西方石油 (OXY) 2009 Q2 法說會逐字稿

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.

Thank you, and good morning, everyone.

I would like to welcome you to Occidental's second quarter 2009 earnings conference call.

Joining us on this call this morning from Los Angeles are Dr.

Ray Irani, Oxy's Chairman and CEO; Steve Chazen, our President and CFO; Bill Albrecht, Oxy's President of 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 supplement schedules, and the conference call presentation slides, which refer to Steve's remarks can be downloaded off of our website at www.oxy.com.

And I'll now pass the call over Dr.

Irani.

Thank you, Chris, and good morning, ladies and gentlemen.

And thank you for joining us today.

After yesterday's market close, 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 six 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 of 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 preserves.

Since then it has produced more than 364 million BOE, yet, as the result of the technology applied by Oxy over the last 11 years, we have actually been able to increase its proved reserves to more than 491 million BOE today after all of the production I mentioned earlier, so the total production of proved reserves since Oxy acquired the Elk Hills field will be approximately 1 billion BOE.

In the years immediately following the Elk Hills acquisition we purchased our operation and Long Beach Harbor followed by the acquisition of a number of additional California properties, those includes oil and gas assets from Vintage Petroleum, Plains, Sizeland in in Long Beach near (inaudible) 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 is 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 10 years.

Oxy's California and US exploration production program is part of our 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 BOE 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 a newly formed contract area in Oman.

First production of those assets is expected in the future.

Also in Oman, production of the (inaudible) oil field, where we have a large-scale field flat project is meeting itself 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.

Thank you, Ray.

Net income was $682 million the second quarter of 2009, compared to $2.3 billion in the second quarter of last year.

Here is a segment breakdown for the second quarter.

Oil and gas, second quarter 2009 segment earnings were $1.1 billion compared to $3.8 billion for the second quarter of 2008.

$2.7 billion decrease the second quarter of 2009 earnings was due to lower crude oil and natural gas prices and higher DD&A 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 for the second quarter of last year.

Worldwide oil and gas sales volumes the second quarter of 2009 were 649,000 barrels of oil equivalent per day, an increase of 10%, compared to the 588,000 barrels a day in the second quarter of last year.

The increase includes 20,000 BOE per day from Dolphin, 18,000 BOE a day from Argentina, 17,000 from 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 a day from new production coming on line and the effect of 15,000 BOE a day for production loss due to the strike in the second quarter of 2008 partially offset by a 5,000 BOE per day loss from a strike in June of this year.

Dolphin's increase reflects higher cost recovery volumes in the second quarter of 2009 resulting from the catchup of unrecovered volumes in the first quarter of 2009.

Substantially all the domestic volume increased in the Mid Continent of Rockies and Permian was attributable to the 2008 acquisitions.

California production increased the 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 with a similar production sharing contract.

The Middle East 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 expense was $54 million in the quarter, in line with our guidance of $60 million.

Oil and gas cash production cost excluding production and 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.

In the second quarter f 2009, oil and gas cash production cost declined $10.17 per BEO, compared to the first quarter 2009 run rate of $10.48 per BOE, these declines are due to lower workover, maintenance and utility costs, and for changes from the prior year, the effective higher production sharing volumes.

The lower cost reflect our continued cost-reduction efforts.

Taxes other than 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 are 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.

The higher earnings were attributable primarily to higher than expected chlorine pricing.

Chemicals earned $144 million in last year's second quarter.

Midstream segment earnings the second quarter of 2009 were $63 million compared to $161 million in the second quarter of 2008.

Decline in earnings was due to 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% in the second quarter compared with our guidance of 43%, the decrease in rate reflects the higher proportion expected total year domestic source pre-tax income.

Let me now turn to Oxy's performance during the first six months then comes $1.1 billion for the first six months compared to $4.1 billion for last year's numbers.

Capital spending for the second quarter of 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, $100 million increase from our estimate.

It's 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.

The second quarter we issued $750 million of four and an eighth 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 of 810.8 million, and weighted average diluted shares outstanding were 813.7 billion.

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 the current oil prices.

The third quarter production is 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 and domestic gas prices has a $20 million impact on quarterly earnings.

While current NYMEX gas price is around $3.70, prices in California are currently about $3.50 and the Permian around $3.30, and the Rockies around $3.

Additionally we expect exploration expense to be about $50 million for seismic and drilling for our exploration programs.

For the chemical segment the second half of the year looks exceptionally weak.

The weakness in caustic soda is not being offset by chlorine price increases resulting in declines in margins.

Fourth quarter is traditionally the weakest for this business, and we expect it to be about a break even.

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% range 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 explorations are 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 9 are commercial and 16 are currently being evaluated.

We expect to drill an additional 8 exploration wells in this year.

Oxy holds 1.1 million acres of (inaudible) acreage lease hold in California which have been acquired in the last two 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 150 million and 250 million gross BOEs of reserves within the small producing area delineated by the six wells drilled to date.

The discovery areas multiple producing zones with aerial geologic extent is 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 pay zones of high permeabilities.

It is most similar to deep water discovery, and bears no relationship at all to so-called resource plays.

In the Kern County discovery area, we are currently producing from the six wells approximately 74 million cubic feet of gases and 5,000 barrels of liquids per day which is more than double the BOE production we disclosed last quarter.

All of this production comes 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 payoff 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 plant in Elk Hills to accommodate this 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 website or through the Edgar system.

And now we would - are ready to take your questions.

(Operator instructions).

Your first question comes from the of Doug Leggate at Howard Weil.

Thanks, good morning, everybody.

Good morning.

Steve it looks like a fairly clean quarter on the earnings, so if you don't mind I'm going to focus my questions on California.

What a surprise.

First of all you've been very clear that this is conventional production, that to me would suggest the claim rates are more in the 10%, 15% range, just taking a stab as opposed to the shale, 60 to 80% type of numbers.

If that was reasonable, then based on your initial production, the production rates that you are telling us from these wells, is it reasonable to think that you are 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 is it going to take to develop this thing in terms of capital cost?

Well, that's a lot of questions -- words.

We actually don't know what the decline rate is.

In the -- since we -- the issue in -- inside the field is recovery rate, recovery factors, so we don't actually -- 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 -- in the lower 48.

So we have not seen any decline to this point, so we're low to estimate what the decline might be.

Obviously all wells decline.

If the wells -- if you have multiple zones, we're going to have to develop each zone separately, so you'll have drilling to each of the zones and production from each of the zones.

So, we tried to indicate the well cost and -- and the resulting finding development cost, but the development program, which is still in work is going to be more complicated, because each of the zones will have to be developed separately, so -- 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 support the size of the field.

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

Sure.

I guess getting to the bottom line, what I'm trying to identify here is you've talked about total costs below $10.

I'm taking a stab here in saying that if these are conventional wells.

You are seeing no decline.

I'm probably being a little conservative at least in the early days.

I'm guessing your F&D cost could be under $1?

Is that ridiculous or is that not a bad place to start?

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

Right.

And the operating costs of these flow rates is going to be pretty modest.

Okay.

So, pretty safe with the $10.

I think I said significantly below $10 actually.

Should we look below 5, Steve?

I don't know.

You can always hope.

We're still in the early days.

Right.

And, I'm sure we'll have some disappointments over the next two or three years as we try to extend the field, so maybe I built in some dry holes ultimately.

Okay.

And thinner zones.

So it's plenty good enough with the $10, and if you want to use a lower number, one would be hard-pressed to argue about that for very long.

Okay.

Let me try two quick follow-ups, and then I'll let somebody else jump on.

First, obviously, I guess a lot of folks are trying to, rightly or wrongly trying to make some kind of analogy about take rates and all the rest of it.

I just want to ask you a real simple question.

Your -- Cynthia, I believe presented to one of the local townships recently, and talked about 128,000 acre seismic program, 200 square miles, I believe that she talked about.

Is that related to this discovery, or is that something separate?

We have an ongoing exploration program in California.

You wouldn't use seismic to look for shale wells.

Okay.

So I'm guessing this could only represent about a 10th of your entire acreage position?

Is that fair?

Oh, no, the exploration seismic program is one thing.

This discovery is much smaller than that.

Much smaller.

Okay.

Good.

And finally the last one was just on 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 a realistic number?

We actually don't want to get in to production forecasting, but it's not all that complicated.

I'll let somebody else jump on.

Thanks a lot, and congrats.

Thank you.

Your next question comes from the line of Michael LaMotte of JPMorgan.

Thanks, and good morning guys, and nice clean corner.

Something in the press release, that was the California volumes, talking about the Long Beach arrangement, could you elaborate on that a little bit?

Bill, why don't you--?

The Long Beach arrangement is pretty much analogous to our production-sharing contract.

So obviously as prices go up net volumes go down, and vice versa.

Okay.

But that's not a new arrangement, that's just--?

No, it's not.

Okay.

Just wanted to clarify that.

That's correct.

All right.

It can be influenced by how much you spend, though.

Of course, in terms of cost recovery.

Yes.

Steve, question for you on rigs, and particularly the comment on the mid-counter Rocky volumes going in to Q3.

If I look at this correctly you have gone from about 28 rigs in the lower 48 to I think just 4 currently running.

Can you talk about the economics of lower 48 today in general when you think you might be ramping back up, and -- and further risks to domestic volumes if you stay at -- say less than 10 rigs through the rest of the year?

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

Michael we currently have 12 rigs runs.

12.

Okay.

But none in the Piceance.

Do you plan to stay at about that level through the end of the year?

We do, yes.

Okay.

And then in terms of volume degradation, is it fair to assume that the Q2 to Q3 pace is something that we could expect at 12 rigs to not accelerate as we move in to Q4, Q1, if you stay around that level.

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

Right.

In the next quarter overall.

I'm just talking about, sort of, the give and take with mid-count and Rockies down, I assume that's where you will continue to see declines as you move forward into next year.

We'll continue to see declines until we get a gas price in the Rockies that makes sense, and based on our view of it that's going to take a few quarters.

So any time we wanted to, we could drill the wells and get the production up.

Doesn't make a lot of sense at $3.

Well, that sort of gets back to my original question, Steve.

Can you talk about -- we haven't seen prices like this since '02, '03, and you still have services cost sort of anywhere between an '04 and '06 level.

How do you see those converging over the next few quarters?

Well, you have got to ask the service guys when they are going to cut their costs.

Well, you are talking to them every day, right?

I think we are yelling at them every day, I don't know if we're--.

Okay.

Are we going to get to there within a couple of quarters?

Clearly you've gotten some break in the last six months but.

Yes, I think over time they'll converge.

I think everybody is still hoping for a big -- a sizable increase in natural gas prices for the back half of the year.

No sign of that, mine you, but I think there is a lot of hope, and maybe by the service companies too, but the -- the costs are coming down nicely, and so we would expect that -- that we would get equilibrium here sometime next year, but I think it is going to be really tough this year, because I think there is still a lot of drilling going on, in hopes of a price rebound.

Okay.

All right.

I'll turn it back.

Thanks.

Thank you.

Your next question comes from the line of Michael Jacobs of Tudor, Pickering, Holt.

Thank you, good morning to you.

Morning.

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 plate concept in California that provides Oxy and potentially the industry with a new core preserve and production engine?

Yes.

How did the industry miss gas here or conventional light oil plate play of this size?

It's the same way they missed Elk Hills.

Okay.

It's -- you can't really tell.

It's -- California is -- 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 in to other places, and they sent their best people to -- for 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 so our people become more knowledgeable about the areas, can see things by working on them over a long period of time, to generate better results.

This is the result of traditional geologic work.

It's not some new technology or geomystics, or satellites flying over, it's traditional geologic work by a handful of imaginative people that work for us.

This is like geology, years ago.

It is a new play concept, obviously, which is why we're a little less transparent than you might like.

So I think there's more for -- for not just us, but possibly for the others if they -- they choose to pursue it.

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

We're not saying.

Can you give us an idea of depth?

It's deeper than the Elk Hills production.

Okay.

And I guess just -- one last question, kind of thinking about California growth, reconciling your -- your production from this new structure, and then thinking about Long Beach effects, and, you are at the 130,000 barrels equivalent now, where do you think you will be a year from now in California production?

Oh, we don't know.

Probably -- almost surely more.

Okay.

Great.

Thank you.

Your next question comes from Arjun Murti of 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 a chance for greater proportion of oil as you go forward?

And is it in fact crude oil or is it more natural gas liquids?

Thank you.

It is not NGLs, it's condensate.

Got you.

It looks like -- I hate to say what it looks like but you can imagine.

It is very, very light, and can easily be either blended or sold to refiners, and -- we're 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 are clearly some more oil-bearing zones that are available there that we haven't really counted.

In terms of the shale opportunity, sounds like it's predominantly oil, you have clearly drilled a number of wells -- what's the timing in terms of having disclosed some of the results there and when we might hear more on the shale oil opportunities?

That is going to take several years.

Obviously people have been diverted by this, this is a much higher return and the acreage isn't going away in the shale.

So we're drilling shale wells.

We'll drill water shale wells in the next two or three years, but, it is pretty predictable, has 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 won't be nearly as dramatic as this.

That's great.

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

This year -- this year we're -- sort of living with what we had.

We put aside at 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 the US this year very much.

There will be some increase next year, really to exploit this, we're going to expand a gas plant for one thing.

Yes.

So, but, it's not a dramatic change in our capital program.

A very modest change in the capital program.

So you are not going to see it -- this is not a huge capital program.

Right.

I doubt if the capital program will hit $4 billion next year.

That's very helpful.

Thanks very much, Steve.

Yes.

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

Good morning.

Good morning.

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

Well, whatever that zone produces.

So at -- at current natural gas prices, the payout from -- from the natural gas side of the production is still six months?

From the zone that it produces, which contains condensate.

Okay.

Well, it's not two zones.

It's really a gas condensate reservoir.

And then in terms of your confidence that there are probable additional reserves outside of the defined area.

You said it wasn't really seismic that was helping you get to that first statement, it was something else.

Is that just a geological work, or is there something else that I'm missing?

Well, you can view it as a map, and you have got these six wells.

You want to call it a circle if you can, so when you estimate reserves, you use the -- the well data to draw the map, and so what we've done is you can view it as drawing a 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.

It -- it's -- and whether -- how much is there, or how -- we really can't tell because we -- we've been pleasantly surprised so far.

Okay.

Understood.

Thanks for the time.

Thank you.

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

Good morning, everyone.

Good morning.

Steve I don't know if I just missed this, but have you said the area in which the six wells in Kern County are currently spread?

I'm sorry?

The area--?

You said how big it is?

Yes.

No.

We said it was small.

You said it was small, and did you -- I think you kind of hinted--?

If you go back to my analogy to an offshore, to a deepwater discovery, that will give you a feel for size.

Aerial size.

So why don't you just tell me?

I'll just give you a feel for it, because I don't actually know the numbers at this point.

Fair enough.

It's not hundreds and thousands of acres.

So you are basically saying it is less than 100,000 right so it's kind of--?

Much less.

Yes.

What is your intended expansion on the gas-processing plant at Elk Hills?

It is still in the engineering phase and we're -- each well has been a positive surprise, so the pencils get bigger as we expand -- as the wells keep coming in.

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

400 million a day.

Are there--?

Well, it's getting full.

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

No.

And the gas price is going to be sort of more like Rockies rather than--?

No, it's California price.

So there's no--?

The border price for California that's published.

Right now it's about $3 an M.

Yes, okay.

I have got you.

And you are not going to change your outlook for volume growth at a corporate level?

I think it's pretty easy to do -- estimate this year, since you have two actuals and one estimate, so you are pretty clear you are going to be in the higher end of where we are for this year, and then as we get there at the end of next -- at the end of this year, we'll probably revise our outlook for the production.

We 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 has got a pretty wide band around it.

Yes.

You are basically running -- you are raising debt and running the cash on your balance sheet.

Is that the plan going forward?

No, the debt was was -- was -- the Dolphin debt -- in fact it has to be paid off this month.

So there's $600 million in cash that will go out, and $600 million of debt that will go down, so all we did was preraised the money.

And -- but do you intend this -- this is a high-level strategic question, do you intend to run a very low level of leverage, financial leverage?

Yes, we do.

Okay.

Steve, I'll leave it there.

Thank you, gentlemen.

Thanks.

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

Hello?

Yes, as one of the many Companies that bid in the Rocky licensing round about three weeks ago, can you give us your thoughts on the process, do you plan to participate in subsequent rounds in Iraq?

Well, as we have said consistently, we do look at opportunities that come along, but we do have financial discipline.

I mean, we -- we -- we still like appropriate returns for the risks involved, and being international, clearly, California is less risky than being Iraq, so we do expect to get high returns.

The group we were in with the best bids for the Bear Field.

However, the Rockies felt that that number was too high for them.

So, yes, we will participate in future rounds.

We'll also participate in one on one negotiations.

The consortium we have formed already, and others.

But we still must get a good return.

We are not in love with just growing volume.

I think that's been the history of the Company and what's contributed to its success.

Sounds good.

Thanks very much.

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

Congratulations on a great quarter, and a great discovery.

Thank you.

Just two questions, Steve.

My recollection was when you bought Elk Hills part of the theory was that because 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 it is prospective for this discovery that you have at Current?

And whether or not you've tested that theory out at the Elk Hills or plan to?

That's the disadvantage of being around a long time, you remember all of the old stories.

You -- we think it's prospective at Elk Hills.

Okay.

Terrific.

When do you think you might test that prospectivity out?

Would it be this year?

Problem -- yes, this year and next year.

The lease isn't going away, so it will be there a while, so as we develop -- as we figure out what is going on, we're redefining -- we're trying to figure out exactly how it works.

It may not work the same under Elk Hills as it does somewhere else, so we need to do some more work so we can minimize the -- the dry holes if we can.

Okay.

Second question has to do with our your thoughts on the North American acquisition market at this point in time.

Obviously oil prices have come back up but there is a number of independents that still have challenging balance sheets, and maybe just other oil reserves to focus on or gas activities.

I think in the last couple of quarters, you said there has been a pretty big mismatch between the bid and ask.

I just wondered if you could update us on your thoughts on that market right now, and your interest in it?

Most of it so gas that's available rather than oil, or gas prospects.

We have a fair-sized gas prospect that probably has superior economics to an acquisition.

So, it's hard to see buying gas reserves at this point.

People's expectations are still very high.

Very little oil available.

You would be interested in oil properties if you could find them obviously?

We are interested in oil properties if we can find them, and we continue to look for them, and probably buy small amounts regularly.

Okay.

Thanks for your thoughts.

Thank you.

(Operator instructions).

Your next question comes from the line of Borden Putnam of (inaudible).

Good morning, Steve, Borden Putnam, I wasn't going to press you on the 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 release information here, if it is primarily a structural fault-bounded track with stack zones which is why you can't go mingle because of different pressure?

And if that's true, thinking about the tectonics at Kern County they are probably small, but you may have a herd of these over your acreage if you've really developed a new model.

Is there anything close to reality in those comments?

There might be.

But not a lot of salt around.

Right.

I realize that.

My guess is there is -- it is not a salt zone.

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.

Thank you.

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

Sorry for jumping back in but as I was listening to your answers in the other things it just occurred to me that you are talking nine -- 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 in to that?

Obviously these are outside of this field, so does that mean that we're -- you have already made additional -- additional explorations, in which case, can you give any kind of analog as to how we should look at that compared to what you learned last night?

We found some other things obviously in the States.

You should expect that we'll continue to fine things.

If it were material to the business, we would disclose it just like we have disclosed this, so, we have smaller discoveries, better -- some good ideas, some leads, if we find something this size, we'll be sure to tell you about it.

All right.

Great.

And my final one is just an update, I guess there are only two bidders in the (inaudible) gas run, any update as to, how you expect that to play out, and potential time line for getting a conclusion?

Will you comment, Sandy.

Sandy Lowe is our International Operations.

Thank you, Dr.

Ray Irani.

Bahrain is fully approved and the handover is being worked out, the detail of the handover with Barium Petroleum Company.

We're forming a joint operating company.

And that handover is expected to go from Bapta to the joint company sometime in the fourth quarter.

I was talking more about the deep gas bed run.

I understand only two companies bid for it.

No, the deep gas has been announced.

We're one of two on the final list, so the decision will be made by NOGA, over the next several months.

All right.

I think as we told you before, we had a competitive advantage, because all we had to do was deepen one of our wells, so pretty hard to bid against us.

Got it.

All right.

Thanks very much.

We have reached the allotted time for questions.

I will now turn the conference back over to Chris Stavros for closing remarks.

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.

Bye.

This concludes today's conference.

You may now disconnect.

Thank you for your participation.