Thank you and good day. Let me remind you that we are having our fourth quarter earnings call and we're conducting it under the Safe Harbor provision.

Today, Berry Petroleum has posted its fourth quarter results of last year completing another solid year of performance in 2007. Fourth quarter net income was $32.2 million or $0.71 a share compared to $19.1 million in the fourth quarter of 2006.

Full year '07 net income was $130 million, $2.89 a share, up 20% compared to last year's earnings of $108 million. These results include an after-tax contribution of $25 million from the gain on asset sales, less dry hole impairment and exploration charges in 2007.

Net production for the fourth quarter of last year averaged 28,020 barrels, up 4% compared to the production of last quarter in 2006. For the year, production increased 6% to 26,900 barrels a day.

Production split for 2007 was 73% oil and 27% gas compared to the split of 77% oil and 23% gas in 2006. The company generated a record discretionary cash flow of $260 million in 2007, up 6% over the 2006 result.

Average realized price for the full year in '07 was $47.50, up 2% over the 2006 average price. Oil and gas revenues increased 9% to $467 million.

In the fourth quarter the realized price was $52.32 a barrel, revenues were $133 million, and discretionary cash flow was $77 million. Year-end proved reserves increased significantly last year from 150 million barrels to 169 barrels of oil equivalent.

The 35.4 million barrels of reserve additions replaced 293% of the company's production for the year. Berry's reserve mix is now 117 million barrels of crude oil and associated liquids and 316 billion cubic feet of natural gas.

61% of our reserves are proved developed, 39% are proved developed, up 5% over year-end 2006. Our RP ratio based on the fourth-quarter production now stands at 16.5 years.

The 70/30 split of oil and gas reserves by percentage approximates our projected 2008 production profile. These results were driven last year by Berry's capital investment of $285 million in its development exploration drilling programs and another $56 million on acquisitions.

Our finding and development cost for the year were $10.07 a barrel. The trailing three-year average now stands at $12.23.

Berry is a growing company focused on execution. We saw improved performance from several key assets last year, including production growth at 215% in our Diatomite heavy oil project to 1,000 barrels a day from the application of more aggressive steam cycling and fracing, current production is about 1,500 barrels a day and the steam oil ratio is about 5 to 1, and we have a number of wells drilled and waiting for steam injection.

Expansion of our Poso Creek steam flood also contributed, last year production doubled to 1,950 barrels a day and currently is at 2,700 barrels a day. We anticipate firing of our fifth steam generator in the next few days at Poso Creek.

We should see production average about 30 to 70 barrels a day for 2008. We were also benefited from the improved drilling performance in our Piceance assets with a number of days required to drill, may so [ph] will decline to the 16 to 19 day range and led to a production increase there of 140%.

We're expecting to double our production in the Piceance in 2008 to 21.6 million cubic feet a day. We were also successful in stemming the production decline from our South Midway assets towards the end of the year, from the drilling of new horizontal wells located just above the oil water contact and continuous steam injection along the flanks of the reservoirs.

In 2008 we have planned a $295 million capital program, our strategy is for continued growth, include developing our drill-ready oil projects in the near term, where we’ll invest about 60% of the capital budget into the Diatomite, South Midway, Poso Creek, and Brundage Canyon, as well as continuing to appraise Lake Canyon. The balance of the capital budget will be invested to develop our gas resources for the longer-term where we will invest about $120 million into our Piceance and DJ assets.

Other strategies would include pursuing acquisitions and exploration opportunities that focus on repeatable pipe developments and adjusting our capital program with cash flows, utilizing hedging, and other long-term contracts. We believe we set up for a very strong year in 2008 where our goals would be increasing production by at least 10% to the 29,500 barrels to 30,500 barrel a day range, increasing our proved reserves into a range of between 180 barrels and 190 barrels proved, developing those reserves for finding and development cost of about $10 barrel to $12 a barrel and generating cash flows that exceed our development on capital.

In fact we believe we can cover our capital and pay our current dividend with oil prices as low as $73 WTI. So with those overview remarks of the quarter and the fourth quarter and for full 2007, I will turn over to Ralph Goehring, our Chief Financial Officer.

Ralph?

Thank you Bob, good morning. Let me start with revenues, our 2007 oil and gas revenues as Bob mentioned increased to $467 million or 9% over 2006.

Our oil revenues were a higher by 7% to $385 million and gas revenues were up 18% to $82 million. Our revenues from electricity increased by 5% in 2007 to $56 million and we had gains from asset sales and other income of $60 million rounding out our total revenues to $583 million.

Our gas sales price was negatively impacted by the widening differential in the Rockies versus Henry Hub pricing in 2007. Those differentials have now narrowed.

Our location and quality differentials averaged $2.93 per MMBtu off of Henry Hub in 2007 and we expect to average between $1.10 and $1.40 per MMBtu off of Henry Hub in 2008. This improvement is primarily due to opening of the Rockies Express Pipeline or REX this year.

Based on our target production of approximately 30,000 BOE per day in 2008 and on a WTI price of $75 a barrel and a Henry Hub price of $7.50 Mcf, we expect total revenues for 2008 to be approximately $650 million and that excludes any asset sales. Our discretionary cash flow for the year was $260 million, an increase of $14 million or 6% over 2006.

Approximately 91% of our 2007 developmental capital expenditures of $285 million were funded by discretionary cash flow. Our debt increased by $53 million during the year and we made acquisitions of $56 million.

In 2008, we are targeting capital expenditures of $295 million and we estimate our discretionary cash flow to range between $310 million to $330 million also based on $75 WTI price and Henry Hub price of $7.50 average for the year. All of the guidance provided today is based on this price deck.

So, we expect our 2008 capital expenditures to be fully funded from our cash flow. We expect our year-end 2007 debt of $459 million to be relatively unchanged by year-end 2008, and that's based on these commodity price expectations, production volumes, and assuming no acquisitions.

Our operating costs for oil and gas per BOE were higher in 2007 by 13% to $14.38 compared to 2006 at $12.69. This variance reflects higher steam related costs primarily through at 8% volume increase of steam injected in 2007 over 2006, higher contract services and labor costs, and higher compression gathering and dehydration cost.

This is in line with our expectations. In 2008, we are targeting average steam injection to increase by almost 25% as we increase our oil production from thermally enhanced projects.

For 2008, we expect our operating cost to average in the range of $16 to $17.50 per BOE for the year. Our production taxes for the year increased 11% on a per BOE basis from 2006 or $1.58 to $1.75 per BOE.

This increase is due to the increased values of our oil and natural gas properties. Going forward, we expect production taxes to generally track oil and gas prices and range between $1.75 and $2.25 per BOE in 2008.

Now looking at our DD&A, our cost per BOE in 2007 increased 31% as expected over 2006 to $9.54 per BOE from $7.30 per BOE. The increase is due to capital spending in fields with higher drilling and leasehold acquisition costs.

We expect this cost to trend a little higher in 2008 and range between $9.75 and $10.75 per BOE. The high side of this range would be an increase of about 13%.

G&A for 2007 was $4.09 per BOE compared to $3.98 per BOE in 2006 with approximately 70% of our G&A relating to compensation. The increase reflects a higher headcount in 2007 versus 2006 to continue our growth and remain competitive in the labor market.

We expect our 2008 G&A cost to average between $4 and $4.50 per BOE. Our effective tax rate in 2007 remained on par with our 2006 rate of 38%.

This rate remains consistent with our projections. You should note that we did defer approximately 80% of our $81 million of the provision for income taxes.

For 2008, we expect our effective tax rate may average closer to 39% and we would expect to defer between 75% and 80% of our income taxes. Financially, we are doing well.

Our balance sheet is strong and we have no liquidity issues. We have plenty of room in our credit facility should we need additional funds.

Some other notable items for the year and quarter, our previously announced plan to form a Master Limited Partnership for certain of our assets is currently on hold due to unfavorable capital market conditions. We will continue to monitor the economic conditions relevant to a successful offering.

Also in the fourth quarter we entered into our second long-term firm transportation contract on REX. This is for a contract volume of 25,000 MMBtu a day beginning this month.

Currently, our total firm capacity on REX is now 35,000 MMBtu per day. This is the sixth consecutive year that we have achieved a greater than 15% return on average shareholders' equity and average capital employed.

In 2007, this was a 29% return on average shareholder equity and a 16% return on average capital employed. Under our standardized measured calculation, our after-tax PV-10 for 2000 and as of December 31, 2007 the measure was 2.420 billion, up 105% from our 1.182 billion standardized measure number as of December 31, 2006.

This is based on a 61% increased per BOE price at year-end 2007 compared to year-end 2006. Our year-end 2007 price per BOE used in this measure was $66.27 and the year-end price of 2006 was $41.23.

These measures are not only a result of higher commodity prices, but we believe also demonstrates our strong asset base and the growth we are and can achieve. We are on track to file our 2007 Form 10-K, within the next six or seven business days.

Bob, that's my report.

Thank you Ralph. We would be pleased to entertain any questions that you have.

Question and Answer

Hi, good morning. Question for you Bob, if I look at your production guidance, and just take out where you guys were in the fourth quarter, started at in Poso and Diatomite and as you said your rest of your clients in Midway, if I add that to the 20 you are at today, obviously that 30,000 a day kind of looks very achievable.

Can you talk about what I could be missing on the downside or are you... are other assets that are declined that you have to overcome those assets or where do you expect the rest of portfolio to go?

We… of course we do have some other assets, legacy assets in California, Placerita et cetera. We are also forecasting that we keep Brundage Canyon relatively flat this year while we are waiting an EIS approval for the Ashley Forest so we are not seeing growth at our Brundage.

The big piece, at least on a percentage basis growth is 100% increase or doubling the Piceance production and that should be fine but you know how it is with pad drilling. Your timing can kind of get in the way, so it takes a lot to drill all eight wells now and get them fraced and hooked up.

We are working diligently to reduce that time. But we are giving you what we think is a good shot at P-50 and then obviously we will work hard to exceed that if we can.

Okay that's fair. The EIS, where do you stand on that nationally for us?

We ... if submitted, we are hoping...

we had originally forecasted probably very early next year what I would say now it's probably end of Q1, may be end of Q2 but certainly first half. We are going to drill something on the order of six to ten wells in the Forest this year where we do have category exemptions.

Alright, one more question, and I'll let somebody else jump on, acquisitions currently looking, not currently looking, if so any more clarity you can give us on regionally?

I would say... I would say looking...

I would say patient, I would say we're looking at California oil in our backyard, probably in areas that reservoir quality you wouldn't consider at a lower commodity price but where we think we can make some money in this commodity price. I would say the normal bolt-ons in the basins where we are and then I would say probably longer term looking at gas and basins that are price advantaged.

Okay. And does the MLP market slowing down, does that help you in California?

We hope so.

Okay.

We hope so. I mean it's...

California is very tightly held as you well know, the ownership in California declines pretty quickly from Chevron down the Berry ending very quickly below Berry so I mean these will be relatively small opportunities but I think if we could accumulate enough of them in a common area, it would be a nice piece for... nice piece of business for us.

And how would you plan on financing?

What I would say is... just roughly speaking I would say $100 million credit facility, $200 million to $300 million additional bonds, $400 million, $500 million plus probably secondary offering or something like that.

Alright, thanks.

Thank you.

Hi, Bob it's actually Eric Hagen. But...

Hi, Eric.

Question on the... just follow up what David was saying on Ashley Forest, how many wells have you drilled there to date and how are results compared to Brundage Canyon and I thought you had some locations you could drill prior to the EIS and if so what's the timing on that, are there any kind of other drilling stipulations out there?

We have about six wells down across the Forest, I think what I would say in the center of the Forest on the North of South trend, we are very, very encouraged. The Southern most well, which is a couple of miles south of the Brundage border, IP there is about 120 barrels a day, very comparable to the central wells at Brundage.

I think the only question in the Forest will be to the East. I think we are pretty optimistic to the West and to the South.

So we plan on drilling one or two wells more towards the East. We do have a number of pads where we can't drill category exemptions wells.

Our plan this year is to drill somewhere between six and ten, not because of the exemptions, but because of the takeaway capacity. We have to put some ability to get gas and oil out of there which at a brand new area is kind of hard to do without the EIS.

So look for us to drill about six to ten and look for those to be more impacting on the appraising the potential of the Forest as opposed to trying to grow production there this year.

Okay. Great.

Thanks. And then one more question on the DJ basin it looks like there were some growth there this year.

It looks like for most of last year the volumes were fairly flat may be that was somewhat related to the MLP. Is there an intention to put more capital up there this year and grow those volumes or just kind of keep them where they are?

As you've heard me say before one of the great things about the DJ assets are we can kind of set our own pace. I think we feel better about gas markets in the near term and probably we could cause us put more capital there.

I think one of the things that we are trying to do is replace our reserves in that asset, in that basin. As we see opportunities to do that we will be investing more capital there.

We don't see big volume growth there but I do think you will see some volume growth there.

Okay, great. Thanks Bob.

Thank you, Eric.

Hi there.

Hi Zach.

Regarding the Diatomite I think you said your steam oil ratio is down to 5 to 1, which is better than your original target of 6 to 1. Can you just give us a sense of what the trajectory is there and what I guess the upside is?

I mean do you have a revised target, you think they can get down to four or three, just a little detail there?

Yeah, we have to be careful the way we say it and of course depending on where you are in any set of cyclic operations, the SOR kind of goes up and down. I would say the way to think about the SOR overall is, we are managing the asset for steam oil ratio today to be between 5 and 6 and that depends on how many wells we are bringing on, how many wells are on cycle, and how many wells are off cycle at any one time.

But for the last, I would say for the month of February or so we are in the bottom part of that range. We are very encouraged by the economics of the Diatomite even at six to one obviously they get all the much better, the lower the SOR is we don't really...

I think it would be pre-mature given the fact that we are may be... we still have 450 wells to drill after this year in the asset to be saying what the eventual SOR is.

But, as we are developing the field and producing the field, I would give you guidance to expect it to be in the 5 to 6 range.

Thank you.

Hi Bob. Whether in the Rockies, Colorado, Utah, have you had any impact, we've heard from other operators in the first quarter thus far, any impact, anything you can give us on that?

Well, I think our, the way we try to discipline ourselves in the company is not to talk about the winter because we are going to have the winter, every winter, it's not like the hurricane season. But pragmatically, I would tell you we've had 5 feet of snow in the Piceance and we have days where we have 30 foot drifts over roads that we have to clear out which only means it takes you that must longer to get people to the top, et cetera, et cetera.

Is it really shutting us down? It's really increasing our drilling days, it's not and I am really pleased with our people's performance through that time but the fact of the matter is it's going to be cold and snowy in Western Colorado every year and we have to develop operating practices that can cope with those conditions and we are on our way to do that.

Okay. And then any comment on Governor Ritter, from a standpoint, you hear a lot of chatter about regulatory, about severance taxes?

We don't like severance taxes. We don't have big ambition to go drill in Aaron.

There could be some, I guess I'd say some ancillary access issues on the Aaron to our Eastern Piceance acreage but we do think we can manage around that. We are constructing another road on the eastern side of the old mountain acreage, which is part of our North Parachute acquisition.

So, we are about the business to try and supply our infrastructure on our own acreage. But we do have the perspective that we want to be good environmental citizens in that part of the country because it's part of our culture and part of what we do at Berry.

So we want to be an excellent operator whatever that takes there.

Alright. And then one final question actually, you already answered it.

I’m good. Thanks, Bob.

Thank you, David.

Thank you for your interest in Berry today and hearing about our earnings. Again we are very optimistic about '08.

I think company that can grow its production 10% to 12%, add another 30 million barrels or so reserves at $10 to $12 F&D, and more than cover its capital investment, its cash flow are in a good position for that year and I think that's a good description of where we are. So thank you for your interest and we look forward to hearing from you and talking to you in the future.

Thank you.