Occidental Petroleum Corporation (OXY) Q2 2010 Earnings Report, Transcript and Summary

Good morning. My name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Occidental Petroleum Second Quarter 2010 Earnings Release Conference Call. [Operator Instructions] Mr. Stavros, you may begin your conference.

Thanks, Christie, and good morning, everyone. Welcome to Occidental Petroleum's Second Quarter 2010 Earnings Conference Call. Joining us on the call this morning from Los Angeles are Dr. Ray Irani, Oxy's Chairman and CEO; Steve Chazen, our President and CFO; Bill Albrecht, President of Occidental's U.S. Oil and Gas Operations; and Sandy Lowe, President of our International Oil and Gas business. Our second quarter earnings press release, Investor Relations supplemental schedule and the conference call presentation slides, which refer to Steve's Chazen's commentary can be downloaded off of our website at www.oxy.com. I'm now going to turn the call over to Steve who will review our second quarter and first half 2010 financial and operating results. Steve, please go ahead.

Thank you, Chris. Net income was $1.1 billion or $1.31 per diluted share in the second quarter of 2010, compared to $682 million or $0.84 per diluted share in the second quarter of last year. Here's the segment breakdown for the second quarter. Oil and Gas second quarter 2010 segment earnings were $1.9 billion, compared to $1.1 billion for the second quarter of 2009. The improvement in 2010 was driven mostly by higher commodity prices, with additional contributions from higher volumes. Realized crude oil prices increased 36% in 2010, and domestic natural gas prices improved 46% in the second quarter of 2009. Partially offsetting these gains were higher DD&A rates and higher operating expenses, partly resulting from fully expensing CO2 costs in 2010. Worldwide Oil and Gas production for the second quarter of 2010 was 743,000 barrels of oil equivalent per day, an increase of 3.5% compared to 717,000 BOE a day in the second quarter of last year. Second quarter of 2010 production was lower than our guidance due primarily to shortfalls in California and adjustments resulting from the mechanics of production sharing contracts in the Middle East. Our production in California continues to be affected by the gas plants' and related infrastructure's inability to process oil and gas that could be produced. Also, this affects the liquids that are associated with this production. Year-over-year production was negatively impacted by 29,000 BOE a day in the Middle East/North Africa, Long Beach and Colombia, as a result of higher oil prices affecting our production sharing and similar contracts. Second quarter 2010 production includes volumes in Bahrain of 3,000 barrels of oil and 161 million cubic feet of gas, and 16,000 BOE a day higher volumes in the Mukhaizna field of Oman. Our domestic operations added 11,000 BOE. Volume gains in the Kern County discovery area were moderated by production declines in Elk Hills, which was caused by gas gathering and processing issues. Exploration expense was $73 million in the quarter. Oil and Gas cash production costs, excluding production and property taxes, were $9.90 a barrel for the first six months of 2010. The second quarter 2010 per barrel production costs were slightly lower than this figure. Last year's 12-month costs were $9.37 per barrel. The increase reflects $0.30 a barrel higher CO2 costs due to our decision to expense 100% of injected CO2 beginning in 2010 and somewhat higher field support operations and maintenance costs. Taxes, other than on income, were $1.80 a barrel for the first six months of 2010, compared to $1.60 per barrel for all of 2009. These costs, which are sensitive to product prices, reflect the effect of the higher crude and gas prices this year. Chemical segment earnings for the second quarter of 2010 were $108 million. Second quarter results reflect improvement from the first quarter in 2010 in margins and volumes across most product lines. Midstream segment earnings for the second quarter of 2010 were $13 million, compared to $63 million last year. The decrease in earnings was mainly due to a pre-tax $104 million, $0.07 per share after taxes, loss at Phibro, the bulk of which resulted from marking its quarter end open positions to market. This was partially offset by higher margins in the marketing, gas processing and pipeline business. The worldwide effective tax rate was 43% for the second quarter of 2010. Now let us turn briefly to our first six months results. The net income was $2.1 billion or $2.61 per diluted share for the first six months of 2010, compared to $1.1 billion or $1.29 per diluted share for the first six months of 2009. Capital spending for the second quarter of 2010 was about $865 million and $1.7 billion for the first six months. Year-to-date capital expenditures by segment were 81% in Oil and Gas, 13% Midstream and the rest in Chemicals. Our total year capital expenditures is estimated to be about $4.5 billion. The capital spending rate will increase in the second half of the year largely from Iraq, Bahrain and California. Cash flow from operations for the first six months of 2010 was $4.3 billion. We used $1.7 billion of the company's cash flow to fund capital expenditures, $460 million on acquisitions and $300 million on foreign contracts. These investing cash flow uses amounted to $2.5 billion. We also used $540 million to pay dividends, and $300 million to retire debt. These and other net cash flows increased our $1.2 billion cash balance at the end of last year by $1.1 billion to $2.3 billion at June 30. The first six months' free cash flow, after capital spending and dividends but before acquisition activity and debt retirements, was about $2.1 billion. The weighted average basic shares outstanding for the six months of 2010 were $812.3 million, and the weighted average diluted shares outstanding was $813.7 million. Our debt-to-capitalization ratio was 8% at the end of the second quarter. As we look ahead to the current quarter, we expect Oil and Gas production and sales volumes to be in the range of 750 to 760 [million] BOE a day at about current oil prices. Volume increases in the third quarter are expected to come from California, Oman's Mukhaizna field and Dolphin. With regard to prices, at current market prices, $1 per barrel change in oil prices impacts Oil and Gas quarterly earnings before income taxes by about $37 million. The average second quarter WTI oil price was $78.03 per barrel. A swing of $0.50 per million BTUs in domestic gas prices have a $30 million impact on quarterly earnings before income taxes. The current NYMEX gas price is around $4.80 an MCF. Additionally, we expect exploration expense to be about $90 million for seismic and drilling for our exploration programs. For the Chemical segment, modest volume and margin improvement is expected over second quarter levels for chlor-alkali and vinyl products. The Chemical segment is expected to provide earnings for the third quarter of about $125 million. While the domestic market continues to be lackluster, export volumes are up about 13% compared to 2009. Chlorine exports are averaging about 42% of total production. We have successfully renegotiated and extended our hydrocarbon concessions in the Santa Cruz province of Argentina, increasing our oil and gas reserves from 129 million barrels to 202 million barrels. The current quarter DD&A expense reflects the resulting decrease in the DD&A rate. We have recently renegotiated a number of asset acquisitions in the Oil and Gas business that in aggregate would be about $1.5 billion. We expect these acquisitions are mainly from private individuals, largely in the gassier parts of the Permian basin where there've been several much more expensive deals recently announced. When the acquisitions are concluded, they will add to production mostly in the Midcontinent business unit, which include these parts of the Permian basin. Virtually all of the improvement in the production rate will be in subsequent years. We expect our combined worldwide tax rate in the third quarter to be about 42%. Our second quarter U.S. and foreign tax rates are included in our supplemental schedules. During the first half of the year, we drilled six conventional exploration and extension wells in California. Of these, five were outside of the Kern County discovery area. Two of these new areas are currently being tested. In the second half of the year, we are planning to drill two conventional exploration wells in the Kern County discovery area and one exploration well outside this area. We also drilled seven unconventional exploration wells in the first half of the year, of which two were successful and two were being tested. We plan to drill 15 additional unconventional exploration wells in the second half. In addition, we have drilled 10 conventional exploitation wells in the Kern County discovery area in the first half of the year, and plan to drill 23 more in the second half. We've also drilled 10 unconventional exploitation wells in California in the first half, with 25 more expected to be drilled in the second half of the year. This skid-mounted gas processing plant came online at the end of the second quarter. The existing main processing plant related to infrastructure continue to have operating issues, which are constraining Elk Hills' production. We are in the process of upgrading the infrastructure to alleviate these issues until a new gas plant comes online. We believe these upgrades will be in place by the end of the third quarter. Construction in the new gas plant has started and is expected to come online in early 2012. Copies of the press release announcing our earnings and the supplemental schedules are available on our website at www.oxy.com, or through SEC's EDGAR system. We're now ready to take your questions.

[Operator Instructions] And your first question comes from Doug Leggate of Bank of America.

Phibro appears to have been really accounting for the bulk of at least the mass compared to what the Street was expecting. For a company which is generally quite conservative and having that kind of volatility in earnings, can you speak to what is the danger of us overreacting to this versus what is your intentions in terms of perhaps trying to manage that risk a little tighter?

Yes, we've reduced the amount of their exposure and reduced the bar, if you will, in hopes of reducing the volatility. Some of that was -- he buys long-term contracts and some of it's simply just mark-to-market, but some of it was realized to -- you can't say that his trading results in the quarter were anything but lousy.

The other one I have is it really relates to acquisitions. You've talked about $1.5 billion. Just to be clear, I assume that means there's no current production with these assets...

No, I didn't say that. No.

So what is the production associated with those assets?

We haven't said because we haven't signed it, completed the deals. But there's some current production -- if I fair lease, compared to the whole business, not a sizable amount. But certainly, in the Permian, a fair size amount.

Well, I guess what I was driving right here was we're starting to hear about Occidental perhaps getting involved in structured acquisitions overtime and place it right in the Marcellus and perhaps the Montney shales. Could you maybe offer some color as to what you're thought process there and likely scale and maybe timing of overseas getting involved in those areas?

We have a modest position in the Marcellus, which we had for a while. And compared to the size of the Enterprise, fairly small, and it's out of the way some and we're basically on the edges of the play. And we'll just see how it evolves over time, but compared to the size of the Enterprise, fairly small, a fairly small total I would expect. We'll see how the drilling progresses over the next year or so, there to see what we want to do.

CapEx was a bit light. I'm just curious as to how that plays into volume as it relates to cost recovery because I'm wondering if that's one of the reasons your guidance was a little light.

Some of the adjustments in the production sharing contracts are result of not quite spending in quite as quickly and therefore, not putting into cost recovery as quick and that's at least some of it. The bulk of it was that they really didn't get at -- I'm not talking about foreign -- didn't get at the drilling in the second quarter at the pace that we had planned. And so it's a little more back-end loaded, so the wells come on pretty quickly. So some of it was related to production sharing contract capital effects and some of it was related to domestically not getting a drilling done as quickly as one might have hoped.

And so nothing terminal in here you're concerned about?

I'm always concerned. You shouldn't view that we're not concerned, but I think ultimately, is the work itself out is a matter of timing and I think a little more focus on short-term results are needed.

Our next question comes from David Heikkinen of Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: As I think about your analyst day and providing the primary and secondary opportunity in the Permian versus these acquisitions, can you talk about how will you update the number of locations and kind of that inventory, or will you give us some idea of what you think about the inventory of what you're buying given that you haven't closed any of those deals?

Yes, we'll provide aggregate numbers after the things are closed. And I haven't talk about each acquisition because these are private individuals, and these aren't public companies selling or something like that. These are private individuals who just may not want their neighbors to know they're rich. So I think we'll provide aggregate numbers rather than what each one did. But the mix is, if you look at them in aggregate and compare to some of the announced deals, these are more reasonably priced. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And the comment in the gassier parts of the Permian, does that also imply kind of more liquids rich or...

They look like the deals that have been announced recently in the mix of around half gas, around a quarter NGLs, which are related to the gas and around a quarter of oil. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And then shifting over to California exploration and kind of the combination of conventional and unconventional tests. As you think about -- remember some horizontal drilling plans and some testing of horizontals in the conventional side, can you give us any update on that activity?

Bill, do you want to do that?

David, we have two horizontals planned in and around the Kern County discovery area, have those planned to be drilled and down before the end of the year, testing some of the tighter parts of that particular structure. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: So those are still towards the back half of the year?

They are. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And then as you think about the five drills outside the discovery area, you kind of broke down the types of prospects that you're drilling at your analyst day. Can you talk about that distribution of -- or categorize those five within the bucket that you described at your analyst day of what types of prospects those are?

I think I broke them down between conventional and unconventional. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: I was meaning more specifically, kind of getting into the details of -- you had the larger concepts down to the smaller concepts?

Well, the concepts always start large, it's just sometimes they turn out small. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: Okay, fair enough. Not going to get the high potential versus discovery type?

No, we're shooting for the high potential ones, but sometimes when you drill them, they turn out to be a lot smaller. So the plan is that they're high potential but how they turn out we'll see as the year progresses. If we find something sizable, we'll tell you about it. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And then just back on the envelope on your acquisitions, a 10% added to your Permian basin production in the acquisition side, is that a reasonable type plus or minus a couple of percentage?

If you give us two or three years, yes. But buying production, upfront production, is generally the most expensive way to acquire because it sort of easy to measure. So we try to buy some production, but we also try to buy drilling potential because the returns are a lot better. Now if you pay 10 times current EBITDA for something, the way some people have, it's very hard to make the numbers work. The returns have to come from the development drilling or wherever you want. So the assets here are a mix of some current production, but a fairly sizable backlog of future drilling which will add to the numbers.

Next, from Robert Kessler of Simmons & Co. Robert Kessler - Simmons & Company: Any chance I could ask you for, given the volatility in Phibro earnings this quarter, for the net book value at quarter end and confirm that it's essentially a long-only book?

It's essentially a long-only book. As far as -- he didn't shorten anything. But initially in the beginning of the second quarter, he had some -- he used a past basket of stocks and ETF or something like that to track oil prices. And for obvious reasons, the stocks didn't track the oil prices too well, for the stocks that were in the ETF some kind of accident somewhere. And so he sort of backed out of that. But the book is -- our net investments is somewhere or under $200 million at this point. The management there owns a tracking instrument in this, so relative to his net worth, even though it's relatively sizable, he is feeling the pain disproportionately. Robert Kessler - Simmons & Company: All right. Okay. Well, thanks for giving some order of magnitude on the net exposure then going forward. In California, the risk of sort of splitting hairs quarter-to-quarter when you're in the midst of working out some kinks on Midstream and adding the capacity, any guidance on the degree of uplift in California outlook, in California production and 3Q versus 2Q?

We're expecting to go up from the third to the second. Some of the things are already sort of worked out as we go into this month. But I'm loathe to predict though the exact number because the old gas plant that work real good for a couple hours and then it won't work so good. And we've had a lot of problem getting it to work the way we would like it to. Robert Kessler - Simmons & Company: So maybe excusing the unexpected hiccups in the old oil plant, the new skid-mounted plant you expect to ramp up to full capacity fairly quickly or has it already?

It's essentially there now.

The next question comes from Arjun Murti of Goldman Sachs.

Steve, just a follow-up on some of the language on the conventional California exploration. Of the I guess five wells drilled outside of the Kern County discovery, which two are testing, just to be clear, those are -- I realize they're outside of the Kern County discovery area, but are they completely different in sort of objectives and targets.

Yes

And then the two that you'll be drilling in the second half within the discovery area, those are also separate prospects or they could be part of the existing discovery?

Well, we hope that they're an extension, but they could be separate. It looks like they're separate, but one can hope that it just makes the whole. I think they're -- you could call them either exploration or exploitation depending on your choice of words.

And any update on how some of the oiler drilling within the Kern County discovery area has been going?

Bill?

Yes, Arjun, it's going just fine. We're continuing to drill bread-and-butter oil wells in the discovery area. These are generally shallower shales, and those wells are anywhere from 200 to 300 barrel a day kind of wells on average.

If I missed in your remarks, I can read the transcript, but any comments on Colombia production, which has been trending down here a little bit?

Some of it's a production sharing contract where we put a new -- we got a new deal starting this year, so some of it's production sharing contract. But some of it is the Caño Limón field, which is in probably its last decade or so.

And then just lastly, any update on Iraq and spending there this year?

Sandy?

Yes, our rehabilitation plan has been improved, and we're moving ahead with drilling completions, work overs. The Minister of Petroleum and his ministry have expedited the approval of bringing in new rigs, and we're going to be remediating some of the facilities to get the production up to the 10% target increase for this year.

Do you have a CapEx in Iraq for this year for you all?

It's uncertain, but it's -- because the schedule is not exactly nailed down, but it's in the order of $100 million or so.

Probably in the fourth quarter.

It is back-end loaded.

Our next question comes from Paul Sankey of Deutsche Bank.

Did you break out, forgive me if I missed this, but you mentioned that 2Q production was lower than guidance. Did you split how much is California and how much was PSCs in the Middle East?

We actually didn't because when I estimated the guidance, I started with a different number that I gave you, I started with essentially a higher number. So I can't really tell you how much was this and how much is that. I think for the PSC effects, we lost 8,000 to 10,000 BOE a day.

And that's the Middle East in PSCs, not the California ones obviously?

No, the California one are pretty small. These are really not caused by the price as much as just a contract -- a re-calculation of our cost pools.

And again, I'm not sure if you mentioned in response to an earlier question, but have the infrastructure issues had a knock-on impact on the activity levels, which obviously you are ramping up quite aggressively? But I was just wondering if there was effectively a knock-on slowdown that occurs because of the problems you're having with the infrastructure?

We're planning that the infrastructure is going to be fixed, and therefore, the drilling will move forward.

Right. So you're just continuing to drill. Does that mean you're going to have essentially stranded production until the infrastructure is fixed, or how will that work out?

No. The hope is and the belief is that, that won't happen; that the infrastructure will be fixed but it's possibly we have to shut in production for short periods of time and that's where we are now effectively.

A just to follow up on Iraq. There was some word that you might be pursuing further opportunities there in the relatively short term. Is there anything more to say about that beyond what you've already said?

I think it's in the very early stages if any thing happens.

Your next question comes from David Neuhauser of Livermore Partners.

With price being relatively stable now in this band of $60 to $80, what's the biggest issue here as far as how you're going to ramp up production growth going forward? Is that the biggest hurdle?

Product price?

Production, with the price being stable, are you focusing more in production and looking for growth there? Is that going to come more so from organic, or are you still focused on some areas of acquisition?

The company's always followed a balance approach. You buy stuff when you can buy it at a reasonable price, and when you can't, you can't. So we have plenty of financial flexibility. But most of the growth will come from organically over the next few years. You might pick up something, but it's pretty hard to tell.

Is the difficulty just like -- is it valuation, that valuation is still relatively pretty high? I mean, we're seeing some sort of carve out of some assets of some other companies. And does that potentially present an opportunity, or you're really still focused on sort of the smaller private players?

We're focused on generating value for the shareholders. If you do a dilutive to value deal, you're going to destroy value. And somebody else may have different stock with different kinds of value in it. So if you pay 10x EBITDA for production, you have a high hurdle to generate future growth in order to pay for that kind of acquisition. If you pay 50% more than the next guy is willing to pay for some asset, you probably have an added value to the company unless you have some special insight. So we look for opportunities where there's some reason why we can have a competitive advantage. Some of it we have in the Permian because of the cost and such. But the purpose of the exercise in an acquisition is to make the company better, not worse. So we're not trying to dumb down the company. We're trying to strengthen the business.

But with some of the private companies that you're seeing using better value as far as the multiple, as far as what you're willing to pay, you're seeing those with the smaller?

That's right. Sometimes it works the other way where the large deals are better, and sometimes it works the other way. For example, in the ARCO Permian assets, we bought out of ARCO Permian over the last seven or eight years two packages out of there, basically, buying out virtually all of the true oil out of the packages. So what's left is sort of the residual after it's been picked over. Nothing wrong with properties, but the price paid was the full price.

And my last question really is more on looking at -- more of a macro question, looking into 2011, potentially even 2012. I mean, again, price being stable, if it stays in this band, what are some of the biggest challenges for a company like Oxy here?

Efficiently spending our capital. Remember that while we're pretty oily, that there's a fairly sizable gas component, whatever it is, $4 and change, we would hope that the price of gas would be less stable and more up.

[Operator Instructions] And your next question comes from John Herrlin [ph] of Société Générale.

With respect to your unconventional drilling, could you characterize what worked and what didn't work? Is this a primary symmetric feature, a di-generic or can you just tell us what you found so far?

I think generally, we're looking for natural fractures that are there, and we're trying to define a technique to figure it out before we drill the well. And sometimes it works okay and some times it doesn't. It's a fundamental truth that the natural frac-ing process got us cheaper than Halliburton. And so our natural frac -- we're looking for the flow from natural fractures, and we're kind of figuring out what the amount of acreage we have. We should have plenty of opportunities to find that rather than spending a boat load of money to do a high -- a large scale frac. We'll probably try some large-scale front because there's a lot of pay here, but the goal in the unconventional is to find areas with natural fracturing so it's more economical to produce. We'll always come back and try something more exotic later.

What's the orientation of the beds, and also are you looking at say crests of folds, things like that to get more fracture?

We're looking for things around the fields that have been flexed, cleverly figuring if the flexed or there might be some fracturing.

What's reasonably priced? What's your definition of reasonably priced given the recent transaction prices?

It's accretive to the company's value.

You won't specify? That's fine. Anything going on in the Hugoton with respect to the oil drilling?

Hugoton oil drilling, Bill?

Yes, John. We got two rigs running, drilling mainly these higher rate of return oil opportunities as opposed to the traditional shallow gas that you generally seen in the past in the Hugoton. But we've got a two-rig program going there, and we expect to continue that throughout the rest of this year.

With respect to acquisitions, you've already opined a little bit of that, Steve. What about Argentina? Would you want more there since there's acreage available and production available?

We'll be cautious in Argentina I think is the best way to say it.

There are no further questions. I'll turn the call back to management for closing remarks.

Thanks, very much for dialing in. If there's no further questions, please feel free to give us a call here in New York. Thanks again, and have a great day.

Thank you. This does concludes today's conference call. You may now disconnect.