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Berry Petroleum Co. (NYSE:BRY)

Q3 2007 Earnings Conference Call

October 31, 2007, 11:00 am ET

Executives

Bob Heinemann - President and CEO

Ralph Goehring - EVP and CFO

Analysts

David Tameron - Wachovia Securities

Brian Singer - Goldman Sachs

Duane Grubert - CRT Capital Group

Patrick Orkin - Zehar Securities

Eric Hagen - Merrill Lynch

Operator

Thank you for your patience. And welcome to the third quarter 2007, Berry Petroleum Company Earnings Presentation. My name is Tanya and I will be your coordinator for today.

At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Bob Heinemann, President and Chief Executive Officer. Please proceed, sir.

Bob Heinemann

Thank you, and good day. I'd like to welcome you to our third quarter call and remind you that we are conducting it under Safe Harbor.

Today, Berry Petroleum posted its third quarter results for 2007. 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's tri-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 a share up considerably compared to the $23 million earned in the second quarter of this year on the same basis.

Earnings for the first nine months of 2007 were $97.7 million or $2.18 a share up 10% over the comparable period in 2006. Excluding specials net income was $66 million for the first three quarters of this year.

Revenues and discretionary cash flow were again very strong in this last quarter at a $134 million and $71 million respectively. Cash flow was $2 million lower than the comparable period in 2006, but $13 million higher than 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 for the nine-month period totaled $182 million.

Production for the third quarter was just under 26,900 barrels a day. This level of production was up 2% over the third quarter of 2006, and down 1% compared to the second quarter of this year. For the nine-month period 2007 production was 7% higher than 2006.

Production in the third quarter was impacted by intermittent and gas shut-ins in our Piceance and Uinta assets. At Brundage Canyon and Uinta about a third of our production is from associated gas and when this is shut-in it also impacts our oil volumes there.

We may see some of these effects in the fourth quarter as well as we have delayed drilling in both basins due to lower gas prices and the need to improve the performance of our mesa drilling in the Piceance.

We ran three rigs in the Piceance for the third quarter and plan to do the same for most of the fourth. Various productions for October has averaged 27,700 barrels a day and it's currently over 28,000 barrels a day.

Asset highlights for the third quarter included the performance of our accelerated Poso Creek development. We've drilled 75 wells here this year and expect to drill about 13 more in the fourth quarter.

Production increased 16% and averaged 21,000 barrels a day for the third quarter and included or exited the September average at 2400 barrels 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 water disposal facilities.

In our North Diatomite asset production increased 24% for the quarter to 1,125 barrels a day. We will have increased production there from about 500 barrels a day at the beginning of the year to 1300 barrels a day at the end of the year without an effect of adding any new wells.

This increase is due the use of more aggressive steam cycling to create flow pathways within the formation. We are now drilling the first of the next 50 wells in the asset and anticipate a year-round drilling program there next year.

We're very encouraged by our diatomite performance and our ability to address technical challenges. With this asset it is now becoming a value creation story for Berry.

We're equally pleased with our drilling performance in the Piceance, where we've seen a step change improvement in the number of days needed to drill a mesa well on both our Garden Gulch at North Parachute acreages.

We are now targeting drilling days of less than 17 days at Garden Gulch and 22 days at North Para chute based on the performance of the last quarter. Our Garden Gulch wells are drilled to about 9500 feet and the North Parachute wells are drilled to about 11,000 feet, which accounts for the difference in the drilling days.

Obviously, this improvement efficiency will improve our economic returns here over the long-term. As we develop this asset to essentially 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 expect another 30% increase to 15 million a day in the fourth quarter.

As we've consistently reported from this asset, production of these wells is as expected with the 30 day initial production rates slightly above 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 gas consumption use for steam generation in California.

And our hedges that we have in place. Our 2008 projections indicate $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 for Berry. With our production mix, our business is obviously benefiting from the current commodity environment. We're equally or even more excited about next year. We expect to exit 2007 at about 28,200 barrels a day.

Our capital, we have in the queue at about 250 to $300 million a day is probably going to be closer to somewhere between 265 and 285 and 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.

Ralph Goehring

Great. Thank you, Bob. Let me start with revenues. Excluding the sale of our Montalvo asset in the second quarter of 2007 revenues this quarter increased 3% over the prior quarter.

Compared to the second quarter of 2007, oil sales represented approximately 75% of the increase in revenues during the quarter. Realized crude prices increased 9% offset partially by 3% decline in crude sales volumes which was mostly related to the sale of our Montalvo asset.

Gas revenues on the other hand decreased 2% as a result of lower gas prices offset by a 6% increase in sales volumes. Again, compared to Q2 sales of electricity declined 12% from about $14 million to approximately $12 million as a result of the decrease in electricity prices, which is correlated to the lower natural gas prices in California.

Discretionary cash flow for the quarter was $70.5 million an increase of $11.8 million or 20% over the second quarter of 2007. Compared to the third quarter of 2006 discretionary cash flow decreased slightly by 3.6%.

We are projecting our 2007 CapEx, excluding acquisitions, to be about $275 million. And we'll fund nearly 90% of these expenditures through our discretionary cash flow. We estimate our discretionary cash flow to be approximately $245 million based on a $70 WTI price in the fourth quarter.

In 2008, we are targeting, as Bob mentioned capital expenditures between 250 and $300 million excluding acquisitions. This is obviously very similar in size to this year's capital program and we would expect to provide more detail on these expenditures before year-end.

We reduced our debt by $35 million to $440 million at September 30, 2007 from $475 million at June 30, 2007. This reduction occurred as a result of higher realized crude oil pricing and a lower capital spending rate in the third quarter based on our activity schedule.

Our year-end debt at WTI 70 oil price in the fourth quarter should range from $450 million to $455 million. In a year-to-year comparison from year-end 2006 to year-end 2007, our debt will be up approximately $45 million. Obviously, our debt outlook improves in a stronger crude price environment.

Our operating costs for oil and gas were lower in the third quarter of 2007 by 4.8% to $13.75 per BOE compared to the second quarter of 2007 at $14.44 per BOE. This variance reflects a $2.1 million decrease in steam related cost primarily due to lower fuel gas cost. The decrease was offset in part by an increase in non-steam related costs of approximately $400,000.

Consequently, we have lowered our operating cost to average in the range of $14 to $15 per BOE for the year. For the nine months ending September 30th our average operating cost per BOE was $14.27.

Our DD&A from oil and gas production remained flat between the second and third quarters. We continue to expect DD&A costs in 2007 to average between $8.50 and $9.50 per BOE. For the nine months ending September 30th our DD&A was $9.04 per BOE.

Our G&A in the third quarter of 2007 was $3.78 per BOE compared to $3.90 per BOE in the second quarter of 2007. This decrease is due to lower compensation related costs and consulting expenses partially offset by higher legal and accounting expenses related to business development activities. 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 third quarter, so there's really not much change there. But overall, our third quarter results reflect improved fundamentals of our business over the first and second quarters of this year in both higher realized prices per BOE and lower 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 cost data on Page 18. And please note that those projections are based on a $60 WTI average oil price and a $7.50 average Henry Hub gas price for 2008.

That concludes my comments, Bob.

Bob Heinemann

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

Operator

Yes.

Bob Heinemann

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

Questions-and-Answers Session

Operator

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

David Tameron - Wachovia Securities

Good morning, Bob.

Bob Heinemann

Hi, David.

David Tameron - Wachovia Securities

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 costs running out there?

Bob Heinemann

Well, I think, you know, drilling days, obviously, means lower costs. I think our better wells now are under $2.5 million.

I think we would like to see a couple more improvements on the cost and the completion. We would like to see costs trend a two in a quarter, $2.3 million.

We think at those cost levels and $7.58 gas. We can have pretty competitive returns.

David Tameron - Wachovia Securities

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

Bob Heinemann

Yes. That's a good number.

David Tameron - Wachovia Securities

Okay. Moving to the differential between the Rockies and California. What kind of problems and it doesn't look like it showed up in the numbers as far as electricity costs.

And I know you said you're hedged. Does that kind of take care of that spread between the two of them?

Bob Heinemann

It does. That kind of that blanket statements that -- I made right at the end saying $1 change in Henry Hub is, I think it turns out to be about 2.6 plus million dollars changed in annual income.

That takes into account the basis differentials, firm transportation that we have on pipe in gas coming into California and moving out of the Rockies.

So that kind of racks and stacks a whole picture. And obviously, it's a big benefit for us.

David Tameron - Wachovia Securities

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

Bob Heinemann

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

David Tameron - Wachovia Securities

Okay. Okay. That's what I was looking for. Thanks. And then finally, and I'll let everybody else jump on, but I'm a little bit ignorant here.

But I understand that the California Public Utility Commission recently made some changes with regard to the electricity market.

Bob Heinemann

Right.

David Tameron - Wachovia Securities

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

Bob Heinemann

Well, I think it's a little bit premature to know how the ruling will really play out and what it will really mean.

We're modeling several alternatives right now. It will have a small impact on the cost of steam.

You know, what we would say is -- the impact would be something like a 3% increase in the coverage or 3% decrease in the coverage that 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's certainly not a showstopper for us.

David Tameron - Wachovia Securities

All right. And then one final and I'll jump off. Uinta Basin, 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 current snapshot of capacity?

I know Holly's got their plant coming on at the end of the year, can you talk about if that's a limiting factor for you right now the basin?

Ralph Goehring

No. We have some room to run, actually, and the contracts we have in place, I think when you look at the basin you get some interesting snapshots. When you see Canadian imports decline because the Syncrude facility and maintenance are in turnaround you see less imports.

I think we're probably also seeing smaller volumes built out of hinge line that were originally forecast. So overall, that probably leaves a little bit more room in the macro in the Salt Lake City market.

David Tameron - Wachovia Securities

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

Ralph Goehring

Absolutely.

David Tameron - Wachovia Securities

Okay. Thanks

Ralph Goehring

Thank you.

Operator

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

Brian Singer - Goldman Sachs

Thank you. Good afternoon.

Bob Heinemann

Hi, Brian.

Brian Singer - Goldman Sachs

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

Bob Heinemann

Right. I think we now have about, I think, seven wells in the forest, at least seven wells drilled, not all of them are on production because of their location.

We have category exemptions to drill up to about 25 wells there and that will be a big focus of our '08 program. We anticipate submitting an EIS for the forest, which could prove up some integer factor greater than that.

We would say that the forest, at least the first wells we've drilled they're the forest to the south of Brundage Canyon look really quite promising.

They look very comparable to our better 40-acre locations that we drilled at Brundage. And one of the wells that we -- probably the first or second well we drilled in the forest is still remains one of the best wells in the field, although it's considerably more gas-prone, more gas-bearing than other wells that we've drilled there.

So we like the forest. We have some permitting and some environmental work to get full approval so we can talk about big numbers of wells.

Brian Singer - Goldman Sachs

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

Bob Heinemann

We're actually, have been doing quite a bit of work at South Midway in the last quarter and we're encouraged about two new concepts that we're trying to bring to the field.

One is that we've gone back in and done quite a bit more geologic work and we believe that some of the, or some significant portion of the early horizontal wells drilled in the field were considerably above the oil water contact. So we still have quite a bit of pay to perhaps go over to try to exploit in a secondary group of horizontal wells.

We drilled about 10 in the quarter and they're showing real benefit as we go into the fourth quarter.

We were also doing quite a bit of temperature survey work in the field and we're learning that in a good bit of the down dip sections out on the flanks of the field that they're still relatively cold and so we're going with some continuous injection from vertical wells in that part of the field and we're starting to see about a 200 to 300-barrel a day increase in production there from a short period of time.

Probably the decline that you saw in the quarter was because we had had a steam flood in a lease in the field that we were testing the economics of, really based on the lateral continuity of the reservoir. We had a pretty successful run there in the second quarter but got discouraged about the economics in the third quarter.

Obviously, now with commodity prices in the shape that they're in and some additional capacity that we have, we're back into that lease in a big way and it's responding and recovering quite nicely.

So we actually think in our home base assets, which are a big part of our South Midway leases. We have a good chance to offset much of the decline. So we could get back and talk about more normal heavy oil declines in our South Midway of maybe 6% to 8%.

We'll take some maintenance capital to get that, but we're actually excited. I mean, we can talk a lot about the diatomite and about the Piceance but the value driver for the company is the performance of South Midway.

Brian Singer - Goldman Sachs

Great. Thank you.

Bob Heinemann

Thank you, Brian.

Operator

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

Duane Grubert - CRT Capital Group

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

Bob Heinemann

Right. You know, I think we've made and since many people have heard from us. I mean, we made a big design or big development plan change in the field, which previously was based on a combination of continuous injection 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 injection itself actually stimulates the formation, actually fracs the formation. So we're very encouraged about that. These wells are producing essentially without pump and without a frac treatment, which obviously will improve the economics.

We wanted to test the concept in a number of wells and we decided to do that before we went into a drilling expansion.

With the success of that program, we're essentially now going into a continuous drilling program in the asset, which should go on for several quarters, certainly, the fourth quarter of this year and all four quarters of next year.

We have some optimization to do there, for example, how close can we drill close to existing thermal operations, so on and so on. We also have another technical challenge.

I mean, there's well known that there are two predominant zones in the diatomite, the Opal-A and the Opal-CT. We're extremely confident from the response in the Opal A. We want to do a little bit more work to be equally bullish about the CT.

Our initial tests into the CT look very promising. So this is 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 of money at Berry.

Duane Grubert - CRT Capital Group

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

Bob Heinemann

Typically, we don't have barrels or Mcf, which get caught on price so we would continue, I think, to book the reserves in the way that we always 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 the year.

And I really don't foresee at this point any big changes over what we've said already. I don't think we have a -- we'll have a change in quote, unquote, the philosophy or the methodology whereby we are booking reserves.

Duane Grubert - CRT Capital Group

Okay. Thank you very much.

Bob Heinemann

Thank you, Duane.

Operator

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

Patrick Orkin - Zehar Securities

Good morning. Congratulations on a great quarter.

Bob Heinemann

Thank you, Pat.

Patrick Orkin - Zehar Securities

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

Bob Heinemann

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

Patrick Orkin - Zehar Securities

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

Bob Heinemann

They probably all have some. What happens, actually, in the diatomite and the Piceance area is we have quite a bit of infrastructure work to do. In the diatomite in particular we have quite a bit of earth to move around to flatten the terrain for pad drilling or to set additional facilities, steam generation, et cetera. So that actually kind of becomes a rate-limiting step from a project management perspective.

Same can be true in the Piceance, although we are making quite a bit of investment in '07 and then in the first part of '08 into pipelines, access into some of those leases. So acceleration is not really a capital allocation issue. It's really an infrastructure issue to keep the infrastructure ahead of the drill bit.

Patrick Orkin - Zehar Securities

Okay. Very good. Thank you.

Bob Heinemann

Thank you, Pat.

Operator

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

David Tameron - Wachovia Securities

Hi Bob. Follow-up question.

Did you give us or could you give us a level of production that was shut-in during the quarter, what that impacted your third quarter volumes by?

Bob Heinemann

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

David Tameron - Wachovia Securities

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

Bob Heinemann

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

David Tameron - Wachovia Securities

All right. Fair enough. Thanks.

Bob Heinemann

Thank you, Dave.

Operator

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

Eric Hagen - Merrill Lynch

Hey, Bob.

Bob Heinemann

Hi Eric.

Eric Hagen - Merrill Lynch

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

Bob Heinemann

Differentials are down in the Uinta. I think we saw them in the summer, probably in the $10 to $12 range. I think the drivers there are pretty 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 other refining options over the last 18 months or so and probably some of those have firmed up and they've taken some barrels out of Salt Lake City as well, perhaps over the longer-term but I really don't know that.

Eric Hagen - Merrill Lynch

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

Bob Heinemann

I think that's probably a fair number.

Eric Hagen - Merrill Lynch

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

Bob Heinemann

I think it's mixed. I think we have some 20-acre wells that we're really interested in a primary. Obviously, the interesting thing when you down-space and you look at other operators in the basin that if we do see interference, that could set us up for a water flood in some portions of the field.

We're actually trying to get our head around putting capital for a water flood pilot in '08. Whether that would be on 20 acre spacing or would require 10 acre spacing, we don't know yet.

So there's Brundage Canyon, we're probably getting, I would guess, 10 to 12% recovery from the field as it is. Certainly, if we could water flood we would have the prospect of another 10 to 12% recovery, albeit take a different type of operation of the asset.

So, too soon to really make the call on 20s. Although, if we have a lot of continuity it's probably going to set up a water flood.

Eric Hagen - Merrill Lynch

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

Bob Heinemann

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 round to one rig year round plus another rig in the summer, et cetera, et cetera.

And if we can get our permitting process or permitting engine greased we could go back at looking at two rigs.

Eric Hagen - Merrill Lynch

The following is on Poso Creek. I think you have it growing to about 3800 barrels per day in 2008, if I recall correctly.

What do you think your peak production from that field could be, Bob over the next few years?

Bob Heinemann

We probably see it going to low 4,000, 4200 something like that. 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 some other heavy oil reservoirs that you see. So the issue there is how aggressively can we steam flood without seeing a lot of break-through or gravity override in the play.

So, we have to be a little bit careful there. Obviously, one of the benefits we get as we ramp up the cycle the wells to preheat, before we do as press to steam flood.

So it's a good situation. It's a great performance from a relatively small asset.

Eric Hagen - Merrill Lynch

Great. Thanks, Bob.

Bob Heinemann

Thank you, Eric.

Operator

There are no further questions at this time, sir.

Bob Heinemann

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

Operator

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

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