Thank you, and good morning. Let me begin by reminding you that we are conducting the call under Safe Harbor.

Michael Duginski, our Chief Operating Officer; and David Wolf, our Chief Financial Officer are with me today, and we'll make more detailed operational and financial comments after my opening remarks. Today, Berry Petroleum Company has posted its second quarter results for 2012.

The company reported net income of $81 million for the quarter from oil and gas revenues of $222 million. Net earnings were affected by several nonrecurring items.

Excluding these, the adjusted net income was $41 million or $0.73 per share. Discretionary cash flow for the quarter was $119 million, and the company generated an operating margin of approximately $48 per barrel.

Q1 production was 35,340 barrels of oil equivalent per day, which was comprised of 26,300 barrels per day of crude oil and 54 million cubic feet per day of natural gas. Oil production was 5% higher than the first quarter.

Natural gas declined 3% as expected. Production from all 4 of the company's development projects grew in the second quarter.

The Permian was up 16%, the Diatomite increased 11%, our New Steam Floods were up 16% and the Uinta grew by 4%. Next, I want to give you some specific updates on the Diatomite.

As you well know, we've been implementing a number of operational changes in the field over the last 9 months. I would offer 3 observations that summarize the status of these changes.

Number one, we worked diligently to improve our realtime surveillance in the field. Our objective here is to have the capability to monitor the zonal isolation of our injection, to measure the productivity of all of our wells in realtime, and to monitor their mechanical integrity.

Second, with our 2012 drilling, we now have 300 completions in our cyclic rotation. We're currently optimizing the size and frequency of our injection cycles to limit the net dilation of the reservoir formation and thereby minimize wellbore stress.

The response to this injection strategy from our new wells thus far is confirming our cycling time curve, and we are encouraged that we have not seen any failures in the wells drilled in 2012. Number three, we're very focused on developing the Diatomite in a more continuous manner.

This means that we have to conduct drilling operations on well pads immediately adjacent to areas that may contain active steam. We're working with other engineering companies to develop this capability that will give us full development flexibility going forward, and eliminate the need to stop injection in neighboring areas as we drill new wells or replacement wells.

So in summary, our results indicate that the Diatomite is starting to work again as we delivered consecutive monthly production increases in the second quarter. As you are aware, March production was at a low level, and in fact, our Q2 average was up about 35% over March.

I'll ask Michael Duginski to discuss the rest of the company's operations momentarily. I would point out that we've continued to experience some processing concerns in the Permian and some project management issues on our New Steam Floods.

I would classify these, along with the starting point for the quarter in the Diatomite as a timing issue, and these issues are not related to reservoir performance. However, when we take all these together, they have lowered our full year guidance to approximately 37,000 barrels a day for 2012, which represents 13% oil growth for the year.

Now let me turn the floor over to David Wolf, who will provide additional details in our financial performance for the quarter.

Thanks, Bob. For the second quarter of 2012, oil and gas revenues were $222 million.

Oil revenues were $211 million. Gas revenues were $11 million.

Total revenues, including electricity sales, gas marketing and other items were $230 million. Our realized oil price per barrel averaged $90.08.

Average realized natural gas price was $2.22 per MCF. That gave us an average BOE sales price, including cash derivative settlements, of $70.40.

Oil and gas operating costs for the second quarter were $19.42 per BOE. Production taxes were $3.01.

DD&A was $16.18 per BOE. G&A was $5.59 and interest expense is $6.46 per BOE.

Total cost for the quarter averaged $50.66, in line with guidance. We're also maintaining our cost guidance for the quarter.

Our first quarter operating margin was approximately $48 per BOE. Our oil hedges added only $0.79 per BOE.

So we feel good about our oil hedges. We also had minimal impact from NGL pricing, given only 3% of our revenues are from NGLs.

Importantly, the margin specific to our 3 oil basins, where all of our capital is allocated, is $59 per BOE. During the quarter, we redeemed all of our $200 million 8 1/4 notes that were due 2016 and repurchased $150 million of our 10 1/4 notes due 2014.

At the end of the quarter, our total debt was $1.5 billion comprised of $1.1 billion of notes, with maturities of 14, 20 and 22, and $401 million drawn under our senior credit facility. Today, our weighted average interest cost is 6%, and we have approximately $730 million of liquidity.

With that, I'll turn the call over to Michael to walk through an operational review of the quarter.

Thanks, David. As Bob mentioned, second quarter production was 35,340 BOE a day, up 3% from Q1, while our natural gas assets declined approximately 10% for the quarter, increasing our oil percentage to 74% of total production.

In the Uinta, production increased 4%, driven by a 15% increase in Lake Canyon, while Brundage Canyon remained flat. The company drilled 22 Uinta wells with 3 rigs in Q2 and plan to drill 60 additional wells with 4 rigs during the remainder of the year.

We are targeting higher oil potential areas of the Wasatch and continue to be satisfied with the co-mingled Wasatch Green River drilling results. In June, the company received its final U.S.

Forest Service EIS approval for Ashley Forest development. There, we have an inventory of 375 locations on approximately 25,000 net acres, with 100% working interest and are actively permitting the next phase of development.

In the second quarter, the company purchased an additional 10,000 net acres in Lake Canyon, targeting the Wasatch formation, increasing our total net Uinta acreage by 10% to approximately 106,000 net acres. In the Permian, Q2 production increased 16% as we drilled 25 wells with 6 drilling rigs and plan to continue that pace for the remainder of the year.

Much has been discussed surrounding the infrastructure issues in the Permian Basin as a result of increased activity there. For Berry, we saw challenges in the second quarter, including maintenance-related disruptions, which caused temporary shut-in production for gas processers to upgrade their facilities.

Elevated activity in the basin has resulted in higher line pressures, which have restricted our flow rate of our wells and reduced our production from new wells. Finally, we began to see some ethane rejection toward the end of the second quarter.

As a company, only a small percentage of Berry's total production comes from NGLs. However, a majority of NGL production comes from the Permian Basin, so we have seen an impact there.

The second area outlets of the company established in key operating areas during the first quarter helped to reduce the volume of our gas curtailed for maintenance-related disruptions. However, late in the quarter, we felt the effects from higher line pressures and ethane rejection.

The assessment of our 32,000 acres outside the Wolfberry fairway is proceeding on schedule, and we still expect to drill 4 appraisal wells in 2012 and assess the data by year-end. Two of the wells have been drilled to date, and in our various stages of evaluation, and we are currently drilling the third well.

In California, in the New Steam Floods area, production increased 16%. In Q2, the company drilled 38 wells, invested in significant infrastructure and started our steam flood pilots.

Although we saw our project management schedule slip due to equipment delays, the majority of our production response is forecasted for the second half the year. A few notes in closing before I turn it back to Bob.

We continued to experience excellent fundamentals for crude oil in California and a high oil-to-gas price ratio, delivering approximately $73 per barrel operating margin in the second quarter. In the Diatomite, we are applying significantly new technology, reducing the reservoir dilation and have had no wellbore failures.

Combined with the newly drilled wells, we have a higher completion cut-off [ph], resulting in increasing production. Permian industry-wide rig count increases in natural gas and NGL infrastructure will continue to put pressure on costs and production.

Although curtailments are lower today, total impact continues to affect the company's production. In the Uinta, with the Ashley Forest EIS approval, we'll focus on our higher interest wells in the second half of the year, and we continue to be encouraged by the Wasatch results.

Thank you, David and Michael. We are here to answer your questions.

Just on the Diatomite, you talked about -- I guess, second quarter you saw this sequential increasing of production. Can you talk about what levels you're at today, and then a ballpark or range of where you're going to be at year-end?

Well, I think if you just looked at the Diatomite this year, we kind of went through the first quarter with production decreases. And we got good responses with production increases in the second quarter.

We're cycling today somewhere between probably 3,500 barrels a day and 4,000 barrels a day, kind of depends on which day we have wells on soap and injection in production. If you just continue to look where we think we're going to be for the year, I mean we're going to be touching that 5,000 barrel-a-day level by the end of the year.

Okay. And can you maybe -- I think you, maybe the last quarter you talked about your increasing your -- the amount that you're steaming.

Can you talk about, I guess before all the permitting issues, your peak amount of steam injection versus what you're doing today?

Yes, I think it's a good question. If you looked at the summer highs of 2011, we were producing 4,500, 4,700 barrels a day.

We were injecting about 5,500 barrels of steam. We had about 225 active completions.

Today, our completion count again is a little bit over 300. We moved our steam injection to somewhere between 60,000 and 65,000 barrels a day.

So we think if we can confirm and continue to confirm the type curve we saw last summer, and we have a number of areas that are right on that type curve, we think we get that kind of performance.

Okay, that was helpful. And one final question on the Permian.

I mean, we know that the basin in general is tight. How should we think about your production growth assuming some sort of down time, kind of each quarter.

I mean, do you feel comfortable with growing 500 to 700 barrels a day per quarter? Or is this going to be -- vary all over the place, depending on how tight everything is?

Yes, I think -- I don't have it in front of me that quite laid out like that, Brian. I would say we're going to be about 7,000 barrels a day in the Permian for the year.

The way I think of this is, is we really have 3 issues. Michael pointed these out.

We've got the ethane rejection. That kind of hit us late the quarter.

We've got these intermittent gas plants that go down for maintenance or expansions. And then the one that is a little bit new to us is in some of our better areas, we're seeing increased line pressure.

These are areas that we would be putting our production into that might have been 25 PSI at the beginning of the year, and they've jumped up to 100 PSI about 6 months later, 7 months later. So while that's not really a curtailment, that's not really a plant outage, that rising line pressure limits the productivity of your wells and your ability to get new production in.

So that -- those are the things that have very little to do with the performance of the reservoir, the performance of the actual well. But at the end of the day, it does impact the number of barrels that we can process.

Now anywhere results -- would you share anywhere result that you were drilling horizontal wells in the Uteland area. I thought you had won a couple of wells you were drilling, completing.

Would you share any data?

Yes, we're in some Uteland Butte wells, drilled some in the beginning of the year. I think there's probably 2 reasons why we pulled back in the Uteland this year.

Number one, we're really pleased with our commingled Wasatch. And we've got some areas particularly in Lake Canyon that are north of Brundage that are giving us very good results with good economics.

I think the other issue is that we believe we really needed longer laterals in the Uteland Butte horizontals for them to give us decent recoveries to generate the return. The first generation of horizontals, I think the laterals were about 3,500 feet.

We now think the lateral needs to be about twice that. And we've requested some additional permission to be able to drill laterals of that length.

Not sure if we're going to drill any of those in the back half of the year, we may postpone that to '13.

On the gas production, it looks like it's holding much better than originally thought. Any comment on it?

I think it's probably 2 things. Number one, as we drill more wells in Lake Canyon, for example, our Lake Canyon's up 16%, we do get a fair amount of associated gas from Lake Canyon, as well as the Permian.

The other thing is, we're a little bit further down that really steep decline in some of our gas assets. So as time goes on, that decline gets a little bit less pronounced.

I think we probably also have a little bit better drainage in some of our gas wells than we probably forecast. So it's really the competition of those 3 factors.

Okay. Any -- on the Permian, I know you drill wells and everything.

Is there any variation from your type curve, good or bad or indifferent, what you've seen so far?

No, Jack, the production continues to be on type curve from our 3 acquisitions. And we're very satisfied with the oil content being in the 80% range.

And from that standpoint, the reservoir is performing.

You highlighted some of the constraints in the Permian and those are definitely industry constraints. I just wondered whether you're satisfied with the size of your acreage position here and whether you think you have the scale to execute as you did, arguably in the second quarter from a productions perspective and also from a cost prospective.

Well, obviously we'd like to have more in the Permian. We like it, even though it's an extremely competitive place to do business.

We have added a pretty sizable position outside the Wolfberry fairway in Borden County. We have a number of plate concepts there we're evaluating from commingle Wolfcamp and Strawn to horizontal Cline and horizontal Mississippian.

So we drilled 2 appraisal wells, looking at log, looking at core, really have done no completion to date. Our goal is to have somewhat of an appraisal, an economic appraisal completed there by year end.

And that, if that's successful, that in fact just about doubles our position of develop -- our acreage that we'd like to develop in the Permian. So --

And since year end, Brian, we've added about 30,000 net acres in the Permian and elsewhere in the portfolio. So we've added about a little over 15,000 net acres in the Permian since year-end.

So we continue to add in the Borden area, as well as our -- in and around our acquisition areas.

Okay. And then shifting back to the Rockies.

With the increased drilling and doubling the lateral length that you're planning, can you just update us on how you're thinking about where you're Black Wax, Yellow Wax production can get to, and then how you're thinking about downstream strategies there?

Well, let me talk about the downstream first. We still have our contract with Holly, which goes through July 1 of next year.

We're certainly doing everything to honor that contract. But we're very interested in seeing if we can get paid more money for our barrels.

And that means we have to look at alternatives with Holly, alternatives with other Salt Lake City refiners. And you've heard me say to a lot of people, I think eventually barrels leave Salt Lake City and go to other markets.

That could be California that could be Anacortes that could be Louisiana, Gulf Coast. And those are going to be rail options, and I think a lot of those things are under evaluation, not only by Berry but by other companies.

So I think when you look at those opportunities, you could see a way to get paid more for your crude. Our goal in the Uinta is to improve our margin there, which is about $35 a barrel.

And we want to improve our margin by getting paid more for our crude and by exploiting the Wasatch, which generally, or at least regionally, has a much higher oil content than our historic oil and gas ratio at Brundage Canyon. I think -- we probably think we have scale, plenty of scale in the Uinta.

My guess is, when we're doing a long-range plan now. It's probably going to be a 12,000 to 15,000-barrel a day basin, probably even if we have success in both the Uteland butte and the Wasatch, it probably goes higher.

I think our risk forecast does a pretty conservative job at looking at the potential of both those.

And of the potential options on the downstream side you were discussing, is there's anything that you are kind of close to? Or is this -- are these just items that you feel that you and others are evaluating more for the medium term?

Well, if we were close, we would tell you. And since we don't have anything in hand, we can't -- there's nothing we can really say.

But I would say a number of producers that are looking at evaluating opportunities that are beyond just trying to cobble up cost numbers on a piece of paper. I mean, there's some real outlook going on here and some real discussions going on.

In the Permian, I just wanted to check in and see what your current thoughts are on horizontal drilling and when you're planning to test that?

Well, we're currently evaluating several of the areas. We're pretty widespread in the basin.

We're probably 250 miles from north to south and almost 100 miles east to west. So we're looking at each one of the shale opportunities and horizontal opportunities.

And we continue to drill our vertical wells and test each one of the formations. And we'll be high grading what we think the best opportunities for horizontal.

I would say, we don't have any plans for horizontal well in 2012, but I would imagine we'll have one -- we'll have a group of wells to propose for 2013.

Okay, great. And then just looking at the cost side.

Your op costs for this quarter, they were just a little bit below the top end of your full year guidance, but they were up quite a bit on the first quarter. I was wondering, if there was anything sort of onetime that was happening this quarter, and how you guys expect them to play out, kind of for the rest of the year?

That's a good question. We did have to book $2 million into operating expense, associated with compression gathering and dehy that was related to underpaid -- the dispute as it related to underpaid royalty payments.

So the quarter is a little bit toppy on the operating cost side as we also had to put about $900,000 into interest expense associated with the that dispute. So that's a little -- that impacts interest as well in the quarter.

Okay, got it. And then can you guys just give a little color about how your new sort of California plays are doing, look like the production is pretty good this quarter?

Well, we have a number of smaller fields in and around our north midway operating area. These are kind of small opportunities.

They've been at this point in the development cycle because they tend to be a higher viscosity oil, which takes longer to heat up, and are not quite as efficient. But when you look at the margins that we get in California today, and you look at the oil-gas price ratio that we enjoy today, we decided kind of late last year, we got to develop these properties.

And so we're starting to see some response in some of those properties, and we expect that we actually expect that response to get better. And so, it's not a huge position for the company, but it's a nice little wedge over the next 3 to 4 years as these things start to come on.

Bob, I was just curious, if you can help us think through all the things that you're looking at, just at the CapEx for next year, what the timing of that would be, and how that would relate to your cash flows?

We, it's usually, Monroe, that -- it's usually a third quarter activity for us, we're right in the middle of it. I think it's a little bit premature for us to make the call.

I'd think our capital planning right now probably indicates we'll be a little bit lower on capital, but we're still shooting to deliver that 12% to 14% of oil growth. Obviously that really depends on Diatomite performance, if we continue to go up the type curve we're on now, we'll feel really good about that.

So if we get the response in the Diatomite, we won't have to spend as much capital on the Permian. That's probably what it will amount to.

We'll look at that against several price scenarios. Probably our working assumption will be something like $90.

And we'll probably run another case at $70, and we'll check the cash flows against those prices. We will set our goal on CapEx to be very much in line with our cash flows for next year.

Okay. And how should we think about your gas production for next year?

Do you think...

We'll be gas-short next year. We typically look at our consumption for our heavy oil properties against our production.

I think we'll be about 70% of our consumption will come -- I mean 70% of our gas needs will come from our production. We are starting to hedge the buy, on the gas.

And I would say, company-wide, if you look at our associated gas and our gas assets, next year on gas, we'll be something about 80 million a day, something like that, or is that right?

Well that seems high. That includes the...

So we'll be in the 40 million to 50 million a day range next year.

Well, let us come back to you on that, Monroe, on the gas forecast. That'll kind of be part of the outlook for next year as well.

Okay. Just one other question.

Are you seeing much or any help at all from lower service costs at this point in time in any -- in the areas you're operating in? And kind of what's your outlook for service costs for next year?

Well, when we look across the operations, California has been relatively steady from a cost standpoint. Only materials come up -- from a commodity standpoint have increased.

In the Uinta, we have -- we're not seeing any reduction in cost yet. Activity continues to be relatively high.

And margins there are good, and so I don't expect to see dramatic decreases in cost or in materials there. In the Permian, we're starting to see the first indications of reduced rig costs, so we've had a couple of opportunities to contract rigs that are a little bit lower priced than what we're currently at, but we're not seeing that in our completions at this point.

The completion market continues to be very tight in the Permian, and we're continuing to forecast that going forward.

Just wanted to ask on the Ashley Forest stuff, that obviously with the acreage position there, what are your thoughts, as far as the rest of this year? How many wells you might be able to get in there and maybe even looking into '13, what you're expecting?

Now, are you referring just to Ashley Forest or the Lake Canyon and Ashley Forest?

Just Ashley Forest. I was wondering how many you might be able to get there with that acreage position this year?

I think what we have planned right now is of the 60 wells that we're going to drill during the remainder of the year, I think a little less than half of those are going to be focused in the Ashley Forest. We -- we're in the permitting process right now.

We just received the EIS. We had a number of categorical exclusion permits remaining from last year.

But I would say we'll be in the 20 to 30 well range for the remainder of the year.

Great. And maybe sticking on permits, but over in California, are you still seeing things kind of improving slowly, as you're working with the new regime, as far as getting permits and being able to kind of work a little more freely?

Absolutely, it's night and day difference -- different than it was just a few months ago. Our mantra for the present is that the regulatory environment is not a limiting step for us in California.

So that feels good. We still have to dig out some from the impacts of the old approvals, and we're doing that.

But the current relationship is very good. Current approvals are coming as requested and promised.

So those types of things are getting turned around pretty promptly now.

Just one quick question for me. Could you guys just give as an update, I guess, on your current rig count by basin?

Yes, we currently have 3 rigs drilling in California, and that -- we've been pretty flat for the majority of the year. We did have a fourth rig early on in the year while -- as we finished the Diatomite drilling.

In the Uinta, we've increased to 4 rigs, and we plan to drill with 4 for the remainder of the year. And in the Permian, we're at 6 rigs right now.

We plan to continue that pace going forward.

Great. And then just as I think about your capital program, based on kind of the rig count allocation, here in your plans from a drilling perspective, should we continue to expect kind of the same run rate on CapEx for the next 2 quarters as what we've seen in the second quarter here?

Well, we've got to continue to monitor that. Our guidance has been 600 to 650.

I think given some of the pressures we have experienced in the Permian because it's so competitive, we're in the top half of that range. We're going to work hard to stay within the range.

Perfect. And then, just a last question for me.

Given the additional line pressures you guys are seeing, is there any chance you could give us a rough update on kind of where current Permian production is? Or maybe where it was in July?

I'd say if -- our mid-year production in the Permian is essentially 7,000 barrels a day.

Just a follow-up on the CapEx. Does the 600 to 650, does that include leasehold acquisitions?

No, it does not.

Can you comment on how much you've spent on leasehold to date and sort of what your expectations are for the remainder of the year?

Yes, year-to-date, we spent about $25 million on acquisitions, made a small acquisition, about 2,000 acres in Southeast Midland, which is about half of that allocation. We -- as we said prior, we picked up about 15,000 net acres in and around Borden County.

So year-to-date, it's about $25 million and 30,000 net acres, none of which are producing assets. Expectations for the balance of the year, we're very much adhering, given the macros and just the competitive aspects to our bolt-on strategy.

So we think these are $25 million to $50 million type opportunities on the high-end, and doing an awful lot in the $5 million to $10 million range in terms of where we're spending time evaluating deals.

Well, I just thank everybody for your attention on the call today, and we look forward to speaking with you over the next quarter. Thank you.