Welcome to the fourth quarter 2008 Berry Petroleum Company earnings conference call. (Operator Instructions) I would now like to turn the call over to your host for today’s call, Mr. Bob Heinemann, President and CEO. Please proceed, sir. Robert F. Heinemann: I’d like to remind everyone we are conducting this call under Safe Harbor provisions. Joining me today are Michael Duginski our Chief Operating Officer, and David Wolf our Chief Financial Officer. Today, Berry Petroleum has posted its 2008 results. The company earned $134 million of net income or $2.94 a share. This result is 3% higher than last year’s number of $130 million or $2.89 a share. The full year results for 2008 include a $12 million loss in the fourth quarter due to a $38.5 million write-off of receivables from the bankruptcy of Bay West of California, a subsidiary of Flying J Incorporated. We also wrote off certain rig related charges and dry hole expense in the fourth quarter. For the full year 2008, these write-offs reduced our net income by approximately $25 million or $0.56 a share. The Flying J bankruptcy accounted for about 85% of this loss. Overall, 2008 was another year of growth for Berry. Our operating cash flow increased by 71% to $410 million supported by the commodity prices of last year and due to the company’s production growth. Production averaged right at 32,000 barrels a day supported by increases from the developments in our diatomite, Poso Creek and Piceance assets, as well as the east Texas acquisition. Obviously, our proved reserves of the third leg of the growth story from last year. Proved reserves increased 45% to 246 million barrels and we replaced 756% of the 11.7 million barrels equivalent produced last year. The oil and F&D cost, including the East Texas acquisition, was $12.30 a barrel. Our proved reserves now stand at 51% oil and 49% natural gas, 55% of the proved reserves are classified as proved developed. The reserve to production ratio increased to 19 years. Before asking Michael and David to provide you with additional operational and financial details, I’d like to make a few comments about the forward outlook in Berry. In the second half of last year we experienced a sharp drop in commodity prices, the anticipation of a significant California severance tax on production, as well as the retraction of credit markets as part of the global financial crisis. While a number of these are beyond our control, we’ve been very focused on addressing those issues that we can proactively influence to put the company on a firm financial footing. I’d like to point out six things that we’ve done. We reduced our activity sharply late last year in expectation of the commodity downturn. We also focused very early on cost reductions because of the impact on year end reserves. We’re now targeting a 20% to 25% reduction in operating capital and G&A costs compared to 2008. Secondly, we marketed our crude successfully in January and February and now into March under short-term agreements with a variety of refiners in California. These agreements are based on the differential between the posted price for San Joaquin, heavy oil and West Texas Intermediate. That differential has decreased to less than $8.00 today. Thirdly, we hedged 90% of our crude production for 2009 such as if WTI averages $40 a barrel, the company will realize $65.50 a barrel. These hedging levels and realizations make the recent decline in the heavy oil differential even more important to our cash flow projections. Fourth, we amended our credit facility to ensure that we would not violate the covenants under that facility. While this was described in an 8-K filing last week, I want to emphasize that this amendment was entirely due to the Flying J bankruptcy. It would have not been needed if that event had not transpired. Fifth, we locked in LIBOR rates through 2012 in the 2% range using interest rate hedges and swaps. And then lastly, we’ve developed a 2009 capital program that invests in our higher return projects, balances expenditures to be within cash flow, and produces over 32,000 barrels a day. Now, while we’re pleased with the progress on cost reductions, true to our marketing hedging amendments in 2009 that we’ve made in a relatively short period of time we are pursuing additional steps that we believe will improve the company. With that, let me know turn the call over to David Wolf who will provide more detail on our financial results. David D. Wolf: First I’ll go over the full year 2008 results, a four quarter review and then walk through some of our 2009 guidance. The full year 2008 oil and gas revenues were $698 million, oil revenues comprised $519 million, and gas revenues $179 million. Total revenues, including electricity sales, gas marketing and other items were just over $800 million. As Bob highlighted, our net income was $134 million or $2.94 per diluted share. Our oil prices per barrel after hedging for 2008 was approximately $70, our gas price after hedging was $7. This gave us an average BOE price after hedging of $59.81. Total operating cost for 2008 averaged $38.44 per BOE. Our oil and gas operating costs were $17.10 per BOE. The variance over our 2007 numbers reflect increased volumes of injected steam, the higher cost of natural gas, higher contract in service costs, as well as higher compression gathering and dehydration costs. Production taxes were $2.56 per BOE in 2008 compared to $1.75 in 2007, and this was due to our increased value of our oil and gas production. Our DD&A cost in 2008 was $11.81 per BOE compared to $9.54 per BOE in 2007. G&A for 2008 was $4.73 per BOE. The higher G&A in 2008 versus 2007 reflects a few items. One is a higher headcount. Two, the cost of relocating our office and employees to Denver midyear, and we also include about $2.3 million of rig termination fees in G&A. Our effective tax rate for 2008 remained on par with 2007 at 37%. We would expect 2009 to be roughly in the same range. Under our standardized measure calculation, our after tax PV-10, as of December 31, 2008, was $1.14 million. The price used in the year end 2008 measure was $30.92 per BOE, which did include a California differential of $14.05. If you were to adjust the California differential to something closer to $8 that standardized measure calculation would be roughly $1.4 billion. Our substantial hedge position, which is obviously excluded from these calculations, was valued at $315 million at the end of the year. Based on strip pricing in mid-February and a current California differential in the $8 range, our PV calculation after tax would approximately be $1.8 billion, our hedge value at strip would add another $200 million of value to that number. Fourth quarter, our operating cash flow was $78 million versus $92 million in capital expenditures for the quarter. Oil and gas revenues totaled $140 million in the fourth quarter. We did report a loss of $12 million or $0.27 per diluted share. And this loss, as Bob mentioned, resulted primarily from the Flying J bankruptcy pre-tax write-off of $38 million. Additionally, we took charges for rig termination fees, rig impairments and dry hole expense totaling $7.2 million. At year end, our debt was $1.16 billion comprising of $200 million of senior sub notes and $957 million drawn under a senior secured credit facility. We have commitments of $1.21 billion today. Our liquidity at the end of the year was $245 million, and our EBITDAX to total funded debt ratio under our bank deal was 2.7 times. We did release last week that the company executed an amendment to our senior secured credit facility, which among other things, increased our maximum EBITDAX to total funded debt ratio 4.75 times through the year end ’09, 4.5 through year end 2010 and four times thereafter. It’s important to note that this amendment was launched prior to the positive out come for Berry related to the California severance tax, as well as a significantly wider California differential than we are experiencing today. The amendment provides the company flexibility to raise capital under the terms of our bank deal, including but not limited to second lien financings, unsecured debt and other junior capital. I’ll spend a second on the 2009 guidance range that we also have in our 10-K. Our operating cost for oil and gas production in 2009 is expected to be in the $13.50 to $15.00 per BOE range. Production taxes in the $1.50 to $2.00 range, DD&A $14 to $16 range, G&A $3.75 to $4.00 per BOE range, interest expense $3 to $4 range. Let me spend a minute on our cash flow guidance for 2009. Based on $47.50 per barrel WTI price and a Henry Hub price of $5 and using an $8 differential in California, which is more conservative than the current differential. You would increase both the operating and discretionary cash flow ranges that have been provided in our prior press release by approximately $15 million. So, again, at an $8 differential in California, we estimate our operating cash flow to range between $190 million to $215 million in 2009. We estimate our discretionary cash flow to range between $260 million and $290 million in 2009. As mentioned in our press release and 10-K, our 2009 cash flow is fairly insensitive to changes in commodity prices. With that, I’ll turn it over to Michael Duginski to walk through an operational review.

As Bob mentioned, year end proved reserves increased significantly to 246 million barrels from 169 million barrels equivalent at the end of 2007, a 45% increase. The 88 million barrels of reserve replaced 756% of the company’s production last year and 43% were replaced organically from our development capital or 392% organic replacement rate. Diatomite proved reserves increased by 160% to over 30 million barrels as a result of drilling 85 development wells and additional production history demonstrating the ultimate recovery. Our Piceance basin proved reserves increased 80% to 42 million barrels from drilling 72 gross wells, and also the active development of the offset operators around our property. We’re able to hold our South Midway-Sunset proved reserves flat after production offsetting a low base decline with improved recovery from deeper zones and the planks of the field. The East Texas acquisition added 50 million barrels of equivalent reserves to our year end total. All of our reserves were stress tested at a WTI price of $44.60 per barrel and a Henry Hub price of $5.63 per MMBtu utilizing appropriate differentials, including a California heavy oil differential of 1405. Additionally, we had no asset impairments. These reserve additions were driven by $398 million development capital and $668 million of acquisition costs. With the addition of capitalized interests, this resulted in [inaudible] $12.30 per BOE. As mentioned, the company made a significant acquisition of two properties in Limestone and Harrison County of East Texas for $668 million closing on the 15th of July in 2008, developing a new core area for Berry. Gases included 100 producing natural gas wells, 4500 acres, in which we have identified over 100 drilling locations targeting multi-zones, DAC pay opportunities in Pettit, Travis Peak, Cotton Valley Sands, Cotton Valley Lime, Bossier Sands, as well as the Bossier and Haynesville Shales. We believe this is an excellent entry point into a price favor basin with strong cash margins and excellent potential to grow production with upside and exposure to a prolific shale plate. We completed four vertical Haynesville tests in 2008 averaging 1.2 million a day IP and demonstrating the productivity of the shale on our properties. Three offset operators to our Darco property have reported horizontal Haynesville shale IPs averaging eight million a day and we expect to drill our first horizontal Haynesville well by midyear. We are also actively evaluating a Bossier Shale horizontal well at our Freestone property. As mentioned for the year, production increased 19% to 31,970 BOE a day consisting of 64% oil and 36% natural gas. In California, diatomite production increased 86% to 1,840 barrels a day and [inaudible] production was 3,100 barrels a day, a 58% increase year-on-year. In our Rocky Mountain operation, production increased 22% to 13,000 barrels of equivalent production per day driven by 105% increase in our Piceance production growth to over 3,500 BOE per day. Our East Texas acquisition added 2,400 BOE per day to the annual production because the acquisition date was in mid-July. In California, we endured a challenging end of year with the Flying J bankruptcy and a proposed California severance tax. I am pleased to say that we have placed all of our California production with various place favored short-term contracts, and since year end, the California differential has shrunk from $14.05 per barrel to $7.58 per barrel today, a similar price to what our Flying J contracts were. In 1993, when WTI ranges between $30 and $40 per barrel, the average differential is $6.40 per barrel and we expect it to return there. With regards to the proposed California severance tax, the California budget runs through June 2010 has passed without a provision or oil severance tax. Looking forward to 2009, we currently have $100 million capital budget planned that is focused on the continued development of our diatomite assets and a one rig drilling program in East Texas. We expect California production to grow with the diatomite production growth, offsetting other heavy oil natural decline. East Texas will remain flat with a one rig drilling program, and without capital investment, we expect production declines in our Rockies natural gas asset. We are focused on capital and operating cost reduction of 20%, and to date we have made significant progress in each of those areas. We have re-bid all of our development services and materials resulting in capital reductions of 17%. As a result of lower activity, lower fuel and electricity prices and lower commodity prices, we’re projecting operating costs to decrease by 20%. As a result of the low differentials, cost reduction and hedging, we are realizing operating margins of $25 per barrel as we did in 2004, 2005 when crude prices were $40 to $50 per barrel. Robert F. Heinemann: That concludes are opening remarks, we will certainly be happy to entertain any questions that you have.

(Operator instructions). Your first question comes from David Tameron – Wachovia Securities.

A couple questions, can you talk about the mixed shelf that hit the tape this afternoon? David D. Wolf: We are no longer a [WIC E] filer, David, so we took steps in order to ensure that when and if the bond market opens to Berry, that we could term out some of our bank facility. It was a filing that you had to make if you weren’t a [WIC E] filer at the end of the year.

Okay. So we’re not supposed to read anything as far as timing? David D. Wolf: No. You know where our bonds trade and as we continue to improve our balance sheet through 2009, the expectation would be that, when the bond market becomes available to Berry, we would look to access it.

While I got you, David, what’s your current debt level and current liquidity position as of I guess today? David D. Wolf: We’re probably in the $200 to $225 million range. I don’t have today’s exact numbers.

But down 15 or 20 from year end. David D. Wolf: Yes. And that’s because we bring in a fair amount of carry in from the commitments in 2008, so you see a modest increase in the first quarter and then the free cash flow starts to kick in.

I got a slew of questions here, let me pick and choose. Bob, you started to mention contract pricing in California and I guess you’re in negotiations, or where exactly is that at and when should we expect to hear something? Robert F. Heinemann: Well, we’re currently marketing our crude on a short-term basis. We have not terminated our contract with Flying J. Depending on how the market moves, then we’ll have to make a decision about pursuing a longer term contract. Obviously, the slope of the curve is quite sharp at the moment and we want to see where that vector is going to lead us to before we get out to a longer term contract.

So right now it’s all being sold under that short-term deal and, if I understand right, then at some point you’ll choose to lock it in? Robert F. Heinemann: That’s the idea. So we’ve marketed March, probably the next thing we’ll start to look and see what kind of commitments we can get on a longer term basis.

And as far as insurance related to the Big West, I was trying to get through the K. It said something in there about there may be insurance on the back end due to contract? Robert F. Heinemann: Well, our administrative claim is $12 million our pre-petition claim is $26 million, that’s $38 million of the receivables that we wrote-off. We are also accumulating performance damages under the existing refining contract that we have. And we have a parent guarantee that goes to Big West, which is the owner of the Bakersfield Refinery and Salt Lake City Refinery, and it shows to be generating significant cash flow this year. And then that parent guarantee also rolls up to Flying J Incorporated. So obviously, we’re not bankruptcy experts, we’re not running the company on the expectation of a bankruptcy result but we have a pretty good view of where our position is.

One more ops question and I will let somebody else jump on. If I think about the Piceance, I know you have a drilling commitment there that’s 2011, it doesn’t sound like you’re going to do a whole lot there this year, which I don’t blame you for. But how do you manage to get that drilling done by early 2011? What do you think about that? Robert F. Heinemann: Well, the first thing I want to point out on the Piceance is that the fundamentals and the basin are changing. And they’re changing quite rapidly. Rigs that topped out in the $26,000 to $28,000 a day are now down into the $15,000 to $17,000 a day. We are also looking very hard at the subsurface performance. We think we have a chance to improve our EURs in the basin, so with our transportation that we have on pace and the possibility of getting more transportation on Ruby. Now the fundamentals on the basin are changing very rapidly within about 120 days. Now, obviously I’m not committing that we’re going to go spend a bunch of capital there this year. But the fundamentals could change, our outlook could change, our activity could change. And we also have a plan that will enable us to earn our acreage based on access that we have based on activity of other offset operators. So, we don’t see a big piece of our acreage or our holding in the Piceance in jeopardy based on pace.

Your next question comes from Brian Singer – Goldman Sachs.

Two questions, first, can you provide just a little more color on the Haynesville in terms of optionally, if there is any, to the extent that the first well is successful and where CapEx would come out of to the extent that you wanted to get more aggressive there? Robert F. Heinemann: I think the simplest way to answer your question is we have one rig drilling program in East Texas. We’re trying to move our horizontal activity up as quickly as possible. So with the first well that we drill and upon success, we would directly follow-up with an additional well, and keep that program going since we’re expecting to drill with one rig all year. So we’re hoping for success early on. We’re trying to accelerate the well so that we can do a follow-up well. That’s a lot of the reasons why we say we’re going to drill either one or two wells this year, and hopefully on success, we would continue to drill.

And then maybe it’s too early to ask this, but how do you look at 2010, just kind of given the combination of a lower ’09 program but the potential to pay down some debt? Are you looking at acceleration in 2010 and does that mean that it really is kind of the second half of 2010 before one would see that? How are you thinking about things right now? Robert F. Heinemann: Well I think all those answers require some type of forecast on the commodity. If we see the commodity firming, not necessarily with a big absolute increase in the second half of this year, but if we see the commodity firming, for example, if we see crude oil demand start to tune up a little bit, then we could put some more dollars back to work in the back half of this year. So for us to say we’re going to grow 10% or get back into a full growth mode, I think we’ve got to see some support on the commodity.

If I could ask just one last quick one. Looks like Rockies realizations have come down a bit, obviously Henry Hub has too. But is there some price where you would expect either yourselves or your partners to shut existing wells in the Rockies?

Well, based on what our operating costs are, at about $1.00 for in NCF and relatively low transportation charges, I really don’t see us shutting any existing wells. Where we are right now is we have a certain inventory of re-completions that actually, even at these prices today, have relatively high rates of return that we’re hoping to expand or execute this year, say in the mid part of the year. So we don’t see any need to shut any existing production. We’re hoping to do re-completions. And if we see a price response, as Bob said, with our improved economics there, you could see us drill potentially at the end of the year in the Piceance.

Your next question comes from Michael Jacobs – Tudor, Pickering and Holt.

Quick question for David, now that the Midway-Sunset differentials coming in quite a bit. How do you think about locking in those differentials vis-à-vis longer term contracts? David D. Wolf: Mike, we’re in the process, just as we already answered, we have short-term contracts and the reason for the short-term contracts was to see that differential come down. We’re studying the life of the San Joaquin Valley posting. And, like I said in my comments, if crude oil prices are going to be in the $30 to $40 range, we expect the differential to come down into the mid six’s. When we see those type of differentials, you’ll see us do longer term contracts.

And you touched earlier on improving EURs in the Piceance. Is there anything that you’re doing differently on the completion side to drive those results? Maybe if you could elaborate just a little bit that’d be great. David D. Wolf: Well, I think if you’d look at a number of seasoned Piceance operators they have been able to improve their EURs per well quite substantially over time. And it really relies on these high water fracs, which use lower prop and concentration and high water concentration, perhaps facilitated with gels, etc., etc. Some of those EURs have increased as much as 50% and it has taken people two or three years to bring that to bear. If we could get a 20% increase, our EUR would go to about 1.8 bcf per well. And we think we have a really good chance at drilling wells below $1.7 million per well. And we think that cost could make the opportunity pretty interesting, particularly with low transportation. If we decide to go ahead and do some completions in the Piceance later this year, that would be one of the things that would be testing.

You touched on post-tax PV-10 and went through the K quickly. I didn’t see a pre-tax number. Could you give us the pre-tax PV-10 and perhaps segregate it by PUD versus PD? David D. Wolf: I don’t have the PUD versus PD but the income tax was roughly $630 odd million. So you’d obviously add that back on to the 1.14. We’ll follow-up separately with your breakout question.

And one final question before I jump off. We’ve seen some of your assets in the public domain. Bob, can you talk about how you address the balance sheet with respect to other items that could be considered non-core? Robert F. Heinemann: Well, we’ve said all along that we would consider selling assets. It’s obviously not easy to transact in this environment, but we’ve done it in the not too distant past and we would do that again in the future. Not to name any assets, but obviously we’d be looking at non-reserve midstream assets and we’d be looking at assets that really don’t fit the portfolio longer term. That’s where we are on it, so if we sold an asset we would use proceeds to pay down debt.

Your next question comes from Phil McPherson – Global Hunter Securities.

David, just a little bit confused on one number. You’re talking about your discretionary cash flow and then total cash flow and it was a little bit different than what you said in December. In December you said cash flow 220 to 240 and then you had this 190 to 200. Can you just kind of run through those numbers again? David D. Wolf: Sure. We’ve kind of, 220 to 240 is discretionary cash flow. The comparable number that we talked about today is 260 to 290. And a couple things have moved that number up by roughly the $40, $50 million. First of all, the California differential hasn’t improved. The second and probably more meaningful is we have taken a series of steps in December to collapse roughly 10,000 barrels a day that was collared 47 by 70. And we collapsed those collars and swapped those barrels at roughly $54 or $55. So getting a $10 uplift from our, call it our base case or our management case, is really what contributed to most of the incremental discretionary cash flow because we did not change our WTI or Henry Hub assumption. The other number is an operating cash flow number, that's in our press release.

And when you talk in the press release about oil averaging $40, you guys would average $65, then we need to subtract out that differential in California, right? David D. Wolf: Correct.

And what's the differential like in Utah right now? David D. Wolf: The differential under our contract is approximately 25%, so at a $40 price we're realizing $30. So that's $10 to us, which is actually quite favorable to the market. Robert F. Heinemann: We've all talked in the past about how thin the posting is, but that number is significantly better than the posting that you could go look up.

And, while we're in Utah, is there any, not that you're looking to drill there, but the Ashley Forest and the environmental stuff, has there been any talk about that, and with the new energy secretary, ending up being affected?

We haven't heard anything regarding any delays in our EIS, and our understanding is it's moving along. We expect it by midyear, and we have not heard anything about any delays, any staffing issues or anything else that would impact us getting that approval.

Last question, you didn't put this guidance in today's press release, but are you still sticking to that 33,500 barrels average for '09? Is that you're kind of going with?

No. I think what we really tried to say in the press release, we're probably down 1,000 barrels off of that. And the reason for that, really, is a lower starting point. And the reason for the lower starting point is the impact of the Flying J bankruptcy. Some of these heavy oil fields, after you shut them in for a time, take some time to recover, particularly those fields that have significant water in them. And those are the fields that we see coming back at the slowest pace. Then, obviously, you go and do a well-by-well analysis, and then you end up asking yourself your lowest rate wells with the highest water cut, is it economic to bring them back. And that is the biggest change in the forecast.

So then you would expect first quarter California production to be down maybe 10% or more from fourth quarter, and then rebound in the second quarter back to those fourth quarter levels, roughly?

Off the top of our head, our heads are going up and down. We'd have to do a little analysis probably to get you a better number, but directionally that feels about right.

Your next question comes from [Rocky Rasley] – Vaquero Energy. [Rocky Rasley]: I'd heard that in the discussions here that you have favorable transportation costs. Can you give me an idea what those are, in your Piceance Basin? Robert F. Heinemann: We have a capacity on the REX Pipeline and those are at max rate, publicly posted transportation costs. [Rocky Rasley]: Can you tell me what your gas price differential is for the Piceance? Robert F. Heinemann: Well, like I said, we're on a fixed differential via our transportation, so we transport our gas into the mid-continent. So we're really not realizing CIG pricing. So I just don't know it off of the top of my head today, because we don't get paid in CIG. [Rocky Rasley]: So are you bundling your gas, then, when you sell it into the REX transportation? Do you sell it at the delivery point? Robert F. Heinemann: Yes we do. [Rocky Rasley]: And the 2011 well commitment, is that a lease commitment, or what exactly is that? Robert F. Heinemann: Yes. It's a lease commitment. [Rocky Rasley]: As I understand it, then, depending on how your price in commodity goes and well costs, there could be a well in 2009, 2010 if the economics allow? Robert F. Heinemann: Definitely. Like we said, we have a schedule to meet all those commitments right now, even if we don't drill in '09.

Your next question comes from Gregg Boddy – JP Morgan.

I just want to jump back to the asset sales. Are any of these assets on the market yet, or is it informal? David D. Wolf: Gregg, it’s David, the answer is yes. We're in various stages of several data runs.

When you think about your liquidity and potentially increasing your spending, what would be some things you'd be looking for to be able to do that outside of the firming of the commodity price, in terms of if you have asset sale. David D. Wolf: Well, a couple things. One, the California differential, every dollar that narrows is about $6 million of pre-tax cash flow. So if we go from eight to seven, there's incremental debt reduction. From the standpoint of realizing greater capital and operating cost reductions, if we were able to reduce our operating capital costs by 5%, that would enable us to pay down another $15, $20 million of debt. So there are a few levers in addition to the non-core reserve asset sales that we're looking to effect.

And then at what point do you feel comfortable picking up your spending? David D. Wolf: Well, I think, again, you probably have to have a view on the commodity, but as we start to increase our liquidity above the $250 million range and you're not looking out six months to what your bank debt would be in terms of re-determinations, I think you then make an assessment of incremental spending. So, if we term out a fair amount of our bank funding and increase our liquidity that would also be an inflection point to increase spending if the price environment warranted it.

Yes. And I think the other thing you look for is you look for assets which are cash flow positive almost from the get-go within your asset team, and we have some of those opportunities.

One last question for you, your PUD percentage went up. Is that driven by the East Texas assets that you acquired? David D. Wolf: It's probably three factors. East Texas is one of them. Offset operator activity in the Piceance is another factor to increase PUDs, as well as our own one location off-drilling. And then because of the performance of the diatomite asset as a whole and the strong analogy that we have with the Cymric Project, Chevron's operating project, we see an increase in PUDs there, as well.

Your next question comes from Duane Grubert – CRT Capital.

On the diatomite project at your analyst day, you have talked about some specific LOEs to that program, thinking of them differently from Midway-Sunset. Can you walk me through what those have become with the lower steaming costs, and also if there's much of a difference early life versus late life LOE-wise in a diatomite development?

I don't have the analyst day presentation in front of me, but what I would tell you is we did see significant reductions in our non-fuel operating costs in the diatomite project of approximately 20%. And what I would tell you is that our capital costs, we're seeing about a 10% decrease in our vertical wells in the diatomite. So capital is down about 10%, non-fuel operating cost is down 20%. Then you'd have to go back to those economics and apply, say an $8 differential as opposed to the $12 differential that we may have showed. So those would really be the improvement. And when we cast the diatomite's economics, the economics are still strong all the way down to the $30 a barrel and we talked about that at the analyst day also, and that would improve with incorporating these cost reductions. And I think also you’ll see high SOR early in the development life of the project. You’ll plateau your production your SOR will come down quite nicely and then it stands to reason late in the life you’ll see your SOR go back up. Now one of the things that we’re starting to hear people, at least I would say probably discuss if not implement, is late in the life of the better diatomite projects you’re hearing people talk about going to even tighter well spacing with continuous steam injection. And certainly I think there’s a good chance that we would do that that’s far, far down the road for us, but it would be the type of thing you would think about when you’re trying to book to 3P.

On some of your oldest properties, now that you’re getting sort of a de facto price stress test, do you have parts of a field that you’re letting go in terms of reducing the steaming and just putting them sort of on their final decline?

Yes. We are and one of the things I would say is that crude oil prices were $50 or $60 a barrel at year end you would have saw our reserves probably closer to 260 million barrels. Primarily the reductions are from higher cost late in life steam flood such as our Placerita operations we saw a certain amount of reserves be written off because they hit the economic limit much sooner at this stressed price that we described. We had some minor adjustments of one and two million barrels in other fields but nothing that material. It really demonstrates the quality of our heavy oil assets in California, particularly our Midway-Sunset both our north and south assets and what a high margin property these are and how economic they are as opposed to some other California operations that are truly late in life or high water cut or high operating cost. Obviously, we didn’t see any impairment and we saw very little reserves come off when you consider the total number of our reserves are in California. Robert F. Heinemann: Now as Michael mentioned earlier, we were really happy to see that we were able to replace our reserves at South Midway, so when we think about that economic cutoff we still have a long way to go in our biggest legacy property.

Your next question is a follow-up from the line of Philip McPherson – Global Hunter Securities.

I was just wondering in the Piceance if you had an inventory of uncompleted wells that you had drilled and not frac'd?

We talked about that in the fourth quarter that because we were cutting our capital so dramatically, that we wanted to go ahead and not complete those wells until we saw a price response in the Rockies. So we have 37 wells that either need to be completed or re-completed that are in our current inventory. We typically don’t like to have a significant amount of re-completion activity in the winter because of the winter conditions on top of the maces and so we are evaluating right now as we come into the spring whether we’re going to try to fund those re-completions sooner than later on in the year.

But if you get a commodity price rebound in the back half of the year that’s a pretty low hanging fruit you can come in there and re-complete them or frac them and get then on for year end, right?

These might be our highest rate of return projects.

Your next question is a follow-up from David Tameron – Wachovia Capital Markets.

I think you answered this, Michael, but you said the reserve write-downs of pricing, I assume I look at the reserve report most of the revisions are due to pricing. Can you talk about what areas that hit the hardest?

Like I said, the majority of those reductions were in the Placerita field so if you took the difference between 160 and 146 what we reported I’d say over half of those come from Placerita. And then there are little ones and twos, one and two million barrel reductions in some of our more mature areas of the North Midway-Sunset field, which are not diatomite. [Inaudible] possibly and majority of it will be in North Midway. Placerita is probably two-thirds of it.

And then on the gas side it’s primarily Piceance? Robert F. Heinemann: We really didn’t have significant revisions in the Piceance.

I’d have to go back and look at it, but it looked like there was a 40 or 50 bcf reduction on the gas side? I was just wondering if it's not Piceance what is that? Robert F. Heinemann: The main revision in gas was East Texas and what we had is when we did our evaluation, particularly one of the shale was productive zones of the Travis Peak we had no completions in Travis Peak. The buyers reserve analyst gave them full credit for those reserves. But we don’t have a producing completion in the Travis Peak and D&M wasn’t comfortable giving us all that is proved reserves so that was the major revision, no a year-on-year issue, but more of an announcement. We think we can come back and get that.

You guys are going through some issues I think with the California Public Utility Commission, would that block the sale of any type of generation assets? Robert F. Heinemann: I don’t believe so. David, I think that would be an extreme case. We have standard offer contracts right now for all of our assets and, although we may renegotiate those as they expire, we still expect to be selling power to the utilities in California.

A couple more, believe it or not. David, you went through some PV-10 calculations and sensitivities. Can you throw those out again? I think you said you go from 11 to 13 based on this oil price. David D. Wolf: So our standardized measure, which puts up with the K at hear end was $1.14 billion and that’s on a per BOE price of $30.92. And that realization includes a deduct of $14.05 associated with the California differential. So given that we’re at $7.57 today on the differential, we went back and tried to normalize that measure assuming an $8 differential and that adds incrementally up to $1.4 billion, so 200 and change. Then what we said was we’re obviously not in a $44 flat world what is our PV after tax if we use the strip, and that adds about another $400 million of value to $1.8 billion at strip at year end. And then since none of these include any of our significant hedges, if you were looking at it at strip our hedges would be worth $200 million. And if you were looking at $44 flat, i.e. the SEC price deck it would add $315 million of value. So basically a normalized measure in terms of PV after tax including hedging is closer to $1.7 billion, and obviously that’s an important number to our lenders.

If I think about that do you care to venture, I mean, you’re at one two, your reserves are up, your hedged out near-term to take away some of that price depression so longer term I can’t think it’s going to be that much different than it was last borrowing base. Do you care to take a guess at what your new borrowing limit level? David D. Wolf: I would say there’s been several positive developments. Obviously, the differential, the fact that we’ve collapsed these collars and nine and ten in swap, the year end reserves were at the top end of our guidance, to counter that our lenders decks are lower, primarily in the first two years. We’re pretty insensitive the first two years because we’re hedged 90% and roughly mid 70% in 2010. If I had to guess right now, I’d say we’re certainly north of $1 billion and we’ve got a real supportive group of lenders. This amendment that passed was 100% consenting vote from our 19 lenders and I’d also say that we’ve raised capital in pretty tough markets in the past so we raised $130 million of capital bank debt in November, December. So our comfort level is at a minimum at $150 to $250 million of liquidity and you get comfortable with that because of the fact that we can free cash flow even at sensitivity prices. So until we know the number I’d hate to put a finer brush than we’ll be north of $1 billion.

What’s the exact timing on that? David D. Wolf: Your question was timing?

Yes. When do we get that revolver? David D. Wolf: It’s a spring re-determination, so April timeframe. Robert F. Heinemann: Just one other point on David’s comment, it sounds like we’ve talked a lot about heavy oil differential today. It’s obviously an important part of our business and we keep quite an exhausted database, but what we would tell you is over the last many years when WTI is less than $40, the heavy oil differential is less than $8 98% of the time that averages $6.40 over that period of time. So it is not unexpected for us to see that differential come down into the mid six’s in this type of pricing. And that even makes the case that David was quoting for the borrowing base even stronger.

Your next question is a follow-up from [Rocky Rasley] from Vaquero Energy. [Rocky Rasley] from Vaquero Energy: Getting back to the well commitment coming up in 2011, if you don’t drill in 2009, 2010, does that trigger lease rental that you need to pay? And if so, do you have an idea what that would be? David D. Wolf: No. It doesn’t. It’s a drilling of commitment that we had with the buyer that we would drill a certain number of wells by 2011. Now, what I would tell you is there’s potential also for us to renegotiate that given the price environment that we’re in. Robert F. Heinemann: The buyer also had some conditions he had to meet as well.

At this time, there are no further questions in queue. I would now like to turn the call back over to Mr. Heinemann for closing remarks. Robert F. Heinemann: I would like to thank everyone for taking the time to hear about Berry. In addition, reviewing last year results we’ve attempted to describe how we’re currently managing our business. We described life after the Flying J bankruptcy, how we’re recalibrating our cost structure in this environment, as well as taking a number of steps to provide the company with increased financial flexibility. We look forward to communicating with you all in the near future. Thank you.

Thank you for your participation in today’s conference. This concludes the presentation.