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Occidental Petroleum Corporation (NYSE:OXY)

Q2 2009 Earnings Call Transcript

July 23, 2009 11:30 am ET

Executives

Chris Stavros - VP, IR

Dr. Ray Irani - Chairman and CEO

Steve Chazen - President and CFO

Will Albrecht - President of US Oil and Gas

Sandy Lowe - President of Oil and Gas International Operations

Analysts

Doug Leggate - Howard Weil

Michael LaMotte - J.P. Morgan

Michael Jacobs - Tudor Pickering & Co.

Arjun Murti - Goldman Sachs

Faisel Khan - Citigroup

Paul Sankey - Deutsche Bank

Pavel - Raymond James

Monroe Helm - CM Energy Partners

Borden Putnam - Mione Capital

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the second quarter 2009 Occidental earnings 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 conference over to Mr. Chris Stavros, Vice President of Investor Relations. Sir, you may begin.

Chris Stavros

Thank you, Paula, and good morning, everyone. I’d like to welcome you to Occidental’s second quarter 2009 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 our US Oil and Gas Operations; and Sandy Lowe, President of OXY’s International Oil and Gas Business.

In just a moment, I’ll turn the call over to Dr. Irani for some opening remarks regarding the exciting announcement we made yesterday surrounding the significant oil and gas discovery in California. Steve Chazen will then review our second quarter and six months 2009 financial results, and also provide some additional details of this discovery in California as well as our California exploration program.

Our second quarter earnings press release; investor relations supplemental schedules; and, the conference call presentation slides, which refer to Steve’s remarks, can be downloaded off of our Web site at www.oxy.com.

And I’ll now pass the call over to Dr. Irani. Dr. Irani, please go ahead.

Dr. Ray Irani

Thank you, Chris, and good morning, ladies and gentlemen. And thank you for joining us today. After yesterday’s market closed, we announced a significant discovery of oil and gas reserves in Kern County, California. We believe it to be the largest, new oil and gas discovery made in the States in more than 35 years.

This new field discovery within the outlying area of the fixed wells we have built to date contains 150 million to 250 million gross barrel equivalents of oil and gas reserves. We believe it to be probable that there are additional reserves outside the outlined area. Mr. Steve Chazen will give you more details about this exciting program later on. It’s also possible that there are similar accumulations elsewhere in OXY’s 1.1 million acre net lease hold and fee mineral holdings in California.

But let me share with you how we got to our current exciting and rewarding position. OXY has been a California oil and gas producer for more than 50 years. Our most significant expansion was in 1998 with our acquisition of the Elk Hills field from the US Government. When Elk Hills was acquired by OXY in 1998, it had approximately 425 million BOE of proven reserves.

Since then it has produced more than 364 million BOE. Yet, as a result of the technology applied by OXY over the past 11 years, we have actually been able to increase its crude reserves to more than 491 million BOE today, after all the production I mentioned earlier. So the total production of crude reserves since OXY acquired the Elk Hills field is approximately 1 billion BOE.

In the years immediately following the Elk Hills acquisition, we purchased THUMS, our operation in Long Beach Harbor, followed by our acquisition of a number of additional California properties. Those include oil and gas assets from Vintage Petroleum, plains, tide lands in Long Beach near THUMS, as well as other properties. OXY’s current combined California assets include more than 7,500 active wells located in 90 fields spanning 600 miles. They are currently producing about 130,000 BOE per day, 70% of which is oil, and at year end 2008, had approximately 708 million BOE of proven reserves.

California represents approximately 20% of OXY’s worldwide production. OXY’s currently the third largest oil producer in California and the largest natural gas producer. We see additional potential in our California holdings by our applying current technologies and the newest thinking to exploration and production. We have invested in California exploration accordingly and we expect this activity to continue for the next five to ten years. OXY’s California and US exploration production program is part of an overall effort to build a pipeline of growth projects in keeping with our long term strategy for increasing stockholder value.

In addition, we continue to grow in our other core regions. OXY’s presence and production in the Middle East, currently producing about 186,000 BOEs per day, net to us, or 29% of our total worldwide production, continues to expand. In recent months, we have signed new agreements in Bahrain, in Abu Dhabi, and Oman, where we have an agreement to develop four gas fields in the newly formed contract area in Oman. First production of those assets is expected in the near future.

Also in Oman, production of the Mukhaizna oil fields, where we have a large-scale field pipe project, is meeting its targets and growing. We are on pace to achieve an exit rate of 80,000 barrels per day at the close of 2009. I’ll now turn the call over to Steve Chazen to give you our second quarter financial results and other details.

Steve Chazen

Thank you, Ray. Net income was $682 million to the second quarter of 2009 compared to $2.3 billion in the second quarter of last year. Here’s a segment breakdown to the second quarter. Oil and gas second quarter 2009 segment earnings were $1.1 billion compared to $3.8 billion for second quarter of 2008. $2.7 billion decrease to the second quarter of 2009 earnings was due to lower crude oil and natural gas prices and higher DDNA rates, partially offset by higher sales volumes and lower operating expenses. Occidental’s average realized crude oil price in 2009 second quarter was $52.97 per barrel, a decrease of 52% from the $110.12 per barrel in the comparable period of last year.

OXY’s domestic average realized gas price for the quarter was $2.87 per MCF compared to $9.99 per MCF in second quarter of last year. Worldwide oil and gas sales volumes the second quarter of 2009 was 649,000 barrels of oil equivalent per day, an increase of 10% compared to the 588,000 barrels a day in second quarter of last year. The increase includes 20,000 BOE a day from Dolphin, 18,000 BOE a day from Argentina, 17,000 BOE a day from Oman, and 12,000 BOE a day from domestic operations, partially offset by 19,000 BOE a day from Libya.

The Argentina increase includes 8,000 BOE from new production coming on line, and the effect of 15,000 BOE a day for production losses due to a strike in the second quarter of 2008. Partially offset by a 5,000 BOE per day loss from the strike in June of this year. Dolphin’s increase reflects higher cost recovery volumes in the second quarter of 2009 resulting from a catch-up of unrecovered volumes in first quarter of 2009.

Substantially, all the domestic volume increase, the Mid-continent, Rockies, and Permian was attributable to 2008 acquisitions. California production increased as a result of new wells. Compared to the first quarter of 2009, Long Beach production decreased by 6,000 BOE a day due to its contract that is similar to a production sharing contract.

The Middle East and North Africa included higher production in Oman and Dolphin, and higher production sharing volumes, compared to last year’s second quarter. Compared to the first quarter of 2009, production sharing volumes decreased by 14,000 BOE a day.

Exploration expenses $54 million in the quarter, in line with our guidance of $60 million. Oil and gas cash production cost, excluding production in property taxes were $10.32 a barrel for the first six months of 2009, a 15% decline from last year’s 12-month cost of $12.13 a barrel. The second quarter of 2009 oil and gas cash production cost declined to $10.17 per BOE compared to the first quarter 2009 run rate of $10.48 per BOE. This declines are due to lower work over, maintenance and utilities cost, and for changes from the prior year, the effect of higher production sharing volumes. The lower cost reflects our continued cost reduction efforts.

Taxes of the non-income were $1.76 per barrel for the first six months of 2009 compared to $2.62 per barrel for all of 2008. These costs, which sensitive to product prices, reflect lower crude oil and gas prices in the first half of 2009. The second quarter of 2009, these taxes increased to $1.82 per BOE compared to the first quarter rate of $1.71 per BOE due to higher crude oil prices.

Chemical segment earnings in the second quarter of 2009 were $115 million, compared to our guidance of $100 million. Higher earnings were attributable primarily to higher than expected chlorine pricing. Chemicals earned $144 million in last year’s second quarter.

Mid-stream segment earnings in the second quarter of 2009 were $63 million, compared to $161 million in second quarter of 2008. Decline in earnings was due to the lower NGL realized prices in the gas processing business, lower earnings in crude oil marketing, and reduced margins in the power generation business. Worldwide effective tax rate was 40% second quarter compared with our guidance of 43%. The decrease in rate reflects a higher proportion expected full year domestic source of pre-tax income.

Let me now turn to OXY’s performance in the first six months. Net income was $1 billion for the first six months, compared to $4.1 billion from last year’s numbers. Capital spending for the second quarter 2009 was $831 million and $1.9 billion for the first six months. We currently anticipate total year 2009 capital spending to be at $3.6 billion, a $100 million increase from our last estimate is mostly allocated to foreign oil and gas locations.

Cash flow from operations for the six months of 2009 was $2.2 billion. We used $2.4 billion of the company’s cash flow to fund capital expenditures, acquisitions and signing bonuses, payments in Libya and Oman, and $520 million to pay dividends.

In the second quarter, we issued $750 million of foreign rate senior notes due in 2016, with net proceeds from the offering of $740 million. The cash balance at June 30 was $1.8 billion. The weighted average basic shares outstanding for the six months were $810.8 million. The weighted average diluted shares outstanding were $813.7 million.

As we look ahead in the current quarter, we expect oil and gas sales volumes to be similar to the second quarter levels at about current oil prices. The third quarter production expected to reflect decreases from Mid-continent, Rockies due to natural declines, and Dolphin, due to its production sharing contract, offset by increases in California, Argentina, and Oman.

With regard to current prices, the current market price is $1 per barrel change in oil prices, impacts oil and gas quarterly earnings before income taxes by about $39 million. The average second quarter WTI oil price is $59.62. A swing of $0.50 per million BTUs in domestic gas prices has a $20 million impact in quarterly earnings before income taxes. Our current NYMEX gas price is around $3.70. Prices in California are currently about $3.50, in the Permian around $3.30, and in the Rockies around $3.00

Additionally, we expect exploration expense to be about $50 million for seismic and drilling for exploration programs. The chemical segment the second half of the year looks exceptionally weak. Weakness in caustic soda is not being offset by chlorine price increases resulting in declines in margins.

The fourth quarter is traditionally the weakest for this business and we expect it to be about a breakeven. We expect the third quarter chemical earnings to fall at least 50% from the second quarter levels. We expect our combined worldwide tax rate in the third quarter of 2009 to be in the 40% to 42% rate depending on the split between domestic and foreign-sourced income. Our second quarter US foreign tax rates are included in the investor relations schedule.

California exploration is our next topic. Excluding the Kern County discovery discussed in yesterday's press release, in the course of a little over a year, we have drilled 34 exploration wells seeking non-traditional hydrocarbon bearing zones in California. Of these wells, nine are commercial and 16 are currently being evaluated. We expect to drill an additional eight exploration wells in this year.

OXY holds $1.1 million acres net of fee in acreage in leasehold in California, which had been acquired in the last few years to exploit these opportunities. Discoveries similar to the Kern County discovery are possible in this net acre position. Additionally, we continue to pursue shale production which is expected to produce oil on this acreage.

As we announced yesterday, we made a significant conventional, that is non-shale, without stimulation discovery in Kern County, California. We believe that there are between a 150 million and 250 million gross BOE of reserves within the small producing area delineated by the six wells drilled to date. The discovery area’s multiple producing zones with aerial geologic extent still being defined consists of both conventional oil and conventional gas bearing zones.

It is probable that there are additional reserves outside the currently defined area as the field limits have not yet been seen. This is a classic oil and gas field with large bay zones with high permeabilities. It is most similar to deep water discovery and bears no relationship at all to the so called resource plays.

In the Kern County discovery area, we are currently producing from the six wells approximately 74 million cubic feet of gas and 5,000 barrels of liquids per day, which is more than double the BOE production we disclosed last quarter. All of these productions come from conventional zones. While there will be production from shale zones in this area, the bulk of the future production will come from conventional wells.

During 2009 we expect to drill an additional 17 wells. The wells in this area cost about $3.5 million to $4 million to drill and complete, and have pay out periods of less than six months. The combined finding, development, and lifting costs are expected to be significantly less than $10 of BOE.

We will also need to expand our 400 million cubic feet per day gas processing bed plant in Elk Hills to accommodate the expected production from this Kern County discovery. Our overall working and revenue interest in this discovery is about 80%. No additional details will be provided at this time. We expect to update the production information next quarter. Copies of our press release can be found on our Web site or through the Edgar system. And now we are ready to take your questions.

Question-and-Answer Session

Operator

(Operator instructions) We'll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Doug Leggate of Howard Weil.

Doug Leggate - Howard Weil

Thanks. Good morning, everybody.

Steve Chazen

Good morning.

Doug Leggate - Howard Weil

Steve, looks like a fairly clean quarter in the earnings, so if you don't mind I'm going to focus my questions on California. Couple of things, first of all you've been very clear that this is conventional production. That to me would suggest decline rates are more in the 10% to 15% kind of range, just taking a stab as opposed to the shale 60% to 80% type of numbers.

If that is reasonable, then based from your initial production, the production rates that you're telling us from these wells, is it reasonable to think that you're looking at something like 6 million barrels in that range, over the life of the field from each of these wells? What I'm trying to get to is what's it going to take to develop these things in terms of capital costs?

Steve Chazen

Well, that’s a lot of questions in few words. We actually don't know what the decline rate is since -- the issue inside the field is the recovery rate, recovery factors. So we don't actually -- if the range we're showing you is not that we don't understand the rock volume, but we don't actually know what the recovery factors are.

There is no good analogy that we can come up with that looks like this field anywhere in the lower 48. So we have not seen any declined to this point. We're low to estimate what the decline might be. Obviously, all wells decline.

If you have multiple zones, we have to develop each zone separately. So you'll have drilling in each of the zones and production from each of the zones. So we try to indicate the well cost and the result in finding development costs. But the development program which is still at work is going to be more complicated because each of the zones left will develop separately. We can't give you better guidance because we just plain don't know at this point. Obviously, this is a very large field and test results that support the size of the field.

Dr. Ray Irani

But the development of the field will be well within our financial capability in general.

Doug Leggate - Howard Weil

Sure. I guess getting to the bottom line, what I'm trying to identify here is you talked about total costs below $10. I am taking a stab here in saying that if these are conventional wells, you're saying no decline, some probably will be a little bit conservative at least in the early days. I'm guessing your F&D costs could be under a $1. Is that ridiculous or is that not a bad place--

Steve Chazen

I don't think that we want to comment on what it might be. But obviously, with this kind of find your future development cost are going to be very, very low.

Doug Leggate - Howard Weil

All right.

Steve Chazen

And the operating cost of these flow rates it' going to be pretty modest.

Doug Leggate - Howard Weil

Okay.

Steve Chazen

We’re pretty safe with the $10 -- I think I said significantly below $10 actually.

Doug Leggate - Howard Weil

Should we look a little higher, Steve?

Steve Chazen

I don't know. You can always hope. We're still in the early days and I'm sure we'll have some disappointments over the next two or three years as we try to extend the field. Maybe I built in some dry holes ultimately and thinner zones. It’s plenty good enough with the pen and you want to use a lower number. One would be hard pressed to argue about that for very long.

Doug Leggate - Howard Weil

Okay. Let me try two quick follow-ups and I’ll let someone else jump on. First, obviously a lot of folks are trying to do, rightly or wrongly, trying to make some kind of analogy about acreage and all the rest of it. I just want to ask a real simple question. Cynthia [ph], I believe, presented to one of the local townships recently and talked about a 128,000 acres seismic program. Turned to square miles I believe that she talked about it. Is that related to this discovery or that something separate?

Steve Chazen

We have an ongoing exploration program in California. You wouldn't use seismic to look for shale wells.

Doug Leggate - Howard Weil

Okay. So I'm guessing is this could only represent about a tenth of your entire acreage position? Is that fair?

Steve Chazen

Oh, no. The exploration seismic of this program is one thing. This discovery is much smaller.

Doug Leggate - Howard Weil

Much smaller. Okay. Good. And finally, last one was just one production potential. I'm kind of thinking if I look at just using my numbers here, 30 wells, let's say over a period of time with these very limited decline rates, this could get up to 60,000 barrels a day. Is that an unrealistic number?

Steve Chazen

We actually don't want to get into production forecasting. But it's not all that complicated.

Doug Leggate - Howard Weil

Okay. Got it. I’ll let someone else jump on. Thanks a lot and congratulations.

Steve Chazen

Thank you.

Operator

Your next question comes from the line of Michael LaMotte of J.P. Morgan

Michael LaMotte - J.P. Morgan

Thanks. Good morning, guys, and a nice clean quarter. Something the press release caught my eye and that was the California volumes, talking about the Long Beach arrangement. Could you elaborate on that a little bit?

Bill Albrecht

The Long Beach arrangement is -- it's just pretty much analogous to our production sharing contract. So obviously, as prices go up, net volumes go down and vice versa

Michael LaMotte - J.P. Morgan

Okay. So that's not a new arrangement? I mean that's--?

Bill Albrecht

No, it's not.

Michael LaMotte - J.P. Morgan

It's just the price effect. Okay. I just wanted to clarify that. All right.

Steve Chazen

It is influenced by how much you spend, though.

Bill Albrecht

Of course, in terms of cost recovery.

Michael LaMotte - J.P. Morgan

Steve, question for you on rigs and particularly the comment on the big Rocky volumes going into Q3. If I'd look at this correctly, gone from about 28 rigs in the lower 48, to I think just four currently running. Can you talk about the economics of lower 48 today in general? When you think you might be ramping back up and further risks to domestic volumes if you stay at less than 10 rigs through the rest of the year?

Steve Chazen

I think Bill can answer the rig question better than I can.

Bill Albrecht

Yes, Michael. We currently have 12 rigs running today

Michael LaMotte - J.P. Morgan

12 rigs.

Bill Albrecht

Yes. We have 12 running

Michael LaMotte - J.P. Morgan

Okay.

Bill Albrecht

But not in the Piceance.

Michael LaMotte - J.P. Morgan

Okay. And then do you plan to stay in that level through the end of the year?

Bill Albrecht

We do. Yes.

Michael LaMotte - J.P. Morgan

Okay. In terms of volume degradation, is it fair to assume that the key to the Q3 pace is something that we could expect at 12 rigs to not accelerate as we move into Q4, Q1 if you stay around that level?

Bill Albrecht

Yes. As Steve reported, we're expecting our production volumes are to be relatively flat quarter-over-quarter.

Michael LaMotte - J.P. Morgan

Right. And in the next quarter overall? I'm just talking about the -- give and take in terms of the mix with Mid-con and Rockies down, I assume that that's where you're going to continue to see declines as you move forward

Steve Chazen

Yes. We'll continue to see the climb until we get the gas price in the Rockies that make sense. And based on our views of it, that's going to take a few quarters. Anytime we wanted to we just drill the wells and get the production of. But that doesn't make a lot of sense at $3.00.

Michael LaMotte - J.P. Morgan

Well, that’s very good specs. My original questions Steve, can you talk about that? We haven’t seen prices like this since ’02, ‘03, and you still had services costs anywhere between ’04 and ’06 levels. How do you see those converging over the next three quarters?

Steve Chazen

You ought to ask the service guys when they are going to cut their costs.

Michael LaMotte - J.P. Morgan

You are talking to them everyday, right?

Steve Chazen

I think we're yelling at them everyday. I don't know.

Michael LaMotte - J.P. Morgan

Are we going to get there within a couple of quarters? Clearly we've got some break in the last six months, but--

Steve Chazen

I think over time they'll converge. I think everybody is still hoping for a sizeable increase in natural gas prices for the back half of the year. No sign of that mind you. But there's a lot of hope and maybe by the service companies too. But the costs are coming down nicely and so we would expect that we’d get equilibrium here sometime next year. I think its going to be really tough this year. I think there's still a lot of drilling going on in hopes of a price rebound.

Michael LaMotte - J.P. Morgan

Okay. I'll turn it back. Thanks.

Operator

Your next question comes from the line of Michael Jacobs of Tudor Pickering & Co.

Michael Jacobs - Tudor Pickering & Co

Thank you, and good morning to you.

Steve Chazen

Good morning.

Michael Jacobs - Tudor Pickering & Co

High level question on California. We've talked about the Monterrey shale. Now we have a big discovery in a different conventional reservoir. Have you identified a new play concept in California that provides OXY and potential industry with a new core reserve and production growth engine?

Steve Chazen

Yes.

Michael Jacobs - Tudor Pickering & Co

How did the industry miss a gap to your conventional light oil play of this size?

Dr. Ray Irani

It's the same way they missed Elk Hills.

Steve Chazen

You can't really tell. California -- most of the acreage in California is controlled by a few parties, mineral acreage. And over the years, most of those parties shifted their focus out of the United States into other places, and they sent their best people to the things that they thought were more attractive. And that’s I assume what happened.

But this has been -- that’s the advantage, when we talk about we want core areas and concentration. It’s not just about that it’s easy to manage. It’s also because so our people become more knowledgeable about the areas, could see things by working on them over a long period of time to generate better results.

And this is the result of traditional geologic work. It’s not some new technology, or geo-mystics, or satellite flying over. It’s traditional geologic work by a handful of -- imagine the people that work for us. This is like geology years ago. Yes, it is a new play concept, obviously, which is why we are a little more or less transparent than you might like. And I think there is more for -- not just us but possibly for the others, if they choose to pursue it.

Michael Jacobs - Tudor Pickering & Co.

So what zones or reservoirs are you going to produce from?

Steve Chazen

We’re not saying yet.

Michael Jacobs - Tudor Pickering & Co.

Can you give us an idea of depth?

Steve Chazen

It’s deeper than the Elk Hills production.

Michael Jacobs - Tudor Pickering & Co.

Okay. And I guess just one last question, kind of thinking about California growth, reconciling your production from this new structure, and then thinking about Long Beach effects and you’re at the 130,000 barrels equivalent a day now. Where do you think you’ll be a year from now in California production?

Steve Chazen

We don’t know, almost surely more.

Michael Jacobs - Tudor Pickering & Co.

Okay. Great. Thank you.

Operator

The next question comes from Arjun Murti of Goldman Sachs.

Arjun Murti - Goldman Sachs

Thank you. On the Kern County conventional discovery, I realize it’s early going, but you alluded to additional opportunities. Do you expect it to generally be two-thirds gas going forward or is there the chance for a greater proportion of oil as you go forward? And is it in fact crude oil, or is it more natural gas liquids? Thank you.

Steve Chazen

It’s not NGLs. It’s condensate.

Arjun Murti - Goldman Sachs

Condensate. Got you.

Steve Chazen

And so it looks like -- hard to say what it looks like. But you could imagine. It’s very light and can easily be either blended or sold to refiners. So we are not talking about NGLs here at all. As far as whether it becomes oilier or not over time, we’ll see as the drilling progresses. But there’s clearly some more oil buried in zones that are available there that we really haven’t counted.

Arjun Murti - Goldman Sachs

Thank you. In terms of the shale opportunity that sounds like it’s predominantly oil, you’ve probably drilled a number of wells, what’s the timing in terms of having contents disclosed, some of the results there? And when we might hear more on the shale oil opportunities?

Steve Chazen

That’s going to take several years. Obviously, people have been diverted by this. This is much higher return and the acreage isn’t going away, and the shale. So we’re drilling shale wells, we’ll drill water shale wells in the next two or three years. But it’s pretty predictable, has a reasonably low finding cost, although not like this. And so, you’ll expect to see production growth over the next few years from that. But it’s won’t be nearly as dramatic as this.

Arjun Murti - Goldman Sachs

That’s great. And then lastly, any update on how we should be thinking there for about US capital spending over the next few years and including 2009?

Steve Chazen

This year we’re sort of -- we’ll live with what we have. We put aside in the beginning of the year a fair amount of money to fund this or something. And so, we’re using that. So we’re probably not going to increase to US this year very, very much. There’ll be some increase next year, really to exploit this. We’ll have to expand the gas plant for one thing.

It’s not a dramatic change in our capital program, a very modest change in the capital program. You’re not going to see it. This is not a huge capital program. I doubt if the capital program will hit $4 billion next year.

Arjun Murti - Goldman Sachs

That’s very helpful. Thank you very much, Steve.

Operator

The next question comes from the line of Faisel Khan of Citigroup.

Faisel Khan - Citigroup

Good morning.

Steve Chazen

Good morning.

Faisel Khan - Citigroup

I just want to clarify and make sure that the economics on the natural gas wells in California have to pay out in six months like you talked about. Was that separating the oil from the gas or was it all together?

Steve Chazen

Whatever that zone produces.

Faisel Khan - Citigroup

So at current national gas prices, the pay out from the natural gas side of production is still six months?

Steve Chazen

From the zone that it produces, which contains condensate.

Faisel Khan - Citigroup

Okay. Got you. So it’s all coming altogether. Now they’re not --

Steve Chazen

It’s not two zones.

Faisel Khan - Citigroup

Okay.

Steve Chazen

It’s really a gas condensate reservoir.

Faisel Khan - Citigroup

Okay. Understood. And then in terms of your confidence on the -- that there are probable additional reserves outside the defined area, you said that it wasn’t really seismic that was helping you to get to that, your statement that it was something else. Is that just geological work or is there something else that I’m missing?

Steve Chazen

Well, you can view it as a map. You’ve got these six wells. You want to call it the circle, if you can. And so, when you estimate reserves, you draw -- you use the well data to draw the map. So what we’ve done is you can view it as drawing the circle around the six wells, with the well data as the primary guiding light.

Obviously, if you haven't seen the limits of the field yet, you could envision that there might be one or two more locations or some other number beyond that limit. And we haven't counted that. And whether how much is there, we really can’t tell because we’ve been pleasantly surprised so far.

Faisel Khan - Citigroup

Okay, understood. Thanks for the time.

Steve Chazen Thank you.

Operator

The next question comes from the line of Paul Sankey of Deutsche Bank.

Paul Sankey - Deutsche Bank

Good morning, everyone.

Steve Chazen

Good Morning.

Paul Sankey - Deutsche Bank

Steve, I don’t know if I just missed this. You said the area at which six wells in Kern County are currently spread?

Steve Chazen

I’m sorry. How big it is?

Paul Sankey - Deutsche Bank

Yes.

Steve Chazen

No. We said it was small.

Paul Sankey - Deutsche Bank

You said it was small. I think you kind of hinted--

Steve Chazen

Yes. I think if you go back to my analogy to an offshore -- to deep water discovery, it’ll give you a feel for size, aerial size.

Paul Sankey - Deutsche Bank

So why don’t you just tell me?

Steve Chazen

What you see you feel for, because I don’t actually know the numbers at this point.

Paul Sankey - Deutsche Bank

Okay. Fair enough.

Steve Chazen

It’s not hundreds of thousands of acres.

Paul Sankey - Deutsche Bank

Yes. So you’re basically saying it’s less than a hundred thousand, right? It’s this kind of--

Steve Chazen

Much less.

Paul Sankey - Deutsche Bank

What‘s your intended expansion on the gas processing plant at Tedelco [ph]?

Steve Chazen

It’s still in the engineering phase and we’re -- each well has been a positive surprise. So the potentials get bigger as we expand the -- as the wells keep coming in.

Paul Sankey - Deutsche Bank

Could you remind me of the size of the plant right now and the--

Steve Chazen

It’s about 400 a day.

Paul Sankey - Deutsche Bank

Is it fully--

Steve Chazen

400 million.

Paul Sankey - Deutsche Bank

If not fuller.

Steve Chazen

No. Well, it’s getting full.

Paul Sankey - Deutsche Bank

Are there any major infrastructure issues surrounding the area in terms of either rig availability, off take? Anything else that we should be--

Steve Chazen

No.

Paul Sankey - Deutsche Bank

Things like that?

Steve Chazen

No.

Paul Sankey - Deutsche Bank

And the gas price is going to be -- is it more like Rockies rather than having a--

Steve Chazen

No. It’s California price.

Paul Sankey - Deutsche Bank

So there’s no--

Steve Chazen

It’s the motor price for California that’s published. Right now it’s about $3 on end.

Paul Sankey - Deutsche Bank

Yes. Okay. I got you. And you’re not going to change your outlook for volume growth at a corporate level? Just sticking with--

Steve Chazen

I think it’s pretty easy to do, to estimate this year since you’ve got two actuals and one estimate. So you’re pretty clear you’re going to be on the higher end on where we are for this year. And as we get near the end of this year we’ll probably revise our outlook for next year on the production. You know we’re still -- you have something that doubles in three months our ability to forecast where it will exit the year, and what it will do next year is -- it’s got a pretty wide band around it.

Paul Sankey - Deutsche Bank

Yes. You’re basically running -- you raising debt and running with cash on your balance sheet. Is that the plan going forward?

Steve Chazen

No. The debt was -- the Dolphin debt has been paid off this month. So there’s $600 million in cash. It’ll go out in $600 million of debt. It’ll go down. So all we did was to pre-raise the money.

Paul Sankey - Deutsche Bank

And did you intend to pile up a high level of cash? Strategic question, did you intend to continue to run at very low level of leverage, financial leverage?

Steve Chazen

Yes, we do.

Paul Sankey - Deutsche Bank

Okay, Steve. Thanks very much, I’ll leave it then. Thank you, gentlemen.

Steve Chazen

Thanks.

Operator

Your next question comes from the line of Pavel [ph] with Raymond James.

Steve Chazen

Hello?

Pavel - Raymond James

Yes. As one of the many companies that bid in the Iraq licensing round about three weeks ago, can you give us your thoughts on the process and can you also tell us if you plan to participate in subsequent rounds in Iraq?

Dr. Ray Irani

Well, as we have said consistently, we do look at opportunities that come along but we do have financial discipline. We still like appropriate returns for the risks involved in being international. Clearly California is less risky than being in Iraq and so we do expect to get high returns. The group we were in were the best bids for the bare field. However the Iraqis felt that that number was too high for them.

And so, yes. We will participate in future rounds. We’ll also participate in one-on-one negotiations. The consortium were formed already and others. But still, we must get a good return. So we’re not in love with just growing volumes. And I think that’s been the history of the company and what’s contributed to its success.

Pavel - Raymond James

That’s good. Thanks very much.

Operator

Your next question comes from the line of Monroe Helm of CM Energy Partners.

Monroe Helm - CM Energy Partners

Congratulations on the great quarter and the great discovery. Just two questions, Steve. Our recollection is when you bought Elk Hills for the theory was that it hadn’t been exploited for a long period of time. That there could be deeper horizons that could be productive. And I was just wondering if you think its perspective for this discovery that you have in Kern, and whether or not you’ve tested that theory out at Elk Hills or plan to?

Steve Chazen

That’s the disadvantage of being around a long time. You remember all the little stories. We think its perspective at Elk Hills.

Monroe Helm - CM Energy Partners

Okay. Terrific. When do you think we might test that prospective out? Would it be this year?

Steve Chazen

This year or next year. The lease isn’t going away so it’ll be there a while.

Monroe Helm - CM Energy Partners

Okay.

Steve Chazen

But as we develop -- as we figure out what’s going on, we’re redefining. We’re trying to figure out exactly how it works. It may not work the same under Elk Hills, but it does somewhere else. So we need to do some more works so we can minimize the dry holes if we can.

Monroe Helm - CM Energy Partners

Okay. Second question has to do with your thoughts on the North American acquisition market at this point in time. Obviously oil prices have come back up and there’s a number of independents that still have challenging balance sheets and may need to sell the oil reserves to focus on their gas activities. I’m thinking that last couple of quarters, you said there’s been a pretty big mismatch between the bid and ask. I was wondering if you could update us on your thoughts on that market right now and your interest in it.

Steve Chazen

Mostly it’s gas that’s available rather than oil. Our gas prospects in -- we have a fair sized gas prospect that probably has a prettier economics to an acquisition. So it’s hard to see buying gas reserves at this point. People’s expectations are still quite high. Very little oil available.

Monroe Helm - CM Energy Partners

But you will be interested in oil properties if you can find them?

Steve Chazen

We’re interested in oil properties if we could find them and we continue to look for them and probably buy small amounts regularly.

Monroe Helm - CM Energy Partners

Okay, I learned a lot. Thanks for your thoughts.

Steve Chazen

Thank you.

Operator

(Operator instructions) Your next question comes from the line of Borden Putnam of Mione Capital.

Borden Putnam - Mione Capital

Hi. Good morning, Steve. Borden Putnam. I wasn’t going to press you on geology but everybody else is trying so I thought I’d throw in an idea. I’m wondering if that Kern County play, based on your limited relieved information here is that it is primarily a structural fault-bounded track with stack zones which is why you can’t co-mingle because of different pressure. And if that’s true, I’m thinking about the tectonics at Kern County, they’re probably small, but you may have a herd of these over your acreage if you really developed a new model. Is there anything close to reality in these comments?

Steve Chazen

Well, it might be. Not a lot of salt around.

Borden Putnam - Mione Capital

Right, I realized that.

Steve Chazen

So my guess is that it’s not a salt zone.

Borden Putnam - Mione Capital

No, conventional structure. Faulting is what I’m thinking, lateral. Anyway, interesting. I look forward to more detail on that thing if you can disclose it.

Steve Chazen

Thank you.

Operator

You have a follow-up question from the line of Doug Leggate of Howard Weil.

Doug Leggate - Howard Weil

Hey, guys. Sorry for jumping back in. I was listening to the answers and the other things. It just occurred to me that you’re talking nine wells and six of course are related to this discovery but nine additional successes. Can you give us any color as to how we should read into that? Obviously these are outside of this field. So does that mean that you’ve already made additional explorations? In which case can you give any kind of analogue just to how we should look at that compared to what announced last night?

Steve Chazen

We found some other things obviously in the State. We should expect that we’ll continue to find things. If it were material to the business, we would disclose it just like we’ve disclosed this. So we have smaller discoveries, better out of some good ideas and leads. If we find something of this size, we’ll be sure to tell you about it.

Doug Leggate - Howard Weil

All right. Great. And my final one is just an update so I guess we were only two bidders in the Bahrain deep gas run. Any update as to how do you expect that to play out and potential time line for getting a conclusion?

Dr. Ray Irani

Will you comment, Sandy? Sandy Lowe heads our International Operations.

Sandy Lowe

Thank you, Dr. Irani. The Bahrain is fully approved and the handover is being worked out. The details of handover with Bapco, Bahrain Petroleum Company. We are formally joining an operating company, and that handover is expected to go from Bapco to the joint company sometime in the fourth quarter.

Doug Leggate - Howard Weil

Sandy, well, I was talking more about the deep gas bed run (inaudible) that only two companies bid for?

Dr. Ray Irani

No, the deep gas has been announced. We’re one of two in the final list. And so the decision will be made by NOGA over the next several months.

Doug Leggate - Howard Weil

All right.

Steve Chazen

I think as we’ve told you before, we have a competitive advantage because all we have to do was dig in one of our wells. So it’s pretty hard to beat that against us.

Doug Leggate - Howard Weil

Got it, all right. Thanks very much.

Operator

We’ve reached the allotted time for questions. I will now turn the conference back over to Chris Stavros for closing remarks.

Chris Stavros

Thank you very much for joining us today and if you have further follow-up questions, please call us in New York. Thanks very much.

Operator

This concludes today’s conference. You may now disconnect. Thank you for your participation.

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