Thank you. I would like to thank everyone for joining our call today and would like to remind everyone that we are conducting the call under safe harbour.

Today, Michael Duginski, our Chief Operating Officer and David Wolf, our Chief Financial Officer are with me today to discuss our Q3 results. Berry Petroleum has posted third quarter results for 2008 net income of $53 million, $1.17 per share for the quarter compared to $26.9 million or $0.60 per share in the third quarter of 2007.

Discretionary cash flow was $122 million, up 70% compared to the $72 million recorded in the third quarter of 2007. Revenues rose to over $208 million, our realized sales price of $64.98 per barrel with 36% higher than the prices for the comparable quarter last year.

Our production for the quarter was 35,150 barrels of oil equivalent per day, up 31% from our Q2 2007 production of 26,873 and up 21% over the second quarter of this year. Oil production was up about 10% over last year's numbers and gas production was up over 90%.

Net income for the first nine months of 2008 was $145 million, up 49% from $98 million last year. Discretionary cash flow was total $332 million for the first nine months based on revenues of $642 million, realized sales price of $66.37 a barrel and production of 30,750 barrels a day, up 16% over last year.

Michael Duginski, our Chief Operating Officer will now update you on the performance of our major assets. Michael?

Thank you Bob. Our diatomite production continues to demonstrate strong growth averaging 2100 barrels a day, increase...

a 24% increase from the second quarter. We drilled 23 wells in the quarter and injected over 14,000 barrels per day.

We've also drilled 6 delineation wells this year, in the northern portion of the field. And as we previously announced in August, we're increasing our estimate of original oil in place by over 35% to 330 million barrels.

These wells encountered 300 foot to 400 foot thick oil column with reservoir characteristics similar to Berry's current diatomite development. As a result, we have increased our production expectation over 12,000 barrels a day by 2015.

Finding and development costs are expected to be between $6 and $8 a barrel. Assuming a steam oil ratio of 6 to 1 and a natural gas price of $7.50 per MMBtu, operating cost should be approximately $20 a barrel.

Even below $60 WTI price, this project delivers strong rates of return. We continue to develop with one rig and are currently averaging 2400 barrels a day.

In the northern areas of the field, we are testing lower pressure stream injection for the shallower wells, and we are encouraged by the response to date. If this response continues, we expect to exit 2008 at 3000 barrels per day.

In the Piceance basin, we produced 22.7 million a day in the quarter, a 36% increase over the second quarter, including a 2 million a day curtailment for the month of September due to the Rockies maintenance shutdown. Production continues to grow surpassing 30 million a day as the summer completion season has progressed.

We drilled 26 wells with four rigs in the third quarter and realized further drilling efficiency with drilling times as low as 9 days, averaging 14 days for the quarter which includes rig moves. This represents an average well cost of just over $2 million per well.

However, we have reduced our rig count to a single rig for the near term to control our capital spend rate. The reservoir continues to perform as expected, and we're shifting our focus on new completion techniques to improve recovery now that we have a well cost under control.

We also closed our East Texas acquisition and the assets contribute 25.9 million a day in the quarter. We've assembled our asset team and production should increase from its current level of approximately 30 million a day as our team takes over the field operations, drilling and completions from the seller November 1ar, 2008.

We drilled nine wells on properties during the quarter but only brought two of these wells on to production. We plan to drill approximately eight wells during the fourth quarter and complete the remaining wells drilled during the third quarter of 2008.

We're in the process of re-leasing three of the five rigs and plan to drill with two rigs going forward. At $6 Henry Hub gas prices, our East Texas vertical program still has 25% rates of return.

As other companies press release, cross-section show our Haynesville position in the East Texas is excellent with over 300 feet of vertical section. As we previously stated, we drilled four vertical, horizontal appraisal wells confirming the shale section, and these wells are actually between 1.2 and 2.1 million a day per well, and we believe demonstrated the productivity of the four horizontal development of this resource.

We expect to drill our first Haynesville horizontal well in the first half of 2009. Other producing areas are on plan.

At Poso Creek, we completed 20-well program in September, and production has increased to 3,300 barrels a day. We expect production to continue to grow as we increase steam injection in the fourth quarter.

In Utah, production increased by 6% to 6,400 barrels a day in the third quarter. We're currently drilling the 8th and final well of the '08 horse [ph] program, five of these wells have now been completed with very encouraging results ranging from 70 barrels a day to over 200 barrels a day per well.

The 400-well Ashley Forest EIS continues to progress towards an anticipated approval in early 2009. Now David Wolf, our CFO, will review our financial performance.

Thanks, Michael. Our oil and gas revenues this quarter were $208 million.

Compared to the second quarter of 2008, oil and gas revenues increased 12% from $185 million. Discretionary cash flow for the first nine months of 2008 was $332 million.

Capital expenditures during the first nine months were $306 million. At $60 WTI for the remainder of the year, we would expect to generate approximately $400 million of discretionary cash flow for the full year which would fully fund our capital program.

Operating costs for oil and gas were higher in the third quarter of 2008 by $900,000 or 2%. Our East Texas acquisition increased our total operating costs on a nominal basis.

The acquisition decreased our per-barrel operating costs as these natural gas assets have lower per-barrel operating costs. In the second quarter, our operating costs decreased to $17.33 per BOE, in the third quarter of 2008 from $20.9.

Our production taxes increased between the second quarter of 2008 and the third quarter of 2008 from $2.83 per BOE to $2.99 per BOE. This increase reflects periodic updates to stationary rates [ph].

Our DD&A was $12.51 per BOE in the third quarter, up from $11.02 per BOE in the second quarter. This increase is a result of integrating our East Texas assets which have higher finding and development costs than our legacy assets.

We expect our effective income tax rate in 2008 to remain consistent at approximately 37%. In our Form 10-Q which we filed this morning for the quarter ended September 30, 2008 we have updated our anticipated range for full year 2008 costs.

We expect our operating costs to average in the range of $17 to $19 per BOE. We expect production taxes to range from $2.50 to $3 per BOE.

We expect DD&A costs to average between $11.75 to $12.25 per BOE. We expect SG&A costs to average between $4 and $4.50 per BOE, and we expect interest expense to average between $1.50 and $2 per BOE.

On October 17, we amended our senior secured credit facility which increased our volume base from $1 billion to $1.25 billion, and our commitment increased to $1.08 billion. The amendment includes an accordion feature which allows us to increase volume commitments up to the 1.25 volume base without further lender approvals.

With this amendment in place, our liquidity is approximately $144 million. With that, I'll turn it back over to Bob.

Thank you, David. We clearly recognize the world's changing oil and gas producers like Berry.

And we are responding to the change. Our current focus is controlling those parts of our business that are under our control.

As Michael just detailed for you, we are already reducing our activity and are releasing eight of the 12 rigs that we are drilling in the third quarter. We do expect the fourth quarter production to average somewhere between 37,000 and 38000 barrels a day.

We're maintaining flexibility with respect to our capital planning for next year. It is our intention to invest approximately $200 million of capital if crude oil prices are in the $65 a barrel range, and we're keeping our options open to further alter our capital depending on movements in price.

However, I should point out that if crude oil averages $50 a barrel in 2009, roughly 20,000 barrels a day of crude are in effect hedged to about $65 a barrel. Approximately half of our budget next year will be focused on our oil projects such as the final phase of the Poso Creek development, expansion of the diatomite development, some additional horizontal wells at South Midway and beginning our Ashley Forest drilling.

Gas projects will focus on producing, our wells in East Texas waiting on completion with some new drilling including one to two horizontals in the Haynesville. We will also be completing a number of Piceance wells drilled in 2008 and drilling some acreage earning wells.

With the $200 million capital budget, we would intend to roughly maintain production in the plus or minus 37,000 barrels a day range while generating cash flow well above the capital spend. So with this review of the quarter and our comments going forward, we would entertain questions.

Thank you. Question And Answer

Thank you and congrats on the renewed focus on differential advantage basins given the current commodity price environment. I have a few questions for Michael.

Recognizing that you still have to take your recommended budget to the Board for approval, I would like to take through your assets and get a better understanding of how '09 shapes up and implications for 2010 growth. Starting out East Texas, you previously alluded to, slightly less than half year of CapEx having a run rate of $75 million, and when we think about your inventories about 100 new drills and about 75 recompletes, how should we think about the revised 2009-2010 drilling plan in terms of recompletes and new wells and kind of what are the new CapEx implications?

Yes I understand the question, and what I would tell you is the acquisition... our acquisition view of the East Texas properties, we had a three-rig program.

We were reducing from a five-rig program that the seller was running at, and we were going to reduce to a three-rig program. So this will slightly reduce our growth rate.

But what I would say is offset by the number of completions that we have that our inventory right now which are 17... which will be 17 by the end of the quarter and then we have a number of recompletions also.

So even though we are not drilling, we should be able to keep production pretty well on track with the acquisitions... with the acquisition view, and we have the upside potential of the two horizontal wells we plan on drilling and those were not in our acquisition view.

So I think at worst case, Michael, I think that we would stretch our peak out maybe a year or so farther than what we had forecasted in the original acquisition. Ticking down the large projects that we have, I would say based on our capital project...

capital expenditures in the diatomite project you should see that projection of production growth pretty much on track. We are going to fund that project, and we are going to pace drilling development much closer to the facility and infrastructure development.

So even though we'll have a slightly lower spend in '09 we should be on track on production.

So just to confirm. You still go from 32 to about $70 million over the next few years.

Might take a year longer and then on that might the grow profile doesn't change from what we have seen in your presentations?

That's correct.

Okay, that makes sense. Just moving up to the Piceance, thinking about production implications from dropping 4 rigs going to 1 rig.

You talked about drilling a hole. Can you give us an idea of how large the backlog of wells you have and kind of your plans for bringing them online and then how we should think about production, within the context of seasonality as well?

What we're planning... currently our inventory is 12 wells that we drilled in '08 and that we'll complete in '08 and then we'll have an additional 18 wells that we've already drilled, we'll complete those in '09.

We also have an inventory of 22 recompletions for '09. So with all that activity and a reduction in drilling, we would expect our production in the Piceance to be flat for next year.

So that's probably the most significant impact of the reduced capital budget we'll be seeing at the Piceance.

Got you.So just kind of production implications, we probably see a fourth is kind of flattish with third quarter, and then we have a drop-off in the first quarter and then kind of ticking up towards back in the second quarter and then another ramp in the third quarter of '09. Is that --

That's about a quarter off. Let's say, as our production is ramping up pretty dramatically right now from the recompletions that we did in the third quarter.

We should see that continue to rise in the first quarter, then you will see the decline in the second quarter and possibly into the third quarter, then our summer completions next year will start the ramp production back up resulting in about a flat production profile.

Great, thank you very much. Look forward to the analyst day.

Thank you, Mike.

Hi good afternoon guys, congratulation on the nice quarter.

Thank you, Phil.

Can you talk these recompletions in the Piceance, can you give us a little more detail on them? It's the first time I've really heard you talk about that much, and what actually goes into them, what do you get out of them?

Yes Phil, what they are... some of the wells we had such strong production particularly in the North parachute area in the lower completions that we...

we delayed the upper section of the well. So what I'd say is costs are going to be between $200,000 and $400,000 to complete those upper sections.

So you can imagine those are very economic at most gas prices, very low cost F&D to bring that additional production on. And again like I said, we have...

we have an inventory about 22 of those wells that we only completed the lower section that we'll be re-completing the upper section.

Great. And were these reserves previously booked as behind pipe then [ph].

They're currently booked as PMP, that's correct.

Great. And can you talk like in the Brundage Canyon area, when do you think you would put a rig back out there, and can you talk a little bit about the differential in your oil prices?

And in the Q, you talked about $15 to $20 differential based upon a $60 to $80 price deck. And that was larger than what I used to be or what I was kind of modeling in.

Can you talk a little bit about that, and at what price you'd probably put a rig back out there, what kind of timing that looks like?

Well I think the first well as we probably drill back in the winter would be in the four... actually four.

We would expect to get EIS approval in time to start drilling after winter steps are over. So I would expect the dollars that we spend there will probably be spent kind of June through the summer.

It's a little bit cheaper and easier to move around there. Differentials, and then you went till with the black wax, or kind of a changing number, simply because as many of you know, if you go try to post a differential today, you'll see one number, but that posting doesn't take into account, gravity differential doesn't take into account, trucking doesn't take into account.

If you don't have a contract, you're probably not selling the black wax on the spot market in summer... in the winter time because the implications of the wax on diesel spec.

So we feel pretty good about our contract and we think it's a reasonable reflection of the all-in costs to market back wax in the basin on an annual basis.

And Bob what's the contract stipulated as far as... have a price we model in [ph]?

But I think we have in the Q is pretty accurate.

Okay so $15 to $20 differential depending upon that $60 to $80.

That's right.

Terrific.And then I just have one last question, let me hop on here. Just given the difference in guidance for '09 on a production basis, Dave, can you give you just a hard number for full year G&A in '09 and what...

I am looking like $49 million, is that ball park or is it... should be little higher?

I know '09 will be slightly higher then?

Yes... well I mean it's a two edged sword as you know as one can expect.

I mean we'll have some inflation in G&A but we're also looking at a lot of issues like contractors, other personnel expenses, implications on long-term comp. This year, on our G&A we've had to factor in our relocation of the corporate office to Denver and we had a couple of lot of extraordinary events.

So I wouldn't expect that number to go up.

Materially...?

I wouldn't expect at 3% to 4% increase in inflation. I think we'll do our best to hold that flat.

Okay. Great guy's thanks and good job again.

Thank you.

Thank you. Good morning, after and I guess we're kind of close where you are.

I wanted to just go back to the production trajectory. If you can just talk a little bit more about, I guess when you look at four quarters from now, the end of fourth quarter of '09, how do you see Diatomite versus 4Q '08?

How do you see EPS, how do you see... how do you see the remaining kind of conventional base?

And then maybe more specifically, can you touch a little bit on this earlier... how many wells and how many million cubic feet of production do you believe are behind pipes where you did not drill, they would come on naturally over the course of the next few quarters?

Thanks.

So you're kind of asking all of our questions Brian which was somewhat a work in progress. Some of it we've got sold out, some of we don't.

We would Diatomite continue to ramp up and be somewhere four quarters out in the 4,000 maybe 4500 barrel a day range. We would see Piceance with a couple of a soft tools through the year.

I think the way we would see a probably fourth quarter, I'm going to say somewhere maybe $27 million a day, something like that, at least I'm going to give you a pretty broad range but some of that depends on how many re-completions we have and re-completion North Parachute versus Guardian Goldspic. I'm going to tell you somewhere between $25 and $30 million a year from now in Piceance.

Okay. Do you feel like, do you feel like, I guess in Iraq especially in the Piceance that you're a bit of micro cause of others in that.

That others could also potentially reign in the recount significantly? But it sounds like you're not really forecasting that huge an impact to production growth that we see with the next four quarters or is it something you feel like you're you need to ...you need to bury?

Well, we hate to speak for other people's business. But we do think that drilling in 9 days to12 days, we think we're very competitive on the drilling side.

This softness in price does give us a chance now to go back and do some of our reservoir work in the base and then... and now starts really to focus on the EUR per well.

We do think we have some opportunity for improvement particularly in the deeper part of our acreage which will be on the North Parachute side. I can't...

I really don't...other than to say what we hear from our production people in the field, which may or may not be how accurate that is. We do think rigs are coming out of the basin.

We don't know how much behind pipe inventory other operators have. One thing that we do like in our position is we do that $35 million a day a fund transportation.

So we do think that that gives a good foundation for our production there. Particularly, on these relatively economic and good return completions that we have waiting to go.

So, we're micro comps [ph] we're first mover in the basin. Brian I really just...

I really hesitate to project things, I really don't have first hand knowledge of.

Okay, thanks. And then lastly on the cost cuttings trends for your production or your operating costs, and what gas price do you assume in that and what variability would we expect if gas prices go up and down around the number?

Brian, are you speaking in terms of '09?

I guess the 17 that I think you put that $17 to $19 a barrel range which I think was a full year '08 but I think if we generally put down into the fourth quarter, one's should expect that the operating cost will be down from third quarter?

The range we have about $650 to $7.

Okay. And so when you think you had in when do you think you had in next year, there should be a decrease from the 17 to 19, one would think?

Yes if gas was down as you all know operating expense move down quite significantly.

Great. Thank you.

Thanks Brian.

Hi, morning everyone, and still morning in reference to Brian's comment. If I look at...

Bob this is a question for you, if I look at going from four rigs to four, if you look at turning volume for next year, how many rigs does that incorporate into that, that type of number, I assume it would be higher than four?

I would say... I'm going to say let me just think about that on, yes I was going to say, I would say five to six.

We might guess, we might estimate.

Okay and then do you worry about from a manage... from a efficiency standpoint, operating standpoint.

You obviously loose some cruise going from 12 to 4 or just loose some efficiency trying to ramp that back up, how do you think about that?

Well we're, I mean it is some thing we worry about lot, and particularly in places where we've worked really hard to get really efficient but what you do is you rank your rigs from most efficient to least efficient and you start from the bottom and you let them go and you try to keep the most efficient rigs. You know this kind of change everybody is trying to determine whether we're in a B-shaped cycle here or whether we're in a prolonged U-shape cycle here.

And when I call other setup worked hard to change our personnel across our entire companies, I mean we're going to work hard to hold on all of our people because we've worked hard to put the teams in place. So we're not going to capital yearly make any changes.

But we have... we feel like the bell whether has sounded and it was time to reduce activity.

Okay what your personnel bearing aside what's Bob Heinemann outlook on oil prices?

I should have asked you first

Do I beat you to the first?

Yes well done. I think what we're saying when we've been in that's precipitates is drop it's just hard to forecast.

And... we have pride in doing in the company as we have pride in doing what we said we were going to do and that said on the street all year.

If WTI goes to 40, we're going to payoff some debt and we'll figure out a way to do that and we're going to do that. The pharma all in ...the inside pharma zone is predicted.

We're tomorrow what it is today. And today we're back at about $68 and our business feels pretty good at $70.

I think what you're going to see just like we always do when we go through these swings is we going to go through a period time where costs are going to recalibrate just like prices come down. That's what I think is really the thing to be watching and tracking in 2009 is can we get price down as quickly as possible and get price down to an area where we like our businesses in $70 a barrel.

We did one time before and felt really good about it. There is a way to do that again, that's going to be our focus.

Okay and do you consider acquisitions or what would it take? What it would take the marketplace for you to step up and try to buy the stressed asset and stressed company?

Well it's a... its not on the forefront of our minds but I would say we would issue equity to do an acquisition.

That acquisition will have to be accretive and finding accretive acquisitions that would be equity funded would be challenge given where we are today.

All right. Question I guess for David Wolf, how...

when can the banks do a re-determination?

They can elect one re-determination, special re-determination between now and April. We'd expect that the April re-determination will be the next time folks look at our reserves.

Okay. Alright and this October announcement that incorporated video reserves?

Yes.

Okay. And then one last question for whomever.

You estimated some production or some contracts in the Piceance, some capacity was where I was looking for, but 35 million a day? And then another 35 million a day copier out I think on Ruby?

Correct.

Did you just sell... how do you...

if you're producing 22 million, but just presumably that pulls back, what do you do with that excess capacity?

We market it, and we actually made a few pennies in the quarter. That market may a few million dollars of marketing or partners.

Okay. That's ...that's will be talked in the queue.

Right.

And then what about the... how do you look at, and I know your drilling commitments, a hundred wells, I guess less than 100 wells to get down before the end of 2010, beginning of 2011.

What happens if we stated the press environment. I'm assuming you need...

to get a hundred ... to get ninety wells down the Piceance over the next two years, you got a pretty good ramp on the rig count at some point.

How do you think about that?

Well that, that's correct. With the exception, and that's through 2011, so we have three years left on that, and we put down quite a few wells.

But if we do reduce activity next year, we'll obviously be looking for a price response for us to add additional rigs in the remaining two years. There's other options.

We could potentially join venture at the acreage with a third-party, we could have someone form into that acreage or we could potentially negotiate different terms on leases.

Okay. How many wells can you drill at your current run rate with one rig?

How many wells per year with one rig?

We can drill 30 ... 27 to 33 wells per year.

So we would have drilled one rig for three years to meet that commitment. So, if we take a rig out per year, we would have to have two...

yes.

All right. That's all I got thanks.

Thank you, David.

Hi Bob.

Eric.

Question on your balance sheet, when we feel comfortable with your balance sheet, what kind of debt levels David? Regardless of the prices you know.

I think from a balance sheet perspective, it was more liquidity comment that we have a 144 million in liquidity. Ideally we'd like a years worth of CapEx, normalized CapEx if you will, tucked away in terms of capacity under our lines.

So, that's... this year in 2009 would be $200 million or more.

Is normalized $350 to $400 million, is that a good normalized kind of number?

Right. If we get back to commodity prices that we saw on the first few quarters that would be a liquidity level, we feel more comfortable with.

Okay. And then following on Dave's question about acquisitions, are any opportunity for divestitures I mean DJ basin what's going on there is that potential to sell an asset and reinvest in the place like East Texas or not?

Well, we have no assets that are currently being marketed for sale. We think we can execute our business without it, but of course we've done it in the past and if we had an offer that was presented to us, we would obviously consider.

But we're not actively pursuing asset sales. Obviously, they're going to be plenty of assets in the industry for sale, and then everybody is going to be looking for value and look for operational fits that are, maybe better one company and than another company.

We can, we'll be fine without it. We would certainly consider any case and to see if we can do better with them.

And the last question just on any color on leasing and the Haynesville trend that East Texas are you seeing cost for acreage drop, any ability there to pickup some bargains there and maybe build up your position or?

Yes we've seen, in a dramatic drop in I guess the street talk of what leases are going forward now in the Haynesville, we have a unique opportunity similar to lot of our competitors in the Haynesville. They have a policy that they're not going to drill any HPP well next year.

So what we like to do is, we like to work with some of our competitors to use a rig to drill wells or to earn acreage. And so that's really one of our strategy its going to be next year is to try to add to our portfolio with a limited capital budget by drilling Haynesville wells and earning acreage.

Great thanks, understood follow-up on other folks comments is commenting you for focusing on returns and balancing strength over just growth for growth sakes.

Thanks Eric.

Yes thanks. Gentlemen, I just wanted to circle back to your reserve guidance of 235 to 250.

Does any of the revise spending at your drilling program is lining down to that, should that put us toward the lower end, or is there any update you can give us on that?

We... Chris one of the things we did in the Q is we did lower the low end of the guidance to 230.

I am sorry, I didn't catch that.

And a high end down to 245, if prices where... prices at the end of the year are where they are right now we would feel okay about our number probably in the mid point of that guidance maybe 240-235 or 240 we just want to give ourselves a little room in case we had some sealing test issue right at the end of the year.

Right now we don't see that but first we didn't see $65 of crude 90 days ago either. So, we still feel okay about our reserves.

We think we got a good confirmation of where we would be through our re-determination of the credit facility. But we just wanted to feel a little conservative.

And as far as the price sensitivity goes I assume that's the Piceance that is the most sensitive area?

We've always said with respect to a development perspective, at least we said the last year that we expect to development perspective Piceance is the most price sensitive basin. And so, that's scenario we have to watch.

The thing we really looking at are be the tails of the production to see if we get any kind of cutoff at a lower price and this was an issue about a year ago they came up for producers and we have said at that time, we did an assessment so we might have 12 to 15 million barrels at risk, due to a cutoff. We have not really tried to quantify that again, so I'm really trying to pick my memory bank from that 12 to 18 months ago but I don't really, I really think it's...

from a reserve perspective its more than cutoff on the tail.

Okay. So, we're not seeing any increase sensitivity due to the recovery factors that the Diatomite assets that still not affected it, at current oil prices?

Just, just you get out there pretty far. But also when you start to get out pretty far I mean the strips not bad, when you get out as far as our tail would be in the Diatomite side, so I'm not overly concerned about the Diatomite.

Okay. Great, thank you guys.

Thanks Chris.

Hi, thanks. And Bob just to clarify, if you are going to add rigs next year I assume to get one at the Piceance and then did you say one in the Uinta?

Well, you starting to ask me questions about half a rigs. So, I don't know we've run a rig, we don't run a rig for the full year in the Uinta I don't think.

Depending on some other options that we're pursuing in the Piceance maybe, but, we're going to get back to our return model there. And as for sales, to justify going to more rigs probably going to have to see a higher price, which given all the capital which is from lot of natural gas producers in the U.S., we could see a quicker response in natural gas and crude oil.

When you're coming down as fast as we've come down, we've got to finish the real other equation, real inside of the question that you're asking is whether we go back in first?

Yes, yes.

We're just not quite; we are quite tied enough on that answer you had David.

Okay that's fair. Last follow-up if...

you slash your budget half but you still over grow pretty significantly on organic basis. Can you give us a feel for what your decline rate is?

What I'm trying to get out is you obviously anchored by your legacy. Some set Midway asset.

I'd assume the corporate decline rate is lower than the average E&P Company?

Well we'd like to say that and we believe that and that's basically because our relatively low base decline in legacy assets. In California, as well as good growth in our oil assets in the Diatomite and at Poso.

That's got to be offset by declines that we're going to see in our gas basins. The good news there is we do have completions behind pipe that can...

we can use to offset that decline. Obviously the next question someone's going to ask is what is 2010 going to look like, and right now, let's say we'll worry about 2010 when we get into...

we see some price singles in '09 to know what our activity levels going to be.

Yes. Do you have a feel for what that number is, corporate wise?

Not yet. Not yet.

Okay.

It's just too early.

But I'm saying as far as the corporate decline rate?

Well Bob, you know an answer to that question is... is based on our development activities in the start of the floods in both Poso Creek and in the Diatomite we're still seeing increasing volumes there from our steam injection.

We don't need drilling; we need an injection response. Like you said that your winter will decline, and the Piceance will increase and then decline, East Texas will still have some growth in it, so it's...

there's really not a lot of decline in the base assets right now.

The other... the other thing that we're looking at, David is if we got...

if we got crude oil down at low 40s and gas at five bucks, is our steaming operation's still economic, are we still cash positive and --

Yes.

We're doing a pretty thorough examination. All that looks really good so far.

So we... we don't see any reduction or steam injection.

All right. That's fair.

Thanks.

Thank you.

Yes, hey Bob, I think at the time you made this Texas acquisition, you talked about an all in fully developed cost per MCF of around 275-280 I...

That's correct.

Where... since then what's hedge you thinking changed it all and if grades drop and cost drop next year, where do you think that could go?

Well what we would say today as snapshot time is we feel really good about the 275 plus we think we've... we're confirming some of our Haynesville upside potential which was not in our acquisition which on a go forward basis would be less than 275 and we're seeing I don't know...

I don't know... I don't want to pre-maturely call rig rates in East Texas yet because I'm not sure where they are going to settle.

We're also starting to bring some of our drilling practice that helps quite a bit in Piceance. We're going to bring some of those same practices to East Texas to try to reduce our cost, so it'd be 275 Ray on a snapshot today with a real focus to bring it down.

Okay. Got it.

Thanks very much.

Appreciate it.

All right, thank you. Dave Tameron actually.

Hi, can you hear me?

We can yes.

Sorry. Dave Tameron actually asked my question.

I didn't want to follow-up on 2010 production if we were to assume that you implement the same program in 2010 that you do in '09 and if we should think about it and I know it's premature. But should we think about it as a low single-digit growth company, should we think about volumes declining with the same capital program or any sort of context on that would be helpful.

Well certainly Mike, I mean I would say, just trying to think about a couple of projections that we've put up, what I would say at the same capital spin probably worst cases flat, probably best cases mid single-digits, just to kind of close numbers out of, how they are little bit. That's obviously something we're going to work on.

But we are... we're really focused on running our business 2009 at much lower commodity price get cost out of business.

We think the whole space is going to be recalibrated. We think the value of growth is going to be recalibrated with these prices.

But it's very hard to forecast running your business at $65 and in fact we're probably still running at $90 plus cost structure. So, we think the prudent thing to do was reduce our capital in '09 to what happens and then plan '010...

2010.

So just as one kind of final follow-up. So, the '09 program is kind of sided to $400 million in cash flow and $200 million in CapEx and so looking at that program going forward and you've got growth in the bag, we should think about it as roughly $200 million free cash flow and free cash per year generating company for the foreseeable future until we get a little bit better color.

Is that reasonable?

So, what I mean what price... I mean what price are we talking about.

And $200 million of free cash, are you talking cash flow or are you talking cash flow above our capital?

Extra capital just thinking about your comments earlier about generating $400 million in cash flow and then.

And that... and Mike that was 2008.

That's in terms of the $400 million of discretionary cash flow.

Well, I would like to thank everybody to attending the call today. Mike you pretty get a clear answer to your last question we'll follow-up with you one-on-one.

Nice really we got the whole story to you there. Obviously it's a changing time.

We feel like we're managing our business in a prudent way. We'll see what happens to activity in the space which will reduce cost and we'll see if we get commodity response through that reduced activity.

Good day everybody. And look forward to talking to you in the next quarter.

Thank you.