Thank you for your patience. And welcome to the thirdquarter 2007, Berry Petroleum Company Earnings Presentation. My name is Tanyaand I will be your coordinator for today. At this time, all participants are in a listen-only mode. Wewill conduct a question-and-answer session towards the end of this conference.(Operator Instructions) As a reminder, this conference is being recorded for replaypurposes. I would now like to turn the presentation over to your host fortoday's call, Mr. Bob Heinemann, President and Chief Executive Officer. Pleaseproceed, sir.

Thank you, and good day. I'd like to welcome you to ourthird quarter call and remind you that we are conducting it under Safe Harbor. Today, Berry Petroleum posted its third quarter results for2007. Net income was $26.9 million or $0.60 a share for the quarter compared to$31.4 million in the third quarter of last year. This quarter included the write-down of the company'stri-state acreage in the DJ Basin along with minor impairments in asset sales.Excluding these items net income for the quarter was $29.2 million or $0.65 ashare up considerably compared to the $23 million earned in the second quarterof this year on the same basis. Earnings for the first nine months of 2007 were $97.7million or $2.18 a share up 10% over the comparable period in 2006. Excludingspecials net income was $66 million for the first three quarters of this year. Revenues and discretionary cash flow were again very strongin this last quarter at a $134 million and $71 million respectively. Cash flowwas $2 million lower than the comparable period in 2006, but $13 million higherthan the $59 million of cash flow achieved in the second quarter of this year. The realized price in the quarter was $47.93. Cash flow forthe nine-month period totaled $182 million. Production for the third quarter was just under 26,900barrels a day. This level of production was up 2% over the third quarter of2006, and down 1% compared to the second quarter of this year. For thenine-month period 2007 production was 7% higher than 2006. Production in the third quarter was impacted by intermittentand gas shut-ins in our Piceance and Uinta assets. At Brundage Canyon and Uintaabout a third of our production is from associated gas and when this is shut-init also impacts our oil volumes there. We may see some of these effects in the fourth quarter aswell as we have delayed drilling in both basins due to lower gas prices and theneed to improve the performance of our mesa drilling in the Piceance. We ran three rigs in the Piceance for the third quarter andplan to do the same for most of the fourth. Various productions for October hasaveraged 27,700 barrels a day and it's currently over 28,000 barrels a day. Asset highlights for the third quarter included theperformance of our accelerated Poso Creek development. We've drilled 75 wellshere this year and expect to drill about 13 more in the fourth quarter. Production increased 16% and averaged 21,000 barrels a dayfor the third quarter and included or exited the September average at 2400barrels a day. We expect to exit this year at 2600 barrels a day Poso Creek,depending on some final timing of our drilling, steam generation and waterdisposal facilities. In our North Diatomite asset production increased 24% forthe quarter to 1,125 barrels a day. We will have increased production therefrom about 500 barrels a day at the beginning of the year to 1300 barrels a dayat the end of the year without an effect of adding any new wells. This increase is due the use of more aggressive steamcycling to create flow pathways within the formation. We are now drilling thefirst of the next 50 wells in the asset and anticipate a year-round drillingprogram there next year. We're very encouraged by our diatomite performance and ourability to address technical challenges. With this asset it is now becoming avalue creation story for Berry. We're equally pleased with our drilling performance in thePiceance, where we've seen a step change improvement in the number of daysneeded to drill a mesa well on both our Garden Gulch at North Parachuteacreages. We are now targeting drilling days of less than 17 days atGarden Gulch and 22 days at North Para chute based on the performance of thelast quarter. Our Garden Gulch wells are drilled to about 9500 feet and theNorth Parachute wells are drilled to about 11,000 feet, which accounts for thedifference in the drilling days. Obviously, this improvement efficiency will improve oureconomic returns here over the long-term. As we develop this asset toessentially manufacture natural gas from the base. Production increased by 40%over the second quarter to an average of 11.5 million a day for Q3. We expectanother 30% increase to 15 million a day in the fourth quarter. As we've consistently reported from this asset, productionof these wells is as expected with the 30 day initial production rates slightlyabove our target of 1.2 million cubic feet per day. While natural gas today comprises 27% of Berry's production,the impact of gas price on our operating income is offset by our natural gasconsumption use for steam generation in California. And our hedges that we have in place. Our 2008 projectionsindicate $1 change a $1per Mcf change in Henry Hub, will result in less than a$3 million change in annual net income. The third quarter of 2007 was another good quarter forBerry. With our production mix, our business is obviously benefiting from thecurrent commodity environment. We're equally or even more excited about nextyear. We expect to exit 2007 at about 28,200 barrels a day. Our capital, we have in the queue at about 250 to $300million a day is probably going to be closer to somewhere between 265 and 285and we're looking for production next year to be north of 29,500 barrels a day. So with those comments, I'll turn it over to Ralph Goehring,our CFO, for some more additional detail, Ralph.

Great. Thank you, Bob. Let me start with revenues. Excludingthe sale of our Montalvo asset in the second quarter of 2007 revenues thisquarter increased 3% over the prior quarter. Compared to the second quarter of 2007, oil salesrepresented approximately 75% of the increase in revenues during the quarter.Realized crude prices increased 9% offset partially by 3% decline in crudesales volumes which was mostly related to the sale of our Montalvo asset. Gas revenues on the other hand decreased 2% as a result oflower gas prices offset by a 6% increase in sales volumes. Again, compared toQ2 sales of electricity declined 12% from about $14 million to approximately$12 million as a result of the decrease in electricity prices, which iscorrelated to the lower natural gas prices in California. Discretionary cash flow for the quarter was $70.5 million anincrease of $11.8 million or 20% over the second quarter of 2007. Compared tothe third quarter of 2006 discretionary cash flow decreased slightly by 3.6%. We are projecting our 2007 CapEx, excluding acquisitions, tobe about $275 million. And we'll fund nearly 90% of these expenditures throughour discretionary cash flow. We estimate our discretionary cash flow to beapproximately $245 million based on a $70 WTI price in the fourth quarter. In 2008, we are targeting, as Bob mentioned capitalexpenditures between 250 and $300 million excluding acquisitions. This isobviously very similar in size to this year's capital program and we wouldexpect to provide more detail on these expenditures before year-end. We reduced our debt by $35 million to $440 million atSeptember 30, 2007 from $475 million at June 30, 2007. This reduction occurredas a result of higher realized crude oil pricing and a lower capital spendingrate in the third quarter based on our activity schedule. Our year-end debt at WTI 70 oil price in the fourth quartershould range from $450 million to $455 million. In a year-to-year comparisonfrom year-end 2006 to year-end 2007, our debt will be up approximately $45million. Obviously, our debt outlook improves in a stronger crude priceenvironment. Our operating costs for oil and gas were lower in the thirdquarter of 2007 by 4.8% to $13.75 per BOE compared to the second quarter of2007 at $14.44 per BOE. This variance reflects a $2.1 million decrease in steamrelated cost primarily due to lower fuel gas cost. The decrease was offset inpart by an increase in non-steam related costs of approximately $400,000. Consequently, we have lowered our operating cost to averagein the range of $14 to $15 per BOE for the year. For the nine months endingSeptember 30th our average operating cost per BOE was $14.27. Our DD&A from oil and gas production remained flatbetween the second and third quarters. We continue to expect DD&A costs in2007 to average between $8.50 and $9.50 per BOE. For the nine months endingSeptember 30th our DD&A was $9.04 per BOE. Our G&A in the third quarter of 2007 was $3.78 per BOEcompared to $3.90 per BOE in the second quarter of 2007. This decrease is dueto lower compensation related costs and consulting expenses partially offset byhigher legal and accounting expenses related to business developmentactivities. We expect our 2007 G&A cost to average less than $4.25 per BOE. We did not enter into any significant hedges in the thirdquarter, so there's really not much change there. But overall, our thirdquarter results reflect improved fundamentals of our business over the firstand second quarters of this year in both higher realized prices per BOE andlower operating cost per BOE and a growing production profile. We filed our Form 10-Q for the quarter ended September 30,2007 today. So that is available. And we did add our guidance for 2008 costdata on Page 18. And please note that those projections are based on a $60 WTIaverage oil price and a $7.50 average Henry Hub gas price for 2008. That concludes my comments, Bob.

Thank you, Ralph. We're available to answer questions thatyou might have. Operator?

Yes.

We have three, looks like we have three questioned teed up.

(Operator Instructions) Our first question comes from theline of David Tameron with Wachovia Securities. Please proceed.

Good morning, Bob.

Hi, David.

A couple of questions. Lower drilling days in the Piceance.What's that mean to the bottom line well counts? Or what are your current costsrunning out there?

Well, I think, you know, drilling days, obviously, meanslower costs. I think our better wells now are under $2.5 million. I think we would like to see a couple more improvements onthe cost and the completion. We would like to see costs trend a two in aquarter, $2.3 million. We think at those cost levels and $7.58 gas. We can havepretty competitive returns.

All right. And you're still getting bcf and-a-half.

Yes. That's a good number.

Okay. Moving to the differential between the Rockies andCalifornia. What kind of problems and it doesn't look like it showed up in thenumbers as far as electricity costs. And I know you said you're hedged. Does that kind of takecare of that spread between the two of them?

It does. That kind of that blanket statements that -- I maderight at the end saying $1 change in Henry Hub is, I think it turns out to beabout 2.6 plus million dollars changed in annual income. That takes into account the basis differentials, firmtransportation that we have on pipe in gas coming into California and movingout of the Rockies. So that kind of racks and stacks a whole picture. Andobviously, it's a big benefit for us.

Okay. One clarification question. You guys had obviouslytalked about the MLP. I know you can't discuss the specifics, but 2008 guidancedoes not take into account any MLP. Is that correct?

Well, we can't discuss the MLP and the projections we talkedabout do not assume in MLP.

Okay. Okay. That's what I was looking for. Thanks. And thenfinally, and I'll let everybody else jump on, but I'm a little bit ignoranthere. But I understand that the California Public UtilityCommission recently made some changes with regard to the electricity market.

Right.

Do you guys have a feel for, if there's any impact on thator can you talk a little about that, what the impact could be?

Well, I think it's a little bit premature to know how theruling will really play out and what it will really mean. We're modeling several alternatives right now. It will havea small impact on the cost of steam. You know, what we would say is -- the impact would besomething like a 3% increase in the coverage or 3% decrease in the coveragethat we get from our cogeneration plants. So instead of having cogeneration offset 70% of the cost,maybe it's going to offset 67 or 65% of the cost. So it's real money, but it'scertainly not a showstopper for us.

All right. And then one final and I'll jump off. UintaBasin, it sounds like the whole situation's improved a little bit. Is that,obviously, it has improved from a year ago, but can you give us a currentsnapshot of capacity? I know Holly's got their plant coming on at the end of theyear, can you talk about if that's a limiting factor for you right now thebasin?

No. We have some room to run, actually, and the contracts wehave in place, I think when you look at the basin you get some interestingsnapshots. When you see Canadian imports decline because the Syncrude facilityand maintenance are in turnaround you see less imports. I think we're probably also seeing smaller volumes built outof hinge line that were originally forecast. So overall, that probably leaves alittle bit more room in the macro in the Salt Lake City market.

All right. And your projections right now, you're fine forthe next year, year and-a-half?

Absolutely.

Okay. Thanks

Thank you.

Our next question comes from the line of Brian Singer withGoldman Sachs. Please proceed.

Thank you. Good afternoon.

Hi, Brian.

Hello. Can you talk a little bit more on the Brundage Canyonextension into Ashley forest? You seemed encouraged by some of the results inthe last couple of quarters. Can you talk a little bit more to that and maybewith some specifics on what you're seeing?

Right. I think we now have about, I think, seven wells inthe forest, at least seven wells drilled, not all of them are on productionbecause of their location. We have category exemptions to drill up to about 25 wellsthere and that will be a big focus of our '08 program. We anticipate submittingan EIS for the forest, which could prove up some integer factor greater thanthat. We would say that the forest, at least the first wells we'vedrilled they're the forest to the south of Brundage Canyon look really quitepromising. They look very comparable to our better 40-acre locationsthat we drilled at Brundage. And one of the wells that we -- probably the firstor second well we drilled in the forest is still remains one of the best wellsin the field, although it's considerably more gas-prone, more gas-bearing thanother wells that we've drilled there. So we like the forest. We have some permitting and someenvironmental work to get full approval so we can talk about big numbers ofwells.

Great. And then secondly, if we look at the SouthMidway-Sunset area, production was down a little bit quarter-on-quarter. Canyou talk to what the natural decline rate is and how do you manage that goingforward?

We're actually, have been doing quite a bit of work at SouthMidway in the last quarter and we're encouraged about two new concepts thatwe're trying to bring to the field. One is that we've gone back in and done quite a bit moregeologic work and we believe that some of the, or some significant portion ofthe early horizontal wells drilled in the field were considerably above the oilwater contact. So we still have quite a bit of pay to perhaps go over to try toexploit in a secondary group of horizontal wells. We drilled about 10 in the quarter and they're showing realbenefit as we go into the fourth quarter. We were also doing quite a bit of temperature survey work inthe field and we're learning that in a good bit of the down dip sections out onthe flanks of the field that they're still relatively cold and so we're goingwith some continuous injection from vertical wells in that part of the fieldand we're starting to see about a 200 to 300-barrel a day increase inproduction there from a short period of time. Probably the decline that you saw in the quarter was becausewe had had a steam flood in a lease in the field that we were testing theeconomics of, really based on the lateral continuity of the reservoir. We had apretty successful run there in the second quarter but got discouraged about theeconomics in the third quarter. Obviously, now with commodity prices in the shape thatthey're in and some additional capacity that we have, we're back into thatlease in a big way and it's responding and recovering quite nicely. So we actually think in our home base assets, which are abig part of our South Midway leases. We have a good chance to offset much ofthe decline. So we could get back and talk about more normal heavy oil declinesin our South Midway of maybe 6% to 8%. We'll take some maintenance capital to get that, but we'reactually excited. I mean, we can talk a lot about the diatomite and about thePiceance but the value driver for the company is the performance of SouthMidway.

Great. Thank you.

Thank you, Brian.

(Operator Instructions) Our next question comes from theline of Duane Grubert with CRT Capital Group. Please proceed.

Yes, Bob, on the diatomite program, you didn't drill verymany wells in the third quarter. You're going to drill a bunch more in thefourth. I'm just wondering what's the thinking behind that and if you're stillevolving your completion designs as you get into the fourth quarter?

Right. You know, I think we've made and since many peoplehave heard from us. I mean, we made a big design or big development plan changein the field, which previously was based on a combination of continuousinjection fabric operations using hydraulic refrac wells. Now we are going to more traditional diatomite development,which relies on more aggressive steam injection where the steam injectionitself actually stimulates the formation, actually fracs the formation. Sowe're very encouraged about that. These wells are producing essentially withoutpump and without a frac treatment, which obviously will improve the economics. We wanted to test the concept in a number of wells and wedecided to do that before we went into a drilling expansion. With the success of that program, we're essentially nowgoing into a continuous drilling program in the asset, which should go on forseveral quarters, certainly, the fourth quarter of this year and all fourquarters of next year. We have some optimization to do there, for example, howclose can we drill close to existing thermal operations, so on and so on. Wealso have another technical challenge. I mean, there's well known that there are two predominantzones in the diatomite, the Opal-A and the Opal-CT. We're extremely confidentfrom the response in the Opal A. We want to do a little bit more work to beequally bullish about the CT. Our initial tests into the CT look very promising. So thisis an asset, which is really going from being -- this is a difficult,technically challenged asset to one where we think we're going to make a lot ofmoney at Berry.

When you think about how the step change in oil priceimpacts your view of reserves, when we get to the end of the year and you doyour reserves for the SEC and you're using that high end of your price thatwe're likely to see. How aggressive do you think you might be in terms of aphilosophy of adding reserves because of price revisions?

Typically, we don't have barrels or Mcf, which get caught onprice so we would continue, I think, to book the reserves in the way that wealways do. We're actually as we're right in the middle of our capital program,we're also right in the middle of our reserve forecasting at the end of theyear. And I really don't foresee at this point any big changesover what we've said already. I don't think we have a -- we'll have a change inquote, unquote, the philosophy or the methodology whereby we are bookingreserves.

Okay. Thank you very much.

Thank you, Duane.

Our next question comes from the line of Patrick [Orkin]with [Zehar] Securities. Please proceed.

Good morning. Congratulations on a great quarter.

Thank you, Pat.

Bob, with respect to the guidance for production in 2008,where is most of that growth coming from?

Well, you're going to see growth in the diatomite. You'regoing to see continued growth in Poso. You're going to see growth in thePiceance. You'll see, and then probably also elsewhere in the portfolio, theups and the downs would kind of cancel each other out. This is what I wouldsay.

Okay. And then with respect to those areas, which of thoseareas, if not all, would have the most opportunity for acceleratingdevelopment?

They probably all have some. What happens, actually, in thediatomite and the Piceance area is we have quite a bit of infrastructure workto do. In the diatomite in particular we have quite a bit of earth to movearound to flatten the terrain for pad drilling or to set additional facilities,steam generation, et cetera. So that actually kind of becomes a rate-limitingstep from a project management perspective. Same can be true in the Piceance, although we are makingquite a bit of investment in '07 and then in the first part of '08 intopipelines, access into some of those leases. So acceleration is not really acapital allocation issue. It's really an infrastructure issue to keep theinfrastructure ahead of the drill bit.

Okay. Very good. Thank you.

Thank you, Pat.

Our next question comes from the line of David Tameron withWachovia Securities. Please proceed.

Hi Bob. Follow-up question. Did you give us or could you give us a level of productionthat was shut-in during the quarter, what that impacted your third quartervolumes by?

Yes, certainly I alluded to it in the comments, Dave, I justhave not put the pencil to paper. But you know, it's got to be in the hundredsof barrels a day. But you know, if you come back to us with that, we might tryto take a shot at that. I just don't know it off the top of my head.

That's fine. And for fourth quarter, how much does theCheyenne Plains hit you guys? Is that an impact?

Yes, somewhat. I mean, we try to push volumes to otherpipelines and we've found some relief in some other pipelines that are in thearea but it certainly does have an impact. I can't tell you how many Mcf a daythat will be but we do have to seek some other take-away?

All right. Fair enough. Thanks.

Thank you, Dave.

Our next question comes from the line of Eric Hagen withMerrill Lynch. Please proceed.

Hey, Bob.

Hi Eric.

Brundage Canyon, just moving back there, has pricingimproved there? What are differentials running now?

Differentials are down in the Uinta. I think we saw them inthe summer, probably in the $10 to $12 range. I think the drivers there arepretty much what we've noted earlier is probably less Canadian imports and less[non-waxy] production growth. There's also, you know, people have also been seeking otherrefining options over the last 18 months or so and probably some of those havefirmed up and they've taken some barrels out of Salt Lake City as well, perhapsover the longer-term but I really don't know that.

And that's down from a peak of like 15 to 18? Is that kindof the?

I think that's probably a fair number.

And 20-acre spacing how's that going? Are you seeing reallymuch communication between wells?

I think it's mixed. I think we have some 20-acre wells thatwe're really interested in a primary. Obviously, the interesting thing when youdown-space and you look at other operators in the basin that if we do seeinterference, that could set us up for a water flood in some portions of thefield. We're actually trying to get our head around putting capitalfor a water flood pilot in '08. Whether that would be on 20 acre spacing orwould require 10 acre spacing, we don't know yet. So there's Brundage Canyon, we're probably getting, I wouldguess, 10 to 12% recovery from the field as it is. Certainly, if we could waterflood we would have the prospect of another 10 to 12% recovery, albeit take adifferent type of operation of the asset. So, too soon to really make the call on 20s. Although, if wehave a lot of continuity it's probably going to set up a water flood.

Okay. And now in terms of just -- how much activity do youneed to maintain out there to keep production flat? Can you keep it flat withone rig drilling or?

That's the call. I would say one rig will keep it flat.We'll look at all kinds of auction there for next year from one rigs year roundto one rig year round plus another rig in the summer, et cetera, et cetera. And if we can get our permitting process or permittingengine greased we could go back at looking at two rigs.

The following is on Poso Creek. I think you have it growingto about 3800 barrels per day in 2008, if I recall correctly. What do you think your peak production from that field couldbe, Bob over the next few years?

We probably see it going to low 4,000, 4200 something likethat. Maybe that's a late '08 exit maybe that's '09. It's an interesting asset. It's high permeable reservoir, but it's not as thick as someother heavy oil reservoirs that you see. So the issue there is how aggressivelycan we steam flood without seeing a lot of break-through or gravity override inthe play. So, we have to be a little bit careful there. Obviously, oneof the benefits we get as we ramp up the cycle the wells to preheat, before wedo as press to steam flood. So it's a good situation. It's a great performance from arelatively small asset.

Great. Thanks, Bob.

Thank you, Eric.

There are no further questions at this time, sir.

I'd like to thank everyone for tuning in and listening to ustoday and your questions. We look forward to speaking to you at year-end. Thankyou.

This concludes the presentation. You may now disconnect. Andhave a great day.