Welcome to the Third Quarter 2009 Berry Petroleum Company Earnings conference call. (Operator Instructions). I would now like to turn the conference over to your host for today, Mr. Robert Heinemann, President and CEO. Robert F. Heinemann: Let me welcome you to our third quarter earnings call and remind you that we will be conducting the call under Safe Harbor provisions. Michael Duginski our Chief Operating Officer and David Wolf our Chief Financial Officer are with me today and will make operational financial comments after my opening remarks. Berry Petroleum posted its Q3 results for 2009 today. The company reported net income of $19 million or $0.41 a share, compared to net income of $53 million or $1.16 per share in the third quarter of 2008. These results include several non-recurring items affecting net income and include a non-cash gain on hedges, write-off of financing costs associated with our credit facility, a net gain on asset sales and the sale of inventory volumes of heavy oil produced in the second quarter. The total impact of these items in the quarter was an increase of about $3.3 million. This brings the adjusted net income for Q3 to $15.7 million or $0.34 a share. Production for the quarter was 28,420 barrels of oil a day, down 3% from our Q2 2009 production of 29,270. The production mix for the quarter remains 68% oil and 32% natural gas. Capital spending for the quarter was $22 million reflecting our capital discipline, especially with regard to gas. This level investment coupled with our continuing focus on operating costs and G&A expense produced strong cash flows in the quarter. Discretionary cash flow for Q3 totaled $60 million or $1.29 per share. This cash flow result coupled with the completion of our East Texas midstream sale allowed us to repay $78 million of debt in the quarter. We expect to increase both capital spending and production in the fourth quarter and are remaining our production guidance of 30,000 barrels a day for full year 2009. Mike will be providing you some additional operating details in a moment. Of course, at this time of the year we like other companies are in the process of developing our 2010 capital program. While we do not yet have board approval, we expect capital investment to be in the range of $220 million to $260 million, which should return Berry to growth. Major focus will continue to be on crude assets and 65% of the capital will be allocated oil projects, including the diatomite and Ethel D developments, initiation of the steam flood on McKittrick 21Z and additional drilling in Brundage Canyon. We would expect production to increase by about 5% at this level of investment with good quarterly increases throughout next year. Let me now turn the floor over to David Wolf, who will provide details on our financial performance for the quarter. David D. Wolf: Our third quarter 2009 oil and gas revenues from continuing operations totaled $127.5 million. Our oil prices per barrel after hedging for continuing operations averaged $57.97 per barrel. Our gas sales price after hedging was $3.48 per Mcfe. This gave us an average price after hedging of $46.39 per BOE. Operating cash flow from continuing operations was $89.2 million. Our capital expenditures for the third quarter totaled $22 million. We expect approximately $38 million of expenditures for the remainder of the year with a total target 2009 budget of $132 million. Let me walk through our cost metrics for the quarter. Oil and gas operating costs were $39 million at $14.99 per BOE. Adjusting for the sale of inventory barrels at Poso, however, operating costs have been about $0.50 less or $14.52 per BOE. Production taxes were $1.48 per BOE. Our DD&A was $12.81 per BOE. G&A was $4.09 per BOE. Interest was $5.57 per BOE. Total costs were $102 million or $38.94 per BOE. Again, adjusting for the sale of inventory barrels at Poso, operating costs would have been $0.50 per BOE less or $38.50 per BOE. We have issued some updated 2009 guidance ranges which will be in our 10-Q. The only item that has changed since the second quarter is the DD&A rate range has come down $0.25 per BOE. The following is our anticipated range of full year costs. Operating costs oil and gas production $13 to $15 per BOE. Production taxes $1.50 to $2.50 per BOE. DD&A oil and gas $12.50 to $13.50 per BOE, G&A $4.25 to $4.75 per BOE. And interest, $4.00 to $4.75 per BOE for a total cost of $35.25 per BOE to $40.50 per BOE. Year-to-date through three quarters, we are at $37.80 per BOE, which is at the midpoint of our guidance. As Bob mentioned, this quarter the company paid down $78 million of debt under the revolver. Approximately $18 million is from the sale of our Texas midstream assets and $60 million from excess cash flow. As of September 30, 2009, we have $382 million drawn and approximately $556 million of availability under our bank line. Our borrowing base today is $938 million. A weighted average cost of all of our debt as instruments is 7%. With that, I will turn it over to Michael Duginski to walk through an operational review.

We continue to focus operations on driving costs out of our business while maximizing production from our $132 million capital budget. As Bob said, company production averaged 28,420 BOE per day for the quarter down 3% from the second quarter, as expected with our reduced capital budget. Production has begun to recover from its low and we're on track to average 30,000 barrels for the year and expect to exit the year at about that rate. We are focusing our capital budget on the highest rate of return projects, which are currently our oil projects. We drilled 32 wells company-wide during the quarter with a two rig program, 30 wells in California and two wells in East Texas. We are realizing additional cost reductions in each operating area with operating costs down 30% from the third quarter of 2008. We're on track to realize 20% to 25% oil and gas production operating cost reductions for the year compared to 2008. Steam costs are down 52% for the quarter versus the third quarter of '08 and are projected to be down 46% for the year as a function of California natural gas prices dropping from $7.92 per an MMBtu to a projected $3.60 per MMBtu. This is a decrease of over $43 million year-over-year. California heavy oil differential averaged $8.35 per barrel in the third quarter and is currently at $8.28 per barrel. California differentials are maintaining at levels well below 2008 average of $13.24 and well below historical averages. With WTI prices in the $80 per barrel range and Southern California border prices at about $4.00 per MMBtu, we have an 18 to 1 oil to gas price ratio and is developing very strong margins for California at $35 to $40 per BOE. In California, our diatomite development production increased to 31,120 BOE per day, a 50% increase from the same quarter of 2008 and a 7% increase from the second quarter. We've allocated the largest portion of our capital budget to the diatomite development and drilled an additional six wells in the quarter for a total of 51 wells drilled year-to-date and are moving our steam injection up to approximately 30,000 barrels of steam per day. We're on track to exit the year at our target of 3,500 BOE per day, which will be a 60% increase year-over-year. At South Midway Sunset, we've drilled 14 deeper horizontal wells in 2009 and production has remained relatively flat for the year as these new horizontal wells begin to respond from steam injection offsetting the natural decline of the field. In East Texas, production averaged 23.2 million barrels – I'm sorry, 23.2 million a day as a function of a one rig drilling program. We have moved the rig to Harrison County and are currently spudding our second vertical well. After we TD this well, we plan to spud our first horizontal Haynesville well. In the Rockies, production has declined in both Piceance and Uinta by 15% to 20% for the full year with no drilling activity as we had planned for. In the Piceance, to partially offset these declines we have completed 18 wells of our 23 well inventory utilizing high volume low density completions. Results have been strong with IPs increasing 25% as expected, and increasing our production over the quarter starting in October. These IPs should translate into higher ultimate recoveries and we would expect individual well recoveries to increase to 1.75 Bcf per well. Combine that with current drilling and completion costs of $1.5 million to $1.7 million and we would expect incremental F&D to be below $1 per Mcf. We plan to complete four of the five remaining to be completed this year and we have an additional 21 wells to re-complete in the upper section utilizing this new completion technique. In the Uinta we have initiated our four pattern waterflood pilot in the Brundage Canyon field, and we will be monitoring this pilot during 2010 for response. Those are my comments, Bob. Robert F. Heinemann: In summary, let me say we continue to execute our 2009 strategy. Our operating costs have come down significantly. Our capital investment is efficient and is moving up in the fourth quarter, it's concentrated toward crude oil development. We remain focused on cash flow generation, debt reduction, and delivering strong margins. EBITDA margins in the third quarter were in the $29 per BOE range, which we believe will be very competitive in this environment. So with that, we will open the floor to questions.

(Operator Instructions) Your first question comes from Michael Jacobs – Tudor, Pickering & Company.

Just wondering if we can clarify the 5% production growth number. Is that kind of on a same-store sales basis or is that including the DJ production for the first quarter of '09?

That does not include the DJ.

Just ticking through the regional items, obviously limited CapEx spending this year and focus on the heavy oil projects. But when I look at the 7.5% sequential decline in the Uinta, how should I think about kind of 2010 versus 2009 growth in the Uinta, any sort of guidance on that would be great. Robert F. Heinemann: I think what is going on there is we're seeing better prospects at Brundage Canyon, our drilling costs have come down, as you would expect. We have category exemptions to start drilling in the forest so we have a bigger portfolio of opportunities. I think just without having a table of numbers in front of us, I would think we would keep you went to flat to maybe slightly up next year. It's just going to be a matter of what time we start to put the money to work, obviously earlier the better. And we may get in a situation where we run a rig full year there and then bring a second rig in for the summer months when we can drill some of the more difficult locations.

How much spending do you think you would need to just keep Uinta flat and maybe, I guess just on the Uinta? Robert F. Heinemann: Mike, we really haven't pinned it down on Uinta, but we're going to say about $30 million, that would be my guess off the top of my head.

One more if I can move to East Texas. Other operators have talked about the Pettit opportunity, I think you guys, its one of the intervals that you originally identified. Have you identified any Pettit oil opportunities in East Texas and is that something that you guys might consider going after? Robert F. Heinemann: Mike, we have not identified any Pettit oil opportunities in our section. From our logging and from our shows we would say that our Pettit is more than likely 100% gas. At this point, we don't believe we're in the oil trend.

Your next question comes from David Tameron – Wells Fargo.

Bob, if I think about it, I'm going back to this 5% number. If I just take it coming off of we'll call it base of 30,000 a day, that's 1,500 barrels. Doesn't almost the diatomite alone get you to that number? And realizing that Midway Sunset may be in decline, I don't know we've been talking about that for five years. But I understand that 5% looks a little conservative to me if you figure you said you went to flat to up. Piceance, it sounds like you've going to ramp activity there. In East Texas you got the diatomite and you've got some McKittrick properties. Do you care to comment on that? Robert F. Heinemann: Well, I think 5% is an average, it's a range. Obviously if we are going to go out at 3,500 in the diatomite and then go out next year at 5,000 it's going to go up about 1,500. South Midway is having some decline. Over time we'll be more than offsetting that decline with the Ethel D redevelopment. I think when you look at the declines and look at the ads on an annual average it's going to be 5%, 6%. Hopefully we see some more increases as we go through the year. David, let me also just thinking on the fly here if the diatomite on an annual average might not be 1,500, it might be a little bit less than that depending on how it ramps up over the course of the year.

In your underlying portfolio when you guys I guess aggressively cut CapEx starting late last year. Have the declines kind of flattened out your base production after the initial – let me step back. I assume you cut CapEx fourth quarter. It took six months of so before you saw the big declines. Robert F. Heinemann: Absolutely.

And has that started to flatten out now? Robert F. Heinemann: Absolutely, in fact you're going to see production come back up in the fourth quarter. We knew the third quarter was going to be the low point in the cycle. We spent about $20 million, $22 million in the third quarter and we talked all year about putting some more money back to work and we'll probably do about $35 million to $40 million now in the fourth quarter of this year.

Acquisitions, I know you guys have been wanting to do another McKittrick. Any progress there or can you give us an update? Robert F. Heinemann: Well, if we had one to announce we'd announce it. While we certainly have a number of opportunities across the company that we have under evaluation, but until you get them in the basket you can't count the fish. But certainly we are seeing assets in the market. We do see oil assets in the market, some of which are attractive to us, some of which are not attractive to us. But overall I think our strategy of rolling in five to six Poso Creeks over the next period of time, call it 12 to 18 months, we still think that is a viable strategy to keep our California inventory where we want it in the near-term.

One final question, you've been vocal about or you've given your opinion on LNG and what you think will happen in the next couple years. Any change on, correct me if I'm wrong, but you thought LNG was going to show up in the U.S. in 2010 or 2011. Can you tell us then what your current thinking is? Robert F. Heinemann: To be honest, Dave, I don't have a lot of new thoughts there, although the one project that we see that is of interest to us is there certainly appears to be a contract to bring [stock] in LNG from Russia to Baja and that gas would then supply San Diego Power & Light. We kind of like that prospect of bringing low cost gas and LNG to Southern California. It can only help our oil/gas price ratio and our heavy oil projects. Globally, I think a lot of people have been on both sides of the LNG forecast for '09. We saw some big numbers forecasted earlier in the year only to see them probably not be as aggressive as a lot of people thought. Certainly, I think the macro driver that LNG developments that can still produce condensate in a high price environment are going to continue to produce, and that gas is going to find a home and the U.S. will eventually be a home for some of that gas.

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

On the cost side, I was kind of surprised on a unit basis in the jump in LOE, can you kind of address that a little bit and wondering if it related to the expanded margin on the electricity sales if that kind of relates to it. David D. Wolf: We had 4% higher fuel costs associated with natural gas prices and additional 9% was a function of fuel costs volumes – fuel gas volumes rather. So that comprises most of the increase, Phil.

Is the trend in your electricity sales, it seems like your margins are expanding as compared to your costs? Is that something we should be starting to look at as far as 2010 or is this kind of an aberration for the quarter? David D. Wolf: I think it's more a function of the low gas price, but that's not something that we're expecting to expand.

You mentioned in the fourth quarter you'll spend about 35 to 40 holding things kind of constant where oil prices are. Looks like you're going to have excess cash flow for the fourth quarter. Are you still looking at further reducing the bank line? David D. Wolf: Well we also have in November/December our semiannual payments for our bond notes, so that's roughly $31 million. So we would expect the fourth quarter to be flat on debt repayment to down slightly, but nothing to the extent of what we've seen in the third quarter.

You talked about Brundage Canyon, can you give us an update on the environmental impacts study and it is still kind of delayed due to the new administration and stuff like that?

Phil, as we indicated earlier we're starting to see some delays in some of the government agencies with the new administration in. I think what we've done is we've been able to confirm that there is a delay in the EIS and we won't expect that probably until mid-year next year is what we're kind of hearing right now. But what I'll tell you is it really doesn't make any consequence to the company because we have 25 category exemptions right now and that's more permits than we were planning on drilling in Ashley Forest next year anyway. So it actually gives about a two-year inventory on drilling. So we're in good shape regardless. But, yes, I would say as other operators have mentioned, with the new administration we see a real delay in some of the government agencies.

Michael, did you say you had 25 permits on hand?

We have 25 category exemptions in which we're permitting. So we're in good shape.

Does this CapEx budget for 2010 anticipate one or two rigs being added into the Piceance at all? David D. Wolf: Right now we're forecasting with the current strip and as I mentioned in my comments, we've got our drilling costs down into a range, depending on depth, of between $1.5 million and $1.7 million per well. With the 25% increase in EURs, you can see that our F&D is more than likely going to be below $1 in Mcf. And our target was to have $1 F&D, $1 operating costs and then roughly a $1 differential to the market that we're selling in, and we're accomplishing that right now. And when we look at next year's strip at about $6, you can see that works our pretty well for us. So you can more than likely see us put one rig back to work in the Piceance.

Given where the strip's at, you guys are a little bit light on your natural gas hedges for next year. Should we anticipate you starting to add a little bit more or is there something in the K or the Q that we're going to see? David D. Wolf: Before we do more gas hedging we wanted to see a little bit of recovery in the strip. We've seen that. There's a good chance we'll do some more gas hedging, but again, it will not have a real huge impact on our cash flow. It's, again, because of our gas consumption and our growing steam volumes as we expand in our heavy oil projects in California. But I think, as Michael says, we can do the one plus one plus one plus model in the Piceance, lock in the top line, lock in the returns that's a good strategy for us.

Your next question comes from Andre Benjamin – Goldman Sachs.

I was wondering, you indicated that you're looking at the current strip I'm assuming and doing most of your forecasting. Is there a range that we should look to see in the ratio between oil and gas that might alter your growth or acquisition plan? Robert F. Heinemann: Even if you look out several years, you still see that ratio greater than 12 to 1, a lot of years still 13 to 1. All of our projects will generate exceptional returns at that ratio. So actually it's that long-term look at the ratio which makes us think about a different set of opportunities in California than perhaps operators have pursued in the past. So even if our SOR is higher than 6, the traditional threshold, we can still generate really good returns at that oil price ratio.

You indicated how much growth you're expecting from the diatomite, but could you just give a little more color on how much you might actually be expecting from some of the other projects you highlighted in your press release such as McKittrick, we know Ethel D's supposed to start to plug the gap, but just thinking about how that should progress through 2010 quarterly maybe and where you plan to exit? David D. Wolf: Andre, I don't know that we have a quarterly forecast here to give today, but what I can tell you is so if you take an increased exit rate at the diatomite from 3,500 to 5,000 that would be an annual average increase of about 750 barrels. You would anticipate, like we've said, that Ethel D will be focusing on that development. We should see an increase there. That should more than offset any decline at our home base properties in South Midway. We'll have an increase in our Poso Creek volumes as we put in our new water plant, we should see an incremental 2 or 300 barrels there. The 21Z pilot will be exactly that. It'll be just a four pattern pilot and will not have a real material effect on production. We'll be drilling with a one-rig program in the Haynesville horizontal program, which would be a continuous drilling program. So you would see us increase our East Texas natural gas volumes for the year, Piceance one-rig program should offset the decline there and we should see slight growth year-on-year in the Piceance. Remember we were coming from a relatively high number in the Piceance for the fourth quarter 2008 and we've been on a pretty steady decline. So that should be relatively flat. And then Unita would be similar where we were on decline and we will be reversing that decline. So annual average you probably won't see a material change in those volumes in the Unita.

Your next question comes from Chris Pikul – Morgan, Keegan.

Bob, just to clarify. I think we sort of danced around it. When you're talking 5% and you said you exclude the DJ properties, are we talking an average of about 31.5 in 2010? Is that what we're saying? Robert F. Heinemann: Yes, I think at this stage during the process that's about where we are.

As far as the 220 to 260, can you just tell us how you're thinking about that internally? Is it price related is it Haynesville success dependent or what are some of the variables that bring you to the high or low end of that range? David D. Wolf: Chris, that's right, just like in 2009 we have a price dependent capital budget. So if we see moderate prices and we see maybe a little dip in crude oil, you'll see us spend at a portion of the range. We stronger than $75 next year, you'd going to probably see us spend towards the high end of the range. It's not Haynesville success dependent. We're very confident of what the Haynesville potential is based on the offset operators that we have.

So current prices would kind of suggest a higher budget. David D. Wolf: That's right, and again, if you saw real gas weakness next year, depending on winter demand, you may see us pare back similar to what we did in 2008-2009.

Just to touch on the East Texas, I believe you said you were producing 23 million a day out of there?

That's correct.

Now I know at the time of acquisition it was 32, we all know there's been lower gas prices. Is that a function decreased activity? Is that all still going according to your model there?

Yes, everything's going according to plan. Remember, in 2008 in the second and third quarter, we were drilling with a five-rig program, and in the fourth quarter we went down to one rig. So these are expediential declines. Or I should say hyperbolic declines and one rig really didn't offset that peak that we saw in the fourth quarter. So it's really activity based. The Bossier is performing near or just slightly below our model. We did have two very good wells come on in the fourth quarter, one at 3.5 million a day and one at 3 million a day. So we're relatively happy with that, and our uphole re-completion opportunities, we're doing a lot of the science on that now and we should start venturing into to the upper sands in the Oakes field in the second or third quarter of next year.

Could you just kind of remind us what you're doing out there in the Piceance as far as those sort of enhanced completion techniques?

Yes, basically what we say when mention a high volume low density frac, we're tripling the volume of water that we're injecting into the well and keeping the sand or the proppant volume at about the same level. What we're seeing is much higher shut-in pressures when we complete the job. We're seeing much higher IPs, and we're seeing a slightly flatter decline. So we're very happy with the results and we think we've got a very concrete completion program going forward for the remaining wells that we have in the Piceance.

If I recall, 25% improvement in the IP rate that was even perhaps better than you guys had suggested, or is that what you expected?

No, actually, you're correct. We projected a lower increase because we felt we had already modified our completion technique. We felt like we were very near the top quartile of completions. We had slick water completions very early on in our program. So we had a range of between 10% and 20%, so 25% improvement really does exceed what our forecast was.

One more bookkeeping question, I noticed deferred tax was perhaps a higher percentage this quarter. How should we be thinking about that going forward, or cash tax, whatever? David D. Wolf: Chris, it really was an impact of some of the state deferrals that we think will be reversed next quarter. So I think I'd focus more on the annual.

So it will be deferred a good deal. David D. Wolf: Yes, I'd focus on what we've kind of done year-to-date versus the quarter and the year-to-date trend should continue.

Your next question comes from Jack Aydin – Keybanc Capital Markets.

When you look at the 5% growth, is that based on $220 million spending or $260 million spending. Is it activity based or dollar amount based? David D. Wolf: It's some of both. It's some of all of it, as you well know. I would say we're saying about 5% and that would lead me to say that's about at the midpoint, and depending on where things end up, top of the range, bottom of the range, will move that number around a little bit.

Your next question comes from Mike Jacobs – Tudor, Pickering & Company

Just a follow-up, Bob and David, when I think about your comments on kind of midpoint spending $240 million, about a third of that is non-California spending and you mentioned that maybe $30 million could go to Uinta. Just kind of think about your portfolio of opportunities and of drilling two vertical wells in the Piceance and looking at the rate there, can you talk about your options with the additional $50 million that would go to Piceance and East Texas and what you do there in 2010 to kind of grow that asset base? Robert F. Heinemann: Well, I think just to maybe recap what we said, we said about 65% of the budget goes to oil. That does include Uinta in that two-thirds. Optionality for us will depend on running more rigs either in East Texas or in the Piceance. I think at this stage we'd have to say we'd like to see some more fundamentals in natural gas improve before we went to bigger rig utilization there. We are starting to develop another generation of heavy oil projects, including McKittrick 21Z, but it takes a while to ramp heavy oil projects. It's not primary production, so you've got to not only drill wells but set infrastructure and preheat the reservoir to start to get response. So we think this budget also is a pretty big increase in our activity. We're probably going to end up spending about $130 million to $135 million this year and to go back into the $220 million to $260 million range will be a big step up for us.

Just maybe if I can focus on just kind of major on the minor, in East Texas specifically, and I know you haven't finalized the budget yet, but kind of your activity with drilling two vertical wells this year, what do you think you have to do from an activity standpoint to keep production flat in East Texas? David D. Wolf: Mike, let me just clarify. We had a one-rig program drilling in East Texas which was three wells per quarter. We had two wells completed in the third quarter and those were the wells that we had very favorable result on. Our 2010 budget is a continuous drilling program of Haynesville wells, so you'll see us probably drilling complete six wells next year, roughly six wells. And that should increase our production year-on-year with the Haynesville projected results that we think we're going to have.

Your next question comes from Evan Templeton – Jefferies.

I was wonder if you could help me out with just looking at capitalized interest. Notice that it's kind of been ticking up over the last couple of quarters. Can you just kind of let us know where that should be headed and really kind of what that's being allocated towards? David D. Wolf: The interest expense went up as a function of having more debt from the prior year. So we would expect to be in the $28 million to $33 million range of capitalized interest for the year. That help answer your question, Evan?

Yes, and just exactly way capitalizing that amount, [call it] $30 million a year as opposed to just directly expensing? David D. Wolf: Evan, we'll chat and follow up with you and I can give the particulars on the capitalized interest. But clearly, with refinancing our bank debt at, call it 2%, 3% with higher coupon on our bonds in the 10.25 range and also 8.25 that amount that we've capitalized has increased.

Your next question comes from David Tameron – Wells Fargo Securities.

Just one follow up, any update on Flying J? I haven't had a chance to look at the Q yet. David D. Wolf: There's not an update relative to the second quarter. As we understand, the pilot transaction continues to move forward. That clearly will be a very positive outcome for the estate and for all the creditors as was originally announced in the press release by Flying J and Pilot that they would expect all creditors to be paid in full. We obviously feel pretty good, David, as we've talked about in the past about our claim, given our parent guarantee to the top of that organization. But there's really not a timing update. It's clearly not a 2009 event. But we're kind of thinking sometime hopefully before the midpoint of the year there'll be either a reorganization plan or the consummation of that merger.

So the event we're kind of looking for is just one of those two events, the last thing reorganization or? David D. wolf: I think there's a couple of things and the most important hurdle is Hart-Scott-Rodino, HSR, given the overlap of the portfolios. Once that hurdle is overcome, which I'm guessing is probably by the end of the year then it really comes down to simultaneously tracking the reorganization plan. But once that happens, I think things will move quickly, but that's really the major gating on it.

Your next question comes from Gregg Boddy – JP Morgan.

Just checking in on the California production tax situation. I started to hear rumblings again about that, I'm just curious what your view is and what you know about what's going on in the assembly.

Well, we're going to continue to hear rumblings about California severance tax. With term limits in the state of California and every new assembly member that joins believes that because California doesn't have a severance tax, that the oil industry doesn't pay its fair share. There's an ad-valorem tax in California, and we pay just above the midpoint of all the states if you were to convert that into a severance tax. And it usually takes someone to introduce or propose a severance tax for them to become educated on that point. And that will be a continuing issue in the state of California when either legislators or others see that California doesn't pay an oil severance tax. So, again, I think this last noise that we heard a few weeks ago, my understanding is it has already been pretty well dismissed with just a little bit of education. Robert F. Heinemann: I think, just as Michael said, the latest proponent for the severance tax had no awareness of the ad-valorem tax.

(Operator Instructions) Robert F. Heinemann: Okay, seeing no other questions we thank you for your interest in Berry. We look forward to our next quarter and we look forward to seeing several of you over the next quarter on the road.

That concludes our presentation. Thank you for your participation. You may now disconnect. Have a great day.