Occidental Petroleum's CEO Discusses Q1 2013 Results - Earnings Call Transcript

Seeking Alpha

Occidental Petroleum Corporation (OXY)

Q1 2013 Earnings Call

April 25, 2013 11:30 am ET

Executives

Chris Stavros – Investor Relations

Cynthia L. Walker – Executive Vice President and Chief Financial Officer

Stephen I. Chazen – President and Chief Executive Officer

William Albrecht – President

Sandy Lowe – Vice President

Analysts

Doug Terreson – ISI Group

Doug Leggate – Bank of America Merrill Lynch

Leo Mariani – RBC Capital Markets

Arjun Murti – Goldman Sachs

Paul Sankey – Deutsche Bank

Matthew Portillo – Tudor, Pickering, Holt & Co.,

Faisel Khan – Citigroup Global Markets

Sven del Pozzo – IHS Herold

Pavel Molchanov – Raymond James & Associates

Presentation

Operator

Good afternoon. My name is Christy 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. (Operator Instructions)

I would now like to turn the call over to Chris Stavros. Please go ahead.

Chris Stavros

Thank you, Christy 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 and Gas Operation in the Americas; Sandy Lowe, President of our International Oil and Gas Business and Willie Chiang, 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 first quarter. Steve Chazen will then follow with an update on the progress we’re making towards 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 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 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 filing. Our first quarter 2013 earnings conference call press release, investor relations supplemental schedules and conference call presentation slides, which refer to you 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 L. Walker

Thank you, Chris, and good morning, everyone. Core income for the quarter was $1.4 billion or $1.69 per diluted share in the fourth quarter of this year – 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 $1.83 per diluted share in the fourth quarter of 2012. Compared to the fourth quarter 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&A rates.

I’ll now discuss the segment break down. 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.

Cost associated with the turnarounds, pipeline disruptions in Columbia and other factors further reduced our earnings by about $30 million after tax. Combined with 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 costs 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.

In our Middle East/North Africa operations, operating cost increased by about $2.50 per barrel on a sequential quarterly basis. This increase was due to the plant maintenance turnarounds in our Qatar North Dome and South Dome fields, and to a lesser extent, the plant turnaround in Dolphin. The 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 plant maintenance impacted production. I am pleased to say the 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 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 [streamside] 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 fourth quarter and 5,000 barrels higher in 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 countries 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 $98.7 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 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.

The 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. Factors other than non-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 was $50 million. We expect second quarter 2013 exploration expense to be about $100 million for seismic and drilling in our exploration program. 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 and seasonal demand in the construction in agricultural markets.

Midstream segment earnings were $215 million for the quarter compared to 2013, excuse me, for the first quarter of 2013 compared to $75 million in the first quarter of 2012 and a $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. 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 with 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

Thank you, Cynthia. Occidental’s Domestic Oil and Gas segment produced record volumes for the tenth 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 with 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 years and today, we’re running ahead of our full-year objectives in our program to improve domestic operational and 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 costs below $14 a barrel for 2013.

While we are still in the early stages of this process in 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 costs level over time about 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 efficiency initiatives that we have implemented.

William Albrecht

Thanks 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 the 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, because 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 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, Delaware Sands and Wolfbone.

The Wolfberry has been a solid core play for many years in 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 mere the solid results we’re seeing in drilling 100s 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 a 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, whereas we’ll be mostly 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 Wolfbone and we’ve 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 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 costs to 2012 using the 2013 program attributes. In other words, for our benchmark year of 2012, we are using costs that we incurred for the same mix of well locations in types being drilled in 2013. By implementing all four elements, we’ve already achieved more than a 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 for 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 for Wolfberry well without any degradation in production. At Elk Hills and 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 the 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’re making numerous incremental changes in our day-to-day activities everywhere, we 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 flow back-end 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 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 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 and our current goal is to bring average Williston well cost down to $7.5 million. 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 formation. And another one of our anchor programs, the Wolfberry, we’re seeing sustained reductions in completed well costs, where costs are down from $3.5 million to $2.6 million.

Lastly, I’d 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’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 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 fall off 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’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. Fourth, 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 what is to recycle more of our produced water, reducing our sourcing as well as disposal cost 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’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 are reducing our energy costs through maximizing the use of self generated energy and rate renegotiations.

As a result of our efforts compared to 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 1000s of small ideas, suggestions and decisions being made everyday 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 million.

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 first quarter.

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 anyway 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

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, a total of 12 times during that period. This 18.5% increase brings the 11-year compounded dividend growth rate to 16% per year.

I’ll 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 our drilling such as steam flood drilling in California. We expect second quarter liquids growth to be modest, the higher growth coming in the second half of the year.

We just received word today that we’ve got permits for three new capacities for our steam flood program, one is already on. So I think we’re going, doing well in California on this, just a slow start this year. The first quarter of 2013, our base gas production did not decline as much as we had initially expected.

Estimating for the eruption for the rest of the year still remains challenging. We expect to see modest declines in our gas production, the result of our reduced drilling on gas properties and natural decline, as well as a number of gas plants turn around 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 from 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 in the last call. As you can see the business is doing well and we are continuing to make progress in our operational and financial goals. I’m very pleased that employees at all levels have stepped up to the challenges we presented to them and are focused on their jobs. We’ve not seen any significant negative turn over trends in our workforce. As I 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 beyond our public announcements about the on going Board activities and succession process.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) And your first question comes from Doug Terreson of ISI Group

Doug Terreson – ISI Group

Congratulations on your results, everybody.

Stephen I. Chazen

Thank you, the guys, the people in the company did a great job.

Doug Terreson – ISI Group

They sure did. 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 components, which is likely to be transitory meaning some of the elements were identified, but how much of sequential decline relates to factors that are not normally recurring like maintenance and pipeline disruptions and lifting variances et cetera?

Stephen I. Chazen

I think Cynthia has that variance, so let her answer.

Doug Terreson – ISI Group

Okay.

Cynthia L. Walker

Yeah, 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 million of the $450 million, the rest of it all relates to timing of liftings as well as the Qatar turnaround, which you mentioned Qatar’s turnarounds and the pipeline disruptions in Columbia.

Doug Terreson – ISI Group

Okay, great. Thanks a lot.

Cynthia L. Walker

Thank you, Doug.

Operator

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

Doug Leggate – Bank of America Merrill Lynch

Thanks, good morning, everybody.

Stephen I. Chazen

Good morning.

Doug Leggate – Bank of America Merrill Lynch

I’ve got a couple if I may, Steve. On the cost fees, if I look at the cost on the U.S., you obviously broke that out for us and I think your commentary about the total company. It looks to me at least the international cost was up a couple of maybe $2 to $3 a barrel.

Stephen I. Chazen

That’s right.

Doug Leggate – Bank of America Merrill Lynch

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 (inaudible) on the operating cost and I’ve got a follow up.

Stephen I. Chazen

We’ll let Cynthia give you the first part and I’ll answer the second part. So what is that run rate?

Cynthia L. Walker

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

[Multiple Speakers]

Cynthia L. Walker

Sorry?

Doug Leggate – Bank of America Merrill Lynch

Sorry.

Stephen I. Chazen

We expected that the U.S. business makes maybe some profile for you. We expect the U.S. business to – we are going to be cautious on the operating cost here to make sure we are not affecting safety in production. So we expect those costs to continue to go down, but obviously not as quickly as it did in this quarter. So the international costs will come back into line. They were up this past quarter, but we think they will be down next quarter. Yeah, and by putting money into the – what we’ve done is turnarounds to increase the reliability and we should actually do better on a gross basis.

There maybe some turnaround costs and stuff that will roll through I think it’s what Cynthia was referring to. The fundamental numbers will be lower, there might, again, there might be some additional turnarounds not in the Middle East, but in the U.S. Sandy, do you want to comment on the Middle East?

Sandy Lowe

Yeah, Doug, in Qatar, we are actually producing to record levels over the past – since the past few years of 118,000, 119,000 barrels and the actual extra money we spent on the turnaround that we get 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, but still paying attention to production reliability and safety issues may give you more answer on your thought I guess, sir.

Doug Leggate – Bank of America Merrill Lynch

No, that was very helpful. Steve, my follow-up, and I hope you’re going to forgive me for this one ahead of time. I realized you don’t…

Stephen I. Chazen

I’m very – I’ve become more forgiving in my old age.

Doug Leggate – Bank of America Merrill Lynch

Okay. I realized you don’t want to talk about the Board situation, however, my question relates to you on – in terms of your intentions. When we followed in the past, you’ve always stated that you saw yourself being in position for a quite a while and executing a strategy that ultimately took you towards the million barrels a day. Should we rule out the possibility of you staying around a bit longer just the Board, for example, had a change of heart? And what is your strategic vision for the company in longer-term?

Stephen I. Chazen

I’m 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. 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. We 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 million barrels a day, I think is a reasonable objective. What we’re going to do, Paul, the call is well, Bill would like to talk this time, we’ll let somebody else talk next quarter, and maybe we’ll talk about California next starter and have Vicky 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 sort of that one. So unless you want to ask the same question another way.

Doug Leggate – Bank of America Merrill Lynch

Well, I’m just thinking, would you ever see the – there’s more, the speculation about structural changes for separating one par or another whether it be MLPs or whether it be California getting split off, is that something that even enters into the discussion right now or is it just not on the table?

Stephen I. Chazen

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.

Doug Leggate – Bank of America Merrill Lynch

All right. I’ll leave it at that. Thanks, Steve.

Stephen I. Chazen

Thank you.

Operator

Thank you. Your next question comes from Leo Mariani of RBC.

Leo Mariani – RBC Capital Markets

Hi, guys. And it looks like you’ve certainly kind of gotten more optimistic on some of these new plays here in the Permian. Wanted to get a sense on how much that is attributable to your recent cost reductions and how much maybe attributable just to better well performance?

Stephen I. Chazen

I think the key to the Permian in my views is costs, repeatable low drilling costs. And that the change in the returns by these reductions is market. Bill, you want to comment on the returns?

William Albrecht

Yeah. Leo, across the plays that I’ve mentioned, we’re seeing solid 15, 20 plus percent 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.

Stephen I. Chazen

So the better – the ITs, the ultimate recoveries, same as our experience. But I think by driving the cost down – by returns we’re not doing the IRR sort of returns. This is sort of more sustainable kind of returns. IRR has to do with how fast you get your money back. So I think we’re doing real well. We’re very please with the progress in the Permian Basin.

Leo Mariani – RBC Capital Markets

Okay. So just to clarify on the returns, that’s more of an after tax corporate…

Stephen I. Chazen

Absolutely, yeah. Unfortunately when you make a lot of money, you pay a lot of taxes.

Leo Mariani – RBC Capital Markets

Okay. And I guess just a question on California; you mentioned being able to reduce some of the costs by about $1.5 million for a 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 economic there?

Stephen I. Chazen

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. But people who 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.

Leo Mariani – RBC Capital Markets

Okay, that’s really helpful. And I guess, in terms of the first quarter, you guys talked about 5000 barrels a day internationally that you loss (inaudible) and get production sharing contract payout, just curious to whether or not there’s going to be any further impact during 2013 from PSCs and project that you have?

Stephen I. Chazen

I don’t think much. I think we’re probably at, for this year where we need to bid and what won’t be. As you know, you’ve got to go to another level of payouts pretty much the program are – the big programs are pretty stable.

Leo Mariani – RBC Capital Markets

Okay. Thanks a lot.

Operator

Thank you. Your next question comes from Arjun Murti of Goldman Sachs.

Arjun Murti – 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 you look back a few years ago and some of the early results, the relationship between costs and what look like could be the EURs and production per well was very, very favorable. Maybe the costs got a little bit higher, now you are trying to bring them back down. Can you comment on what the wells 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 and again talk about the unconventional in California?

Stephen I. Chazen

Yeah, I think that’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 costs got markedly higher than we would like and didn’t make them terrible, certainly sort of wistful. So I think as far as the results are concerned, I think they are in line with what we said before of IPs sorts of things. But we have shifted the focus to more conventional drilling to give more or less decline and the program was underlying decline, so I think the decline is what we’ll be trying to fight against.

Arjun Murti – Goldman Sachs

With the declines unexpected I mean usually unconventional does come with quick declines, or is it just…

Stephen I. Chazen

It’s been I think more than we originally thought.

Arjun Murti – Goldman Sachs

Yeah, got it. Got it. Any update on the permitting process in California, I know it’s always a challenge that – any improvement there at all?

Stephen I. Chazen

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.

Arjun Murti – Goldman Sachs

Yeah.

Stephen I. Chazen

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 will build a backlog of permit, so we could do the same thing next year but at a higher level of spending.

Arjun Murti – Goldman Sachs

Yeah. 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 of whether you are kind of in or out. It sounds like you are little optimistic on the Bakken, is this now on kind of the right side of the return threshold or still more work to do in the Bakken?

Stephen I. Chazen

More work to be done.

Arjun Murti – Goldman Sachs

Yeah. What kind of rig count are you looking at there this year, Steve?

Stephen I. Chazen

Yeah, (inaudible) at six, should be between six and seven.

Arjun Murti – Goldman Sachs

Got it.

Stephen I. Chazen

And then, we are going to be able to obviously do more work with six or seven rigs than we might have done last year with nine or ten.

Arjun Murti – Goldman Sachs

Yeah.

Stephen I. Chazen

So the goal is to get the organization and the people to get more efficient with the rigs before you add more rigs. 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, you may diminish the quality of the crew. So the goal here is – we’re trying to make company as efficient as possible before we do any major increase in spend.

Arjun Murti – Goldman Sachs

And then just lastly, and I apologize for all the questions. Given…

Stephen I. Chazen

That’s okay.

Arjun Murti – Goldman Sachs

Thank you. With the stock cheaper than it once was, what is it that 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

Stock obviously is cheaper than it once was. And we think that the – some stock buybacks are probably in our future.

Arjun Murti – Goldman Sachs

Care to quantify?

Stephen I. Chazen

No.

Arjun Murti – Goldman Sachs

That’s fine. Thank you very much, Steve. Really appreciate it.

Stephen I. Chazen

Thank you.

Operator

Thank you. Your next question comes from Paul Sankey of Deutsche Bank.

Paul Sankey – Deutsche Bank

Hi, good morning, everybody.

Stephen I. Chazen

Good morning.

Paul Sankey – Deutsche Bank

Steve, in the past you’ve spoken about the difficulty in finding values from, for example, splitting the company. Is that still the way you think that essentially with the stock having traded off and relatively cheaper, could you now see benefit of the Middle East/North America split? Thanks.

Stephen I. Chazen

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 pieces, 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. It’s just sort of a tautology.

Paul Sankey – Deutsche Bank

Yeah, I’ve got you. I guess, the other issue at the Middle East that it would be prolifically somewhat difficult, I imagine to, for example, sell the whole business?

Stephen I. Chazen

I think that generally if you went and sold individual countries, you would have to gain the consent of individual country. So if you wanted to sell, I don’t know in some country, generally, the contract requires somebody else to – the country to approve the sale. However, if the business were split off or something, may be not take so much effort.

Paul Sankey – Deutsche Bank

Yeah, 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.

Stephen I. Chazen

I think we look at virtually everything and we know shortage of suggestion. I think you start looking for things that move the needle a lot rather than things to fine tune.

Paul Sankey – Deutsche Bank

Well, you mean an MLP would be a fine-tuning or would be a …

Stephen I. Chazen

Yeah, 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. And so I, but we also have been borrowing 2.5%. You just look at 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, we’re simply selling our joint venture in Brazil and we’ll get like $250 million or some 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 are lots of tweaky things that one can talk about. But again, first of all, focus is on things that really change value.

Paul Sankey – Deutsche Bank

Yeah, I guess that would be selling the whole of OXY or splitting it, right?

Stephen I. Chazen

Well, selling the whole of OXY, that won’t take many phone calls to line up to find out if there are buyers.

Paul Sankey – Deutsche Bank

One, I think it’s probably one call, isn’t it?

Stephen I. Chazen

Yeah, one call. You’ll probably not – who knows. 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.

Paul Sankey – Deutsche Bank

Okay. So you have – that it’s basically – I mean what else is the needle there other than splitting?

Stephen I. Chazen

Well, I don’t know. But there may be other things. There maybe assets we could sell that aren’t contributing to much of the business. I mean there are lots of things we could do that are different than just splitting, but I mean, and maybe even splitting doesn’t move the needle. But the first thing you need to focus on that’s 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 a delicatessen approach to this, where you slice a piece of baloney off and you throw it to the wolves.

Paul Sankey – Deutsche Bank

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 to find a CEO and how much longer you are going to be doing this job?

Stephen I. Chazen

We’re not (inaudible) going to answer that. I think we’ve – look at the press releases and the board and our statements speaks for themselves

Paul Sankey – Deutsche Bank

Okay, a technical question. If the Chairman and some board members are not reelected, how long is it before they are replaced and how does that process work technically speaking.

Stephen I. Chazen

It’s really a decision for the board to make as something that you could read proxy in detail, but it’s really a board decision.

Paul Sankey – Deutsche Bank

Okay, Steve. I’ll leave it at that. Thanks for your comment.

Stephen I. Chazen

Thank you.

Paul Sankey – Deutsche Bank

Thank you.

Operator

Thank you. Your next question comes from Matt Portillo of Tudor, Pickering, Holt.

Matthew Portillo – Tudor, Pickering, Holt & Co.,

Good afternoon.

Stephen I. Chazen

Hi. I think it’s morning for us.

Matthew Portillo – Tudor, Pickering, Holt & Co.,

Just a few…

Stephen I. Chazen

It’s always morning in California.

Matthew Portillo – Tudor, Pickering, Holt & Co.,

Just one additional question in terms of the potential for share repurchase, could you talk a little about your capital structure and how you think about kind of the appropriate leverage for your balance sheet today. Just tying to get a better sense of how much capital that you have to access on a potential repurchase or other opportunities you are looking at to enhance shareholder value?

Stephen I. Chazen

I don’t think we probably 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 could react to opportunities that occur in an ugly market. And then our operations in Middle East, it’s very important, if you’re going to sign for a long-term project 30 years or something like that, do you have a solid balance sheets of they believe you’re going to be around. I don’t – that sort of qualitative view. What the exact number is, I just don’t know, but we have a lot of financial flexibility

Matthew Portillo – Tudor, Pickering, Holt & Co.,

Okay

Stephen I. Chazen

We’ve got the very strong balance sheet for that.

Matthew Portillo – Tudor, Pickering, Holt & Co.,

Perfect and then just two quick asset level questions, I was wondering if you can give us some color, the Wolfbone sounds like a new play you are focusing on. If you can give us a little bit of color on how you’re seeing well costs and potentially returns to EURs there? And then I have one quick follow-up on the midstream side.

Stephen I. Chazen

Bill?

William Albrecht

Yeah, Matt, on the Wolfbone, what we’re seeing for – these are completed well costs, including hookup, we are in the $3 million to $3.5 million range in the completed well costs.

Matthew Portillo – Tudor, Pickering, Holt & Co.,

Thank you and then just a last question on the midstream side of business, you obviously saw a pretty significant up tick in operating profit for the quarter, just trying to get a little bit better sense and how we should think about 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 maybe as we move into the second and third quarter?

Stephen I. Chazen

We’ll start, we’ll say – Willie will answer the question, but you should view it as volatile. Go ahead, Willy.

Willie C.W. Chiang

I think you saw last year’s number; we were kind of in the low 400s. And as Steve said, a lot of the wells for the whole year and a lot of what we do rids on arbitrage opportunities and market prices. We keep reinforcing that one of our key roles is to make sure everything that we produce gives access to the highest markets. So we’ve done things like, renegotiated 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 first quarter results, a lot of that was due to the arbitrage opportunity between Permian and the Gulf Coast. And 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 this is market based.

Matthew Portillo – Tudor, Pickering, Holt & Co.,

Thank you very much.

Stephen I. Chazen

A very little of it was from the fiber 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 up in the segment.

Matthew Portillo – Tudor, Pickering, Holt & Co.,

Thank you.

Stephen I. Chazen

Thanks.

Operator

Thank you. Your next question comes from Faisel Khan of Citigroup.

Faisel Khan – Citigroup Global Markets

Thank you, good morning.

Stephen I. Chazen

Good morning.

Faisel Khan – Citigroup Global Markets

I was wondering if you could back to California a little bit and discuss the CapEx trends there. So I guess in the middle of the year, you were trending in 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

I think we’re budgeting $1.5 billion in California this year.

Faisel Khan – Citigroup Global Markets

Okay. So then should we see that number sort of pickup as we…

Stephen I. Chazen

That’s right. Actually all of the capital, we had a slow start in spending this year, not all of that by the way. So we had a slow start everywhere, costs are coming down and you will see the capital spending go to the nine, six-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.

Faisel Khan – Citigroup Global Markets

Okay. And then I want to go back to also 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?

Stephen I. Chazen

The reserve revision largely was a single old conventional oil part of Elk Hills filed. And it has a different kind of production driver. And the wells there have declined (inaudible) it’s not conventional. So it fell off the curves, so we took the write down on reserves, but it’s not unconventional, it’s hourly the shale, it’s a reservoir that’s probably producing almost 100 years and will probably produce for another 100 years.

Faisel Khan – Citigroup Global Markets

Okay, understood. And then just if you could on the rig count it’s been kind of bouncing around the last year or two, you were kind of 50 rigs on average in ‘11 and then you were at 60 somewhat rigs on average for ‘12, but then at the end of the year you were at 41 rigs, so what’s the trend for this year?

Stephen I. Chazen

We believe 50, 55 rigs.

William Albrecht

Yeah, in the Americas – 50 to 55 pretty stable.

Stephen I. Chazen

Yeah.

Faisel Khan – Citigroup Global Markets

Okay. So I am just trying to reconcile that with the 10-K we talk about 41 rigs at the end of the year…

Stephen I. Chazen

At any time, these rig numbers, how many you have, we answer it almost too truthfully, and so it’s exactly the – 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 Global Markets

Okay, understood. The one last question, in terms of – if I look at the year-over-year growth in volumes and the lower 48, how much would you say the volume growth was attributed to the acquisitions you made last year?

Stephen I. Chazen

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 else where, but it’s very hard. Most of what we acquired was pud locations.

Faisel Khan – Citigroup Global Markets

Okay, understood. Thanks for the time, I appreciate it.

Stephen I. Chazen

Thank you.

Operator

Thank you. Your next question comes from Sven del Pozzo of IHS.

Sven del Pozzo – IHS Herold

Yeah, good morning.

Stephen I. Chazen

Good morning.

Sven del Pozzo – IHS Herold

I’m trying to quantify, I know it’s a hard question to answer, because it’s driven by third-party operators. But how much do you budget for rather the $1.9 billion in the – you said two-thirds of $1.9 billion in CapEx in the Permian and non-CO2 businesses?

Stephen I. Chazen

That’s right. 601.3 as I remember.

Sven del Pozzo – IHS Herold

Oh, that would be operated versus non-operated?

Stephen I. Chazen

No, no. That’s total. The CO2 business is almost all our 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 – IHS Herold

Yeah. 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

We clearly have some, you might decline. What the – generally the results what I would like to have from them is the results they tell the street rather than the AFPs we see.

Sven del Pozzo – IHS Herold

Would it be possible to quantify of your 1.7 million net acres that you consider perspective for these emerging plays, how much of that is non-operated acreage and how much is operated?

Stephen I. Chazen

I don’t think we could do that here on the phone.

Sven del Pozzo – IHS Herold

Okay.

Stephen I. Chazen

Yeah. You can see the gross in that. We’ll show you a gross in that, so you get some idea of our percentage. So I mean, that may help you some, but we don’t actually keep our records that way.

Sven del Pozzo – IHS Herold

Okay. Yeah, I saw 2.5 million net acres in the Permian on your website for the total acreage number?

Stephen I. Chazen

That’s right.

Sven del Pozzo – IHS Herold

Does that include what you acquired in Reeves County, was that last year for the WolfBone stuff?

Stephen I. Chazen

Whatever is – whatever there on 12/31.

Sven del Pozzo – IHS Herold

Okay. And there were just some comments I was just looking over the fourth quarter 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 first quarter?

Stephen I. Chazen

Yeah, Bill will answer that.

William Albrecht

Yes, and we’ve got a one of our major CO2 recycling plants getting ready to undergo a turnaround. It’s going to start, I think next Saturday, last about two weeks.

Sven del Pozzo – IHS Herold

All right. Well, thanks, everybody.

William Albrecht

Thank you. Chris?

Chris Stavros

We have one last question.

Stephen I. Chazen

Okay, thank you.

Operator

And your final question comes from Pavel Molchanovi of Raymond James.

Pavel Molchanov – Raymond James & Associates

Hey guys, just one more on the cost side. I mean, clearly you’re running ahead of schedule on your cost productions. 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 production target for the year?

Stephen I. Chazen

We might do it internally, we’ll show you actuals.

Pavel Molchanov – Raymond James & Associates

Okay. And I mean, anecdotally, have you seen some softening across the value chain in the last, let’s say four weeks?

Stephen I. Chazen

Are you talking about cost? We contract on a longer basis in 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 for us to tell about the last month.

Pavel Molchanov – Raymond James & Associates

Okay, fair enough. I’ll take that off-line, thanks.

Stephen I. Chazen

Thank you.

Chris Stavros

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.

Operator

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



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