西方石油 (OXY) 2013 Q1 法說會逐字稿

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 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) 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 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 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 will turn the call over to our CFO, Cynthia Walker who will review our financial and operating results for this year's first quarter.

Steven Chazen will then follow with an update on the progress we're making toward our ongoing efforts to improve our oil and gas operating cost, as well as our capital and drilling efficiencies as part of our effort to improve our financial returns.

Steve will conclude the call with some comments around guidance for the second quarter.

Our highlight of this quarter's conference call will be an in-depth discussion from Bill Albrecht focusing on our non-CO2 drilling program in the Permian basin.

And additional details on our drive to improve capital and drilling efficiency and reduce our operating cost throughout the domestic oil and gas business.

As a reminder, today's conference call contains projections and other forward-looking statements.

Within the meaning of the securities laws, these statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied in these statements and our filings.

Our first quarter 2013 earnings conference call press release, investor relations supplemental schedules and conference call presentation slides, which refer to our prepared remarks, can be downloaded off of our website at www.oxy.com.

I will now turn the call over to Cynthia Walker.

Cynthia please go ahead.

Thank you, good morning everyone.

Core income for the quarter was $1.4 billion, $1.69 per diluted share in the fourth quarter of this year.

Excuse me -- 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 will now discuss the segment accounts.

Oil and gas core earnings for the first quarter 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 2012, due mostly to the timing of [liftings], as well as the effect of the maintenance turnarounds in Cutter and full cost recovery in our contract in Oman.

This reduced our 2013 first-quarter earnings by about $200 million after-tax compared with the fourth quarter of 2012.

Costs associated with the turnarounds, pipeline disruptions in Colombia, and other factors further reduced earnings by about $30 million after-tax.

Combined, these factors reduced oil and gas segment earnings by approximately $450 million on a pretax 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 for 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 planned maintenance turnaround in our Cutter North Dome and South Dome fields, and to a lesser extent, the planned turnaround in Dolphin.

First quarter 2013 total daily production on a BOE basis was 763,000 barrels, which was 16,000 barrels per day lower than the fourth quarter of 2012, and 8000 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 Cutter and Dolphin, where the planned maintenance impacted production.

I am 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 3000 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 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 1000 barrels lower compared to the fourth quarter, and 5000 barrels higher than the same period in 2012.

The production 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 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 first quarter production volumes by an additional 5000 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 $98.07 per barrel, a 2% increase from the fourth quarter, while worldwide NGLs were $40.27 per barrel, a decrease of about 11%.

And domestic natural gas prices were about flat at $3.08 per million cubic feet.

First quarter 2013 realized prices were lower than the prior year first-quarter prices for crude oil and NGLs.

On a year-over-year basis, price decreases were 9% for worldwide crude oil and 23% for worldwide NGLs.

Domestic natural gas prices were higher by about 8%.

Realized oil prices for the quarter represented 104% of the average WTI price and 87% of the average Brent price.

Realized NGL prices were 43% of the average WTI price, and realized domestic gas prices were 91% of the average Nimax 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 Nimax for gas.

At current global prices, a dollar-per-barrel change in oil prices affects our quarterly earnings before income taxes by $37 million, and $7 million for a dollar-per-barrel change in NGL prices.

The change in domestic gas prices of $0.50 per million BTU affects quarterly pretax earnings by about $30 million.

These price-change sensitivities include the impact of production sharing and similar contract volume changes.

Taxes other than on income, which are generally related to product prices were $2.63 per barrel for the first quarter of 2013, compared to $2.39 per barrel for the full year of 2012.

The 2013 amount includes California greenhouse gas expense of $0.05 per barrel.

First quarter exploration expense was $50 million.

We expect second quarter 2013 exploration expense to be about $100 million for seismic and drilling in our exploration programs.

Chemical segment earnings for the first quarter of 2013 were $159 million, compared to $180 million in the fourth quarter of 2012, and $184 million in the first quarter of 2012.

The sequential quarterly decrease was due to higher ethylene cost and increased competitive activity, particularly in the domestic caustic soda markets.

This was partially offset by higher VCM and PVC prices.

The chemical segment second-quarter 2013 earnings are expected to improve to about $170 million, benefiting from higher seasonal demand in the construction and agricultural markets.

Midstream segment earnings were $215 million for the quarter compared to 2013 -- for the first quarter 2013 compared to $75 million in the first quarter of 2012, and $131 million in the first quarter of 2012.

Over 70% of the 2013 sequential quarterly increase in earnings resulted from improved marketing and trading performance.

The remainder of the increase came from improved margins in the gas processing and power generation businesses, and higher earnings from foreign pipelines.

The worldwide effective tax rate on our core income was 38% for the quarter, this included a benefit resulting from the relinquishment of an international expiration block.

Our first-quarter US 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.

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.

First-quarter domestic production of 478,000 barrel equivalents per day consisting of 342,000 barrels of liquids, 817 million cubic feet of gas per day, was an increase of 3000 barrel equivalents per day compared to the fourth quarter of 2012.

We are executing a focus drilling program in our core areas and to date we are running ahead of our full-year objectives in our program to improve domestic operational capital efficiencies.

For example, we have reduced both our domestic well and operating cost by about 19% relative to 2012.

This is ahead of our previously stated targets of 15% well cost improvement, and a total oil and gas operating cost below $14 a barrel for 2013.

While we are still in the early stages of this process, and making a longer-term projection is difficult, our goal is to sustain the benefits realized to date, achieve additional savings in our drilling costs, and reach our 2011 operating cost level over time, without a loss in production or sacrificing safety.

The purpose of these initiatives is to improve our return on capital.

I will now turn the discussion over to Bill Albrecht who will provide details of our domestic drilling programs and of the capital and operational efficiencies initiatives that we have implemented.

Thank you, Steve.

This morning, I would like to share with you the three main objectives of our 2013 domestic program.

First, delineate our core or anchor drilling areas in the Permian basin.

We've accumulated more than 1.7 million net acres covering both relatively established and emerging plays in the Permian.

This year, we're focused on delineating incremental opportunities in established plays as well as testing the potential of many emerging plays.

Second, drive capital efficiency, particularly in our core drilling programs.

We believe that the results of our capital efficiency improvement program are not only scalable across our core programs, but that these results are also sustainable.

And third, enhance our cash margins through operating expense reductions.

Turning now to our first objective, our Permian basin activity.

As we 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 will 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 at Oxy and represents the largest proportion of our activity.

In 2013, we will drill a mix of infill wells in already established core areas, and stepout wells in emerging areas of the play.

We expect stepout wells to pretty much mirror the solid results we have seen in drilling hundreds of Wolfberry wells in the last several years.

The Delaware will be about a quarter of our activity in 2013.

We are seeing increased opportunity to enhance economics utilizing horizontal drilling and completions to develop established Titan reservoirs.

We expect to grow 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 will increase our activity this year as we further delineate our acreage position.

Because of the multipay nature of the play, wells will be mostly vertical at this stage, although we will drill a number of horizontal wells and sweet spots of this multipay 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 have been drilling for less than a year in Wolfbone and have already seen substantial improvements in well cost.

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 will 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 and types being drilled in 2013.

By implementing all four elements, we have 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 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 of our assets.

Consequently, we have reduced our rig downtimes by 20%.

For example, in the Williston, our optimized drilling schedule designed to minimize rig mobilizations has reduced move costs 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 have also reduced costs by 47% per frac stage, per Wolfberry well, without any degradation in production.

At Elk Hills, in our anchor shale program, we are running mostly slotted liners instead of cemented liners, saving $1.5 million per well, again with no degradation in production.

In a number of our programs, we have reduced the amount of gel loading and resin-coated sand, thus reducing completion costs.

In short, we are seeing the benefits in the form of reduced drilling and completion times, and reduced and more efficient use of materials and supplies.

Let me now turn to the third element -- improving operational execution.

While we are making numerous incremental changes in our day-to-day activities everywhere, we have made significant improvements, specifically in the Permian and Williston business units.

In both areas, we are optimizing our use of water and completion operations, by using flowback and/ or produced water in stimulations, which is generating substantial savings this year.

In the Williston, more of the wells we are drilling have been trouble-free, particularly due to improved directional-fuel reliability.

And finally, we have 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 have reduced our stimulation contract pricing.

We have also reduced our fluid-hauling costs by implementing a trucking cluster concept whereby certain trucking fleets are dedicated to specific core areas.

Overall, we have 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 are 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 will have the flexibility to focus on continuing development of our Russian Creek acreage where we plan to drill 46 wells in 2013, concentrating on the sweet spot of our acreage there.

Our development will be mainly in the middle Bakken with other wells testing both the Pronghorn and Three Forks formations.

In another one of our anchor programs, the Wolfberry, we have seen sustained reductions in completed well costs where costs are down from $3.5 million to $2.6 million.

Lastly, I would like to discuss the third objective of our overall domestic strategy, and that is enhancing our cash margins through reductions in operating costs.

While our operating costs have also benefited from some of the actions taken for capital efficiencies that I just described, we have taken additional steps specific to reducing our operating costs, especially in the areas of down-home maintenance and workovers which together make up the bulk of our costs.

I would like to share a few examples with you of the actions we have taken toward achieving our goal.

First, in order to optimize our well-servicing rig costs, we are eliminating inefficient workover rigs.

While this has caused an overall decline in our workover rig count, we are finding that through better planning and scheduling, we are able to perform a similar number of well servicing jobs as we did with a larger fleet.

As a result, we have not seen any production falloff from these reductions.

Second, through a more rigorous review of wells that are repair and maintenance candidates, we have 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 efficiencies 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 have 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 have 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 is a key area of focus for us.

In some locations, we have been able to find ways to recycle more of our produced water, reducing our sourcing as well as disposable costs, and as a result handling water in a more environmentally conscious manner.

We're also working with our suppliers to address the cost of these supplies and services.

In addition, we are working on optimizing our use of injectants and energy.

For example, we are improving our CO2 and steam utilization through ongoing pattern surveillance and evaluation of injectant-to-oil recovery ratios, and we'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 down-home 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 would like to add that the great success we have had to date in achieving our capital efficiency in 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 am 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 have made progress in both our capital efficiency and operating cost-reduction efforts, we are still in the early stages of this process and therefore our data is based on a relatively small portion of our overall program.

In addition, we executed a relatively trouble-free drilling program in the first quarter.

Nonetheless, given our results to date and our people's effort in this endeavor, we are optimistic we can sustain and further improve upon the results achieved to date.

I would 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 will 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% to an annual rate of $2.56 per share from the previous annual rate of $2.16.

We have 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 second-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 drillings such as steam flood drilling in California.

We expect second quarter liquids growth to be modest with higher growth coming in the second half of the year.

We just received word today that we got permits for three new compressors for our steam flood program, one is already on, so I think we are going -- doing well in California on this, just a slow start this year.

The first quarter of 2013, our based gas production did not decline as much as we had initially expected.

Estimating for the ruption for the rest of the year still remains challenging.

We expect to see modest declines in our gas production as a result of our reduced drilling on gas properties, and natural decline, as well as a number of gas plants turnarounds scheduled in our Permian business for the rest of the year.

Internationally, excluding Iraq, at current prices we expect production to be higher in the second quarter, back to around the fourth quarter 2012 levels, with the increase coming mainly from resumption of production in 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, expected to be in line with the $9.6 billion program I discussed on the last call.

As you can see, the business is doing well, and we are continuing to make progress in our operational and financial goals.

I am very pleased that employees at all levels have stepped up the challenges we have 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 are 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 ongoing Board activities and succession process.

Thank you.

(Operator Instructions)

Your first question comes from Doug Terreson of ISI.

Congratulations on your results, everybody.

Thank you.

The people in the Company did a great job.

They sure did, my question regards the sequential decline in earnings of $450 million, which was highlighted I think on slide 3; and specifically whether you can provide any additional insight into the component, which is likely to be transitory -- meaning some of the elements were identified, but how much is sequential decline related to factors that are not normally recurring, like maintenance and pipeline disruptions in listing variances, et cetera?

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 contact 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 he mentioned -- Qatar turnaround, 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 have a couple if I may, Steve.

On the cost, Steve -- if I look at the cost on the US, you obviously built that out for us and I take your commentary about the total company.

It looks to me at least that the international cost went up -- maybe $2 to $3 a barrel.

I am 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 cost?

And then I have a follow-up.

Oh, we will let Cynthia give you the first part, and then I will answer the second part.

So, where does that put our run rate?

Yes, in the second quarter, there will be some other factors, likely offsetting things, but we would not expect to get substantially below the levels that we are currently.

We will not be below $13 a barrel in the second quarter.

Some of the activity that we did not do in the first quarter will come into the second quarter.

(Inaudible - multiple speakers)

We expect that the US business -- this may simplify it a little bit for you -- we expect the US business; 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.

And the international costs will come back into line.

They were up this past quarter, but we think they will be down next quarter.

And by putting money into the -- what we have done, the turnarounds, will 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 that is what Cynthia was referring to.

The fundamental numbers will be lower.

Again, there might be some additional turnarounds -- not in the Middle East but in the US.

Sandy, you want to comment on the Middle East?

Yes, Doug, in Qatar we were actually producing to record levels over the past, since the past few years, of 118,000 to119,000 gross, and the actual extra money we spent on the turnaround, that we got much higher reliability.

We have records in Oman right now of 235,000 barrels a day gross; and we actually are reducing OpEx per barrel there, still paying attention to production reliability and safety issues.

That is very helpful.

Steve, my follow-up, and I hope you're going to forgive me for this one ahead of time, I realize you --

I have become more forgiving in my old age.

Okay, I realize you do not want to talk about the Board situation.

However, my question to you relates to you in terms of your intentions.

When we traveled in the past, you have always stated that you saw yourself being in position for quite a while in executing a strategy that ultimately took you towards 1 million barrels a day.

Should we rule out the possibility of you staying around a bit longer, if the Boards, for example, had a change of heart?

And what is your strategic vision for the Company longer-term?

I am not going to answer the first question.

That is really outside the purview of what we want to talk about.

On the strategy issue, the Company, as we get -- the Company is really executing well.

Every day I'm happy to talk about the operations.

And I think the Company is doing really well; I think we will continue to grow nicely.

We have little bumps in the road, in the quarter, but fundamentally, I really could not be happier about the progress we are making as a company.

The million barrels a day, I think is a reasonable objective.

What we are going to do, call-to-call is, while Bill got to talk this time, we will let somebody else talk next quarter, and maybe we will talk about California next quarter, and have Vicki come and talk.

So we will try to give you more detail, one call at a time, rather than try to flood you with it.

I think you will see that the strategy of building a large domestic business, together with a highly profitable international business, will work for us.

I think the vision right now is that one.

Unless you want to ask the same question another way.

Well, I'm just thinking, would you ever see that -- there's been a lot of speculation about structural changes for the separating one part of another for the MLP, so 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?

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 our actions, if we can find actions that are meaningful and are accretive to value, we will do those things.

All right, I will leave it at that.

Thanks, Steve.

Thank you.

Thank you; your next question comes from Leo Mariani of RBC.

It looks like you've certainly gotten more optimistic on some of these new plays here in the Permian.

Want to get a sense of how much of that is attributable to your recent cost reductions, and how much may be attributable just to better well performance.

The key to the Permian, in my view, is cost -- well, repeatable, low drilling cost.

And the change in the returns by these reductions is market.

Bill, you want to comment on the returns?

Yes, Leo, across the plays that I've mentioned, we are seeing solid 15%, 20%- plus returns.

And as Steve said, what's really been a big enhancing factor is what we have done to take dollars out of our cost structure.

So the barrel, the IPs, the ultimate recoveries -- same as our experience.

But I think by driving the cost down, by returns, we are not doing the IRR sort of returns -- sort of a more sustainable kind of returns.

IRRs have to do with how fast you get your money back.

I think we are doing really well; we are very pleased with the progress in the Permian at this point.

Okay, so just to clarify on the return -- that is more of an after-tax corporate effort?

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 $1.5 million per well, I think you said, in Elk Hills in 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 have 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.

We are trying to get the cost down to even lower sustainable levels before we boost the number of rigs that work.

So we need to get our costs down to what we think is sustainable levels, which will be lower than we are showing here, and then we will build the program up from there.

But I think there's more room here.

I am very optimistic about that capital, the well cost program, the 19% -- it would be disappointing if that is all it turned out on us.

Okay, that is really helpful.

And I guess in terms of your first quarter, you guys talked about 5000 barrels a day internationally, and loss due to production sharing contracts payout.

Just curious as to whether or not there is going to be any further impact during 2013 from TSEs in projects you pay out.

I do not think much.

I think we are probably at for this year where we need to be, where we will be.

Because you have to go to another level of payouts, Pretty much the programs, 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, and I guess if we look back a few years ago on some of the early results, that relationship between costs and what looked like could be the EURs, and production per well, looks very favorable.

Maybe the costs 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 here is just maybe the geology's obviously different or not as robust as before?

Really any color around -- again, I'm talking about the unconventional in California?

Yes, I think we have not been able to drill where we wanted to drill all the time.

And so some of it is related to that.

That has created some inefficiencies.

And the well costs got markedly higher than we would like.

And while it did not make them terrible, certainly sort of wasteful.

So I think as far as the results are concerned, I think they are in line with what we said before, of IPs, of those sorts of things.

But we have shifted the focus to more conventional drilling to get less decline in the program, less underlying decline.

Because I think the decline is what we're trying to fight against.

Were the declines unexpected?

I mean, usually unconventional does come with quick declines.

Or is it just --

It's been, I think, more than we originally thought.

Got it.

Any update on the permitting process in California?

I know it is always a challenge.

But, any improvement there at all?

The permitting -- I do not 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, But, also continues to be hard to predict from a quarter-to-quarter basis.

You get some good news, you get some not-so-good news.

I think that we've built a program this year that does not rely on the permitting process to deliver the results.

And so we will be able to deliver a good set of results this year, with low finding costs and reasonable growth.

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

Yes, and then just finally -- thank you.

On the Bakken, 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 were kind of in or out.

It sounds like you are a little more optimistic on the Bakken, just now on the right side of the return threshold, or still more work to do in the Bakken?

More work to be done.

Yes.

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

This is Bill.

It is six.

It should be between six and seven.

Got it.

We are going to be able to obviously do more work with the 6 or 7 rigs than we might have done last year with 9 or 10.

So if the goal is to get the organization and people to get more efficient with the rigs before you add more rigs, because part of this game or a lot of this game is having the best crews on the rigs.

So as you add another rig, you may diminish the quality of the crew.

So the goal here is, we are trying to make the Company as efficient as possible before we do any major increase in spending.

Yes.

And then just lastly -- and I apologize for all the questions -- in a given --

That's okay.

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 unexcited you are to do those at this at this point?

Stock obviously is cheaper than it once was.

And we think that some stock buybacks are probably in our future.

Care 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.

Good morning, everybody.

Steve, in the past you've spoken about the difficulty in finding value from, for example, splitting the Company.

Is that still the way you view things?

That essentially with the stock having traded off and relatively cheaper, could you now see the benefit of a Middle East/North American split?

I think that is 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 -- it may be fairly straightforward to do the US.

Valuing the international standalone, is really more complicated because there's not a lot of good comps.

So I think that we will look at everything; but, obviously, with the 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.

Yes, I've got you.

I guess the other issue with the 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, I don't know, some country, generally the contract requires somebody else to -- the country to approve the sale.

However, if the businesses were split off or something, it may not take so much effort.

Yes, that make sense.

There is a lot of speculation around the potential for an MLP of the midstream.

Could you just talk a little bit about how you see that?

Thanks.

We look at virtually everything; no shortage of suggestions.

I think you start looking for things that move the needle a lot, rather than things to fine-tune.

You mean an MLP would be a fine-tuning or --

Yes, I think an MLP would be a fine-tuning, rather than a major mover -- that is something one can think about over time.

But MLP is, hopefully, low-cost capital.

So presumably the play would be, sell the MLP, take the proceeds, and buy the shares -- but, we also can borrow at 2.5%.

So, just looking for things that, at least initially, are things that move the needle a lot rather than tweaking things.

A tweak, for example -- we're selling our joint venture in Brazil, and we will get $250 million 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.

There's lots of tweaky things that one could talk about, but -- the first of our focus is on things that really change value.

Yes, I guess that would be selling the whole of Oxy, or splitting it, right?

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

(Laughter)

One -- I think it is probably one call, isn't it?

Yes, one call.

He probably -- who knows?

So we won't need to hire a lot of investment bankers to study the call.

(Laughter) I think that is an improbable outcome.

Okay, so yes, it is basically -- what else is the needle moving other than splitting?

I don't know.

But there may be other things; there may be assets we can sell that aren't contributing to much of the business.

There's lots of things we could do that are different than just splitting.

And maybe even splitting doesn't move the needle.

But the first thing you need to focus on is what really matters, and then you can focus on things to improve it slightly.

But I think you don't want to go down the path of sort of a delicatessen approach to this, where you slice a piece of baloney off and you throw it to the wolves.

(Laughter.)

Listen, the biggest risk on this start, no question, is your future.

You really have to address this question of how long you think it is going to take to find a CEO, and how much longer are you going to be doing this job?

I am just not going to answer that.

I think the press releases, and the Board -- 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 is really a decision for the Board to make.

It is not something that you could read the proxy and it tells.

It is really a Board decision.

Okay, Steve I will leave it there, thanks.

Next, Matt Portillo of Tudor, Pickering, Holt.

Just a few questions; 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 the appropriate leverage for your balance sheet today?

Just trying to get a better sense of how much capital you have to access on a potential share repurchase or other opportunities you are looking at to enhance shareholder value?

You know, I do not 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 can react to opportunities that occur in an ugly market.

And then there are operations in the Middle East.

It is very important if you're going to sign for long-term project -- 30 years or something like that -- that you have a solid balance sheet so they believe you are going to be around.

That is sort of a qualitative view.

What the exact number is, I just do not 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 Wolfbone sounds like a new play you are 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 had one quick follow-up on the midstream side.

Bill --

Yes Matt, on the Wolfbone, what we are seeing for -- these are completed well costs, including hookup.

We are in the $3 to $3.5 million range, in completed well costs.

Thank you.

And then just the last question -- on the midstream side of the business, you obviously saw a pretty significant uptick in operating profit for the quarter.

Just trying to get a little bit better sense of how we should think about that midstream and marketing and trading part of that business -- the $100 million you guys generated there, and how that should trend over the rest of the year?

Or how volatile that may be as we move into the second and third quarter.

We will start, we will say -- Willie will answer the question -- but you should view it as volatile.

Go ahead, Willie.

Sure, Matt, I think you saw last year's numbers; we were kind of in the low $400s.

And as Steve said, a lot of -- well, that was for the full 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 have done things like renegotiate contracts, to uncouple them from things like WTI.

You will see us take a lot more capacity and 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 was 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 a lot of it is market-paced.

Thank you very much.

Very little of it was from the Phibro operation, almost all of the gain was from gas plants and arbitrage with our capacity to move oil around.

So instead of showing up in the oil segment -- because it was not our oil -- it would show up in this segment.

Thank you.

Thank you.

Your next question comes from Faisel Khan, Citigroup.

Thank you.

I was wondering if I could go back to California a little bit and discuss the CapEx trends there.

I guess in the middle of the year you were trending at about $550 million in CapEx a quarter, and now you are down to close to $300 million in CapEx.

Is this the new trend through the year?

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

Okay, so then we should see that number pick up as we get in?

That's right -- actually, all of the capital -- we had a slow start in the spending this year, not all bad by the way.

So we had a slow start everywhere; the costs are coming down.

And you will see the capital spending go to the $96-ish level for the year, for the whole company.

So we will start to see a pickup of it, 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 what resulted in the reserve revision you guys took in the 10-K?

The reserve revision largely was a single, old, nonconventional oil part of Elk Hills field.

And it has a different kind of production driver.

And the wells there have declined more than we thought, but it is not conventional, so it fell off the curves.

So we took the write-down on the reserves.

But it is not an unconventional; it's not really a shale, it is a reservoir that's probably been producing almost 100 years.

And will probably produce for another 100 years.

Okay, understood.

And if you could, on the rig count, it's been bouncing around the last year or two.

You were at 50 rigs on average in '11, and then you were at 60-some odd rigs on average for '12, and at the end of the year you were at 41 rigs.

So what is the trend for this year?

We believe it's 50, 55 rigs in the Americas --

Yes, in the Americas, 50 to 55, pretty stable.

Okay, so I'm just trying to reconcile that with the 10-K, where you talk about 41 rigs at the end of the year --

Yes, and anytime these rig numbers, how many you have, we answer it almost too truthfully.

And so it is exactly what it is that day or the day before.

And it could be three rigs or four rigs higher or lower the next day.

So you know, I would not make too much of the exact number.

Okay, understood.

And last question for me-- in terms of, if I look at the year-over-year growth in volumes in the lower 48, how much would you say of 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 is very hard -- most of what we acquired was PUD locations.

Okay, understood, thanks for the time, appreciate it.

Next, Sven Del Pozzo, IHS.

Good morning.

I am trying to quantify -- I know it is a hard question to answer, because it is driven by third-party operators, but how much do you budget for out of the $1.

9 billion, and you said two-thirds of $1.

9 billion in CapEx in the Permian and non-CO2 businesses?

That is right.

$600 million and $1.3billion, as I remember.

Oh, that would be operated versus nonoperated --

No, that is total.

The CO2 business is almost all our operation.

The $1.3 billion includes some of the nonoperated ones; we have to estimate that number obviously; it is not our choice.

Yes, and so in relation to that nonoperated estimate, I was wondering what kind of exposure you have to nonoperated 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?

We clearly have some.

You might decline.

Generally the result, what I would like to have from them is the results they tell the Street, rather than the AFPs we see.

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

I do not think we could do that, here on the phone.

Okay.

You can see the gross and net; we show you gross and net so you get some idea of our percentage.

So that may help you some.

But we do not actually keep our records that way.

Okay.

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

Does this include what you acquired in Greene County?

Was that last year for the Wolfbone stuff?

Whatever was -- there on 12/31.

Okay, and then they were just some comments.

I was 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 -- in the first quarter?

Yes.

Bill will answer that.

Yes, we have one of our major CO2 recycling plants getting ready to undergo a turnaround.

It is going to start, I think, next Saturday -- lasts about two weeks.

All right.

Thanks everybody.

Final question comes from Pavel Molchanov, Raymond James.

Just one more on the cost side.

Clearly, you are running ahead of schedule on your cost reductions.

Since the end of the quarter we have 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 will show you actuals.

Okay, and, anecdotally, have you seen some softening across the value chain in the last, lets say, four weeks?

Are you talking about costs?

Yes.

We contract on a longer basis than that.

Certainly the costs from suppliers is -- what they are charging has come down.

But we do not do a lot of daily sorts of activities.

Most of our stuff is contracted for a period.

So it is really hard for us to tell about the last month.

Okay, fair enough.

I will take that offline.

Thanks.

Thank you.

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.