at this point. Okay. So just to clarify on the return that's more of an after tax corporate? Absolutely. Oh, yes. Unfortunately when you make a lot of money you pay a lot of taxes. Okay. And I guess just a question on California. You mentioned being able to reduce some of the costs by about $1,500,000 per well. I think you said in Elk Hills and the shale program. It sounds very substantial. Just trying to get a sense of how much that can improve your economics there? California, we're doing well. We continue we've got more to go here in California. I think we're in the early phases of cost reduction in California. Again, the people that work there are doing a fabulous job. And so I think we're trying to get the cost down to even lower sustainable levels before we boost the number of rigs at work. So we need to get our cost down to what we think is sustainable levels, 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'm very optimistic about the capital, the well cost program, the 19%. It would be disappointing if that's all that turned out of this. Okay. That's really helpful. And I guess in terms of your Q1, 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 hitting payout? I don't think much. I think we're probably at work for this year where we need to be where we'll be. Because you got to go to another level of payouts. Pretty much the programs are the big programs are pretty stable. Okay. Thanks a lot. Thank you. Your next question comes from Arjun Murti of Goldman Sachs. Thanks. 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 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. Now you're trying to bring them back down. Can you comment on what the well results look like? And whether part of the issue 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? Yes. I think it's we haven't been able to drill where we wanted to drill all the time. And so some of it's related to that and that's created some inefficiencies. And the well cost got markedly higher than we would like. And while it didn't make them terrible, certainly sort of wasteful. So I think as far as the results are concerned, I think they're in line with what we said before IPs those sorts of things. But we have shifted the focus to more conventional drilling to get more less decline in the program with underlying decline because I think the decline is what's what we're trying to fight against. With the decline unexpected? I mean usually unconventional does come with quick declines or is it just It's been I think more than we originally thought. Yes. Got it. Got it. Any update on the permitting process in California? I know it's always a challenge, but any improvement there at all? 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 but also continues to be hard to predict from a quarter to quarter basis. So you get some good news. You get some not so good news. I think that we've built a program this year that doesn't rely on the permitting process to deliver the results. Yes. And so we'll be able to deliver a good set of results this year, I think low finding costs and reasonable growth. Hopefully, we'll build a backlog of permits so we could do the same thing next year, but at a higher level of spending. Yes. And then just finally, thank you. On the Bakken, it looks like the well costs have come down quite a bit. This has always been an area for you guys where you've kind of been on the bubble whether you were kind of in or out. Sounds like you're a little more optimistic on the Bakken. Is this now on kind of the right side of the return threshold or mean, at there this year Steve? Yes. Arjun this is Bill at 6. Should be between 6 and 7. Got it. We're going to be able to obviously do more work with 6 or 7 rigs than we might have done last year with 9 or 10. Yes. So I'm 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 a lot of this gain is having the best crews on the rigs. So as you add the new another rig, it may diminish quality of the crew. So the goal here is we're trying to make the company as efficient as possible before we do any major increase in spending. Yes. And then just lastly and I apologize for all the questions. Given That's okay. Yes. Thank you. 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 un excited you are to do those at this point? Stock obviously is cheaper than it once was. And we think that some stock buybacks are probably in our future. Good to quantify? No. That's fine. Thank you very much, Steve. Really appreciate it. Thank you. Thank you. Your next question comes from Paul Sankey of Deutsche Bank. Hi. Good morning, everybody. Good morning. Hi, Steve. 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 the Middle East North America split? Thanks. 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. And so valuing each piece is maybe fairly straightforward to do the U. S. Valuing the international standalone is really more complicated, because there's not a lot of good comps. So I think that we'll look at everything, but obviously with a lower stock price things that might not have worked before might work now. That isn't any kind of forecast or anything. That's just sort of a tautology. Yes. I've got you. I guess the other issue with Middle East is it would be politically somewhat difficult I imagine to for example sell the whole business. I think that generally if you went and sold individual countries, you would have to gain the consent of the individual country. So if you wanted to sell some country, generally the contract requires somebody else to the country to approve the sale. However, if the business were split off or something, it may not take so much effort. Yes. That makes sense. There's a lot of speculation around the potential for an MLP of the midstream. Can you just talk a little bit about how you see that? Thanks. Yes. I think we look at virtually everything and we know a shortage of suggestions. I think you start looking for things that move the needle a lot rather than things to fine tune? What you mean an MLP would be a fine tuning or would be a fine tuning? Yes. I think an MLP would be a fine tuning rather than a major mover. That's something one can think about over time. But an MLP is a hopefully low cost capital. So I mean presumably the play would be you sell the MLT take the proceeds and buy the shares. So I but we also can borrow at 2.5%. So I you're looking for things that at least initially are things that move the needle a lot rather than tweaking we're tweaking things. A tweak for example where we're selling our joint venture in Brazil And we'll get like $250,000,000 or something like that for it. And so that will close here in a few weeks and we can use some of that money to reduce the share count. But there's lots of tweaky things that one can talk about. But first of our focus is on things that really change value. Yes. Well, I guess that would be selling the whole of Oxy or splitting it, right? Well, selling the whole of Oxy that's that won't take many phone calls to line up to find out if they're buyers. Yes, right. 1 I think it's probably one call isn't it? Yes, one call. He probably not who knows? But so we don't want you to hire a lot of investment bankers to study the call. So I think that's an improbable outcome. Okay. So yes, it's basically I mean what else is the needle moving other than splitting? Well, I don't know. But there may be other things or maybe assets we can sell that aren't contributing to much of the business. I mean there's lots of things we could do that are different than just splitting. But I mean and maybe the splitting doesn't move the needle. But the first thing you need to focus on is what really matters. And then you could focus on things to improve it slightly. But I think you don't want to go down the path of a sort of a delicatessen approach to this where you slice a piece of baloney off and you throw it to the wolves. Listen, the biggest risk on this stock no question is your future. You really have to address this question of how long do you think it's going to take find a CEO and how much long are you going to be doing this job? I know. We're just not going to answer that. I think we've the press releases and the Board and our statements speak for themselves. Okay. A technical question. If the Chairman and certain Board members are not reelected, how long is it before they are replaced? And how does that process work technically speaking? It's really a decision for the Board to make. It isn't something that you could read the proxy and it tells. But it's really a Board decision. Okay, Steve. I'll leave it there. Thanks for your guidance. Thank you. Thank you. Your next question comes from Matt Portillo of Tudor, Pickering, Holt. Good afternoon. Hi. I think it's morning for us. Just a few It's always morning in California. 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're looking at to enhance shareholder value? I don't think we probably won't want to wander into 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're going to sign for a long term project 30 years or something like that, that you have a solid balance sheet that they believe you're going to be around. I don't know 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. Okay. Perfect. We've kept a very strong balance sheet for that. Perfect. And then just two quick asset level questions. I was wondering if you could give us some color. The Wolf Dome sounds like a new player focusing on. If you could give us a little bit of color on how you're seeing well costs and potentially returns or EURs there? And then I have one quick follow-up on the midstream side. Bill? Yes, Matt. On the Wolf Bone, what we're seeing for these are completed well costs including hookup. We're in the $3,000,000 to $3,500,000 range completed well costs. Thank you. And then just a last question on the midstream side of the business. You obviously saw a pretty significant that that midstream and marketing and trading part of that business, the $100,000,000 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 2nd Q3? We'll start with what we're saying. Willie will answer the question, but you should view it as volatile. Go ahead Willie. Sure Matt. I think you saw last year's number we were kind of in the low 400s. And as Steve said a lot of well 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 market. So we've done things like renegotiate contracts to uncouple them from things like WTI. You'll see us take a lot more capacity in pipelines to get out of constrained areas, particularly the Permian. And if you look at our Q1 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 that allowed us to capture that. So we hope we can maintain that pace going forward. But again a lot of it is market based. Sorry. Very little of it was from the Fibro 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 will show shows up in this segment. Thank you. Thanks. Thank you. Your next question comes from Faisal Khan of Citigroup. Thank you and good morning. Good morning. I was wondering if you could go back in to California a little bit and discuss the CapEx trends there. So I guess in the middle of the year you were trending at about $550,000,000 in CapEx a quarter and now you're down to close to $300,000,000 in CapEx. Is this a new trend through the year? I think we're budgeting $1,500,000,000 in California this year. Okay. So then we should see that number sort of pick up as we get into the 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 pickup of it in the second and third quarters. Okay. And 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. Was that is that what resulted in the reserve revision you guys took in the 10 ks? The reserve revision largely was a single old non conventional oil part of Elk Hills field. And it has a different kind of production driver. And the well well, 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 shale. It's a reservoir that's probably been producing almost 100 years and will probably produce for another 100 years. Okay. Understood. And then just if you could on the rig count, it's been kind of bouncing around the last year or 2. You were at kind of 50 rigs on average in 2011 and then you were at 60 some odd 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? We'll be at 50, 55 rigs. Yes. In the Americas, 50 to 55 pretty stable. Yes. Okay. So I'm just trying to reconcile that with the 10 ks where you talk about 41 rigs at the end of the year. So you're saying Yes. 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 3 rigs or 4 rigs higher or lower the next day. So I wouldn't make too much of the exact number. Okay, understood. And one last question for me. In terms of if I look at the year over year growth in volumes in the Lower forty eight, how much would you say the volume growth was attributed to the acquisitions you made last year? A little bit. We made a gas acquisition in California at the end of 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 PUD locations. Okay. Understood. Thanks for the time. Appreciate it. Thank you. Thank you. Your next question comes from Sandel Pozo of IHS. Yeah. Good morning. Good morning. I'm trying to quantify I know it's a hard question to answer because it's driven by 3rd party operators. But how much do you budget for rather $1,900,000,000 in the you said 2 thirds of $1,900,000,000 in CapEx in the Permian and non CO2 businesses? That's right. How much 600 and 1,300,000,000 as I remember. Oh, that would be operated versus non operated the No, no, no, no. That's total. The CO2 business is almost all are operated. The 1.3 includes some of the non percent includes some of the non operated ones. We have to estimate that number. Obviously, it's not our choice. Yes. And so in relation to that non operated estimate, I was wondering what kind of exposure you have to non operated wells. And I'd imagine with cost cutting efforts going on that perhaps you might decline to participate in 3rd party wells. And how much exposure do you have to 3rd party business in the Permian? We clearly have some. You might decline. What the generally the result what I'd like to have from them is the results they tell The Street rather than the AFEs we see. Would it be possible to quantify the of your 1 point 7,000,000 net acres and that you consider perspective for these emerging plays, how much of that is non operated acreage and how much is operated? I don't think we could do that here on the phone. Okay. Yes. You can see the gross in net. We show you gross in 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. Okay. The yes, I saw 2,500,000 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 Wolf Bone stuff? It's whatever is whatever there on twelvethirty one. Okay. And then there were just some comments and I was just looking over the Q4 call that talked about CO2 maintenance. Might that I mean is that on the horizon or has it already have we already seen the maintenance in the Q1? Okay. Bill will answer that. Yes, Sandler. We've got one of our major CO2 recycling plants getting ready to undergo a turnaround. It's going to start I think next Saturday, last about 2 weeks. All right. All right. Well, thanks everybody. Thank you. Chris? We have one last question. Okay. Thank you. And your final question comes from Pavel Molchanov of Raymond James. Hey, guys. Just one more on the cost side. I mean, clearly, you're 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? Well, we might do it internally, but it will be we'll show you actuals. Okay. And I mean, has anecdotally have you seen some softening across the value chain in the last, let's say, 4 weeks? You're talking about costs? Yes. Yes. We contract on a longer basis than that. Certainly the cost from suppliers is what they're charging has come down. And 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 to us to tell about last month. Okay. Fair enough. I'll take that offline. Thanks. Thank you. Chris? Thanks Chris? Thanks very much for joining us today. If you have further questions, please call us here in New York. Thanks again. Have a good day. Thank you. This does conclude today's conference call. You may now disconnect.