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Executives

Mike Edwards – VP, IR

Tim Marquez – Chairman and CEO

Tim Ficker – CFO

Gale Wright – Reserves Manager

Bill Schneider – President

Analysts

Mike Scialla – Thomas Weisel Partners

Steve Berman – Pritchard Capital Partners

Sven Del Pozzo – C.K. Cooper

Jeff Robertson – Barclays Capital

Joe Allman – JP Morgan

Anish Patel – Credit Suisse

Venoco, Inc. (VQ) Q3 2009 Earnings Call Transcript November 3, 2009 11:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the third quarter 2009 Venoco Inc. earnings conference call. My name is Latitia and I will be your operator 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 call over to your host for today, Mr. Mike Edwards, Vice President. Please proceed sir.

Mike Edwards

Good morning everyone, Venoco issued a press release today on our third quarter 2009 results. We also filed our Form 10-K with the SEC. On the call today to discuss the results we have Venoco's Chairman and CEO, Tim Marquez; CFO, Tim Ficker, and other members of the Venoco management team.

Before we get underway, allow me to make a couple of comments regarding forward-looking statements. All statements made in this conference call, other than statements of historical facts, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are subject to a wide range of business risks and uncertainties including adverse developments in financial markets and general economic conditions.

Any number of factors could cause actual results to differ materially from those presented in the forward-looking statements, including but not limited to the timing and extent of changes in oil and gas prices, the timing and results of drilling activity, the possibility of delays in completing production, treatment and transportation facilities, difficulty obtaining third-party services including transportation, and higher-than-expected production costs and other expenses.

The SEC permits oil and gas companies to disclose in their filings with the SEC only proved reserves, which are reserve estimates about geological and engineering data, demonstrated with a reasonable certainty to be recoverable in future years from known reservoirs through existing economic and operating conditions. Estimates of unproved or 2P reserves, which may potentially be recoverable through additional drilling or recovery techniques are by their nature more uncertain than estimates of proved reserves, and accordingly are subject to substantially greater risk of not actually being realized by the company.

Forward-looking statements made about the Hastings Complex and the contract with Danbury Resources are subject to business risks and uncertainties not in Venoco's control, including but not limited to the implementation of the CO2 flood, and the production results and reserves if the flood is implemented. All forward-looking statements are made only as of the date hereof, and the company undertakes no obligation to update any such statement. Further information on the risks and uncertainties relating to the forward-looking statements are set forth in our filings with the Securities and Exchange Commission, including under the heading Risk Factors in our Annual Report on Form 10-K for the year-ended December 31, 2008. The earnings release and the relevant non-GAAP reconciliations are available on the Investor Relations page of the Venoco Web site, which is venocoinc.com.

Now, let me introduce Venoco's Chairman and CEO, Tim Marquez.

Tim Marquez

Thanks Mike, as always a stunning introduction there. I would like to welcome everybody who have called in today and are looking to the webcast. God be here today to discuss our solid third quarter results.

Production, as we anticipated, has been very steady and adds to the positive results that we recorded for the first half of 2009. Our focus given in the third quarter was on consistent operation, in other words, maintaining production levels to keep the expenses in check. We started the quarter with about little less than 3 million cubic feet of new production from the acquisition of Aspen Exploration & Partners, which offset most of the production we launched this quarter due to our scheduled downtime in South Ellwood.

As for production this quarter, our plan for 2009 has always been to spend more heavily in the first half of the year. This year we scaled back capital expenditures in the third quarter and anticipate the same kind of trend in the fourth quarter. We are pleased to see production performance expected and stay flat with the second quarter at 1.86 million barrels of oil equivalent. Because of the extra day in the third quarter, our daily average is down slightly to 20,264 BOE per day. For the first nine months, we are averaging 20,803 BOE per day. (inaudible) the anticipated downtime like having the big ASP go down offshore, we expect fourth quarter production to be similar to the third quarter, which result in us exceeding the revised annual production guidance by a percent or two. Compared to the first nine months of 2008, pro forma for the sale of Hastings, production is up 9%.

With regards to capital expenditures, we announced in late September that we added $10 million to the capital budget for 2009, which allows us to keep our activity level in the Sacramento Basin on a good pace through year-end. Total capital cost for E&P operation in the quarter were $28 million including $15 million for drilling and rework, $4 million for facilities, and $9 million for seismic leasehold, asset retirement obligations, and capitalized G&A. We spent about 52% or $14 million in capital projects in the Sac Basin, 30% or $8 million in Southern California, and 8% or about $2 million in Texas, and a small percentage on exploration.

Third quarter lease operating expense and G&A cost, third quarter lease operating expenses were $13.55 per BOE, which is a decrease of 24% from the third quarter 2008 operating expenses of $17.89 per BOE. For the first nine months of the year, LOE was $12.59 per barrel, down 21% from $16.03 per barrel in the same period in 2008. That is down 9% pro forma for the sale of Hastings. LOE was up 9% from the second quarter of 2009 and we expect to see fourth quarter LOE per BOE up again but our guidance of $13.50 per BOE is still good. (inaudible) cost decreased this year compared to last due in part for the sale of one of our highest cost operating properties Hastings but even on pro forma basis costs were down 9% in the first nine months. So we have realized cost savings from vendors and service providers.

Third quarter G&A expenses including non-cash share-based compensation charges were essentially flat at $4.82 per BOE compared to $4.80 per BOE we had in the third quarter of 2008, and up from the $4.36 per BOE in the second quarter this year. For the nine months of the year, G&A is down 6% to $4.34 per BOE compared to $4.64 per BOE in the same period of 2008. Tim Ficker will have additional detail on our expenses later on the call but I would like to touch on some operating highlights first.

Beginning in field count, offshore in the Sockeye field to platform Gail, production declined slightly in the quarter as activity levels were low. We began to see a response from the increased suite of the Upper Topanga water flood, from the dual completion well we completed in the second quarter. Production from the other zone we completed in the well, the (inaudible) Monterey shell zone has continued to meet our budget target. Gross oil rates from the field are slightly under 4000 barrels per day. The South Ellwood field, at platform Holly, we have been concentrating our efforts on identifying opportunities on existing leases. We have several rework and workover opportunities identified, several locations where we believe there may be (inaudible) oil which we can tap with redrills.

As mentioned earlier, we had some scheduled downtime at South Ellwood during the quarter that impacted third quarter daily production by about 250 barrels per day. We used to schedule maintenance downtime to complete the facilities projects necessary for some of our 2010 capital projects. As we previously discussed, we bifurcated our onshore pipeline projects (inaudible) extension application so the pipeline project can move more expeditiously through the process. The resubmitted [ph] pipeline only permit application is now through the final completeness reviewed by the County of Santa Barbara and the City of Goleta.

Environmental and technical review today began with the (inaudible) hearing in October and we are hoping the project’s total [ph] hearing will be in mid 2010. To receive an approval the actual construction of 8.5 mile pipeline is estimated to take about three months. We are pretty certain of the timing here in that there is very little opposition or potentially no opposition to this project. Everybody, environmentals and everybody are for this project.

As for lease boundary adjustment portion of the project, we are continuing to process with the agency hopeful that there will be some progress in the first half of 2010. We provide the agencies with additional information they request but have not received an indication that that information is sufficient to move forward with the project review. In the West Montalvo field, production is steady during the quarter as the workover/recompletion activity is lower.

Our main focus is getting ready to join several wells including one that was spud in September to test previously unidentified pipeline [ph]. We will evaluate the potential of that pipeline from laying in the horizontal leg. In Texas, we finished drilling the well in the South Liberty field in October and have evaluated all the potentially productive zone. (inaudible) continued to evaluate and implement operational efficiencies in the Texas field and we will continue working on a new type in the Mandeville field designed to (inaudible).

We continue to hear that Danbury’s greenline [ph] bringing CO2 from the (inaudible) to Hastings is on schedule to be completed about a year from now. Danbury will then be able to begin CO2 flooding the field and if the response is expected, we should be able to start booking reserves related to our (inaudible) working interest of 22.3% in 2011. Our backing can amount to two to three times reserve (inaudible) and as a reminder, those cost associated with those reserves are carried by Danbury. So these would be lower, no cost reserve wells.

Moving to Sacramento Basin in Northern California, as we discussed in our second quarter call, we (inaudible) our joint activity in the basin during the third quarter. However we maintained our price and workovers and completion performing 49 in the quarter for a total of 162 in the first nine months of the year. During the first nine months, we spud 57 wells and completed 53 including wells spud in 2008 although one of the completions this year has been 28 Grimes Field wells. By year-end we expect to have drilled over 60 wells and performed about 200 workovers and recompletions. We performed our first workover (inaudible) and have seen some very good results. Production base is up over second quarter by approximately level production required from Aspen. We expect fourth quarter activity levels in the basin will be similar to the third quarter even with reduced activity.

Though we curtailed activity in the field, our (inaudible) continued to optimise our drilling effort. Last year we have seen drilling cost decline by little over 30% with a big portion coming from decreased rig rates lower steel costs. We have also got more efficient. I can tell you over the last three years that we have seen our total drilling time, move in and move out time decrease from about 16 to 18 days to a little bit under 10 days. So it is not just the reduced service cost.

At our Analysts’ Day on October 6, we were very excited to talk in much greater detail about our evolving Monterey shale play in Southern California. The full presentation replay is posted on the Investor Relations pages of our Web site. Mike Wracher of VP of exploration does an outstanding job and he can explain the Monterey shale site and you will get a much better picture of the project, the extent of research and science the chart displays. As for our acreage position with Monterey Shale potential, we have approximately 70,000 net acres that are held by production including both onshore and offshore leaseholds. In our leasing program in several onshore prospect areas, we are about 100,000 net acres. So that is in addition to the 70,000 acres held by production. Our goal by next year is to lease another 100,000 net acres to give us a total of 200,000 prospective acres along with our 70,000 HBT [ph] acres for a grand total of 270,000 net acres.

As we discussed at the Analysts’ Day we are in the process of looking for a partner on the play. We have had initial meetings followed by extensive technical review with several potential partners. Our goal is to find a suitable partner on our terms before the end of the year. If we are not able to find the right partner with the right terms, we will move ahead with the Monterey Shale development in 2010 on our own. We think the additional capital and potential expertise of a partner will help advance the play. We started this process with JP Morgan leading the way and identified about a dozen potential partners. We are in the process of conducting detailed technical presentations, are beginning to discuss potential commercial arrangements with a few of these potential partners.

The interesting this about this exploration play targeting the Monterey Shale is that the formation is fairly well defined. Thousands of well bores have been drilled (inaudible) oil to the Monterey Shale in Southern California including on and around our leaseholds. As a reminder to people, this is not exploration in the typical sense of looking for the hydrocarbon because we know they are there. With the information we have, we believe our leases to have an excess of 10 billion barrels of oil in place. As we said, we are not exploring with oils, we are really more looking at drilling and completion techniques that will replicate productive capacity we see in the naturally fractioned Monterey Shale offshore. We can imply our Monterey Shale expertise came from producing the naturally fractured shale more than (inaudible) and South Ellwood and Sockeye field. Offshore we are learned that the Monterey Shale is complex with mixed lithology. Shale (inaudible) and sandstone can influence reservoir response making it seem quite diverse.

Productivity capacity of Monterey Shale is very exciting because unlike other shale plays the zone is extremely thick. Our South Ellwood field Monterey Shale is nearly 2000 feet thick and the same is true for a good portion of the onshore Monterey Shale. Monterey Shale formation is a proven and rich source rock in Southern California responsible for an estimated 38 billion barrels of recoverable oil, with a generative capacity as much as 290 billion barrels. As exciting as Monterey Shale is to us, we believe it will take some time to complete our lease and goals and again drilling and completing wells. We anticipate a very active drilling and seismic effort onshore California for Venoco in 2010. Further reminder is for those who have seen our presentation there that we are also focused on medium gravity to light oil from the 25 to high 30 in terms of API [ph] gravity, so this is good quality oil.

Moving on to reserves, our mid-year reserves, in conjunction with the refinancing of our senior notes, we disclose mid-year reserves were 94.3 million of oil equivalent which adjusted for first half production was a 9% increase over year-end 2008 reserves, pro forma for sale Hastings in February. The mid-year reserve report included proved reserves attributable to the Aspen property. I am not going to go into details right now about the mid-year report but I will say that we have some nice additions (inaudible).

2010 CapEx, we announced last month our 2010 CapEx budget is $180 million with about 60% focused on oil projects. $72 million or 40% will be deployed in our existing Southern California assets, $26 million or 14% is for our onshore Monterey shale play, $73 million or 41% will go to our Sacramento Basin assets, and remaining $9 million or 5% is laid for our Texas property. We also discussed our production guidance for 2010 is going to be 20,250 BOE per day, the same as our 2009 guidance. I remind you that our original 2009 guidance is flat with 2008 we backed [ph] out Hastings for about 19,000 BOE per day. We had good results in the first and second quarters and increased guidance in June to 20,250 barrels per day.

For 2010, we are forecasting that the oil projects will take longer to bring on line than some of the gas projects we pursued in the past. In much of the production growth, we expect in 2010 drilling projects will be fully realized in 2011. Furthermore we are not forecasting any production-related expenses on our onshore Monterey Shale play and believe that several of our development projects has the potential to outperform our budget production enabling our EA frac at Sockeye, that is our first offshore frac in the Monterey, workovers at South Ellwood, horizontal wells at West Montalvo as well as exploration in the Sacramento Basin so with good upside all around.

Southern California, we plan to drill three wells in West Montalvo, two wells in the Sockeye field, one with two fracs, and performing five workovers in recompletion for South Ellwood. One well Sockeye will be dual completion like this year’s well already [ph] complete both Monterey Shale’s produce lower Topanga increase the sweep of the water flood. We are very excited about the offshore frac we will talk in the next year, not just because of potential production gains but also because (inaudible) appears to be analogous to an onshore Monterey shale.

The onshore Monterey Shale play, our $26 million budget without a partner, includes drilling five wells in several prospect areas. We are cutting CapEx and stock-based incurred in 2009 by about 20%. We expect to downsize some greater efficiency and lower cost so we will drill approximately the same number of wells, a little over 60 performed about the same number of workovers and recompletions that is close to 200 this year. In Texas, we (inaudible) four new development wells and try to return five wells to production.

I will let Tim Ficker to go into more detail but the biggest event financially occurred after the end of the quarter as we refinanced our high-yield bond due in 2011 with a new issued deal in 2017. The (inaudible) are $494 million term loans extends maturity to 2014. On the cash flow front, oil prices has stayed firm in the third quarter though natural gas price, of course, weak. There was about 95% of our production guidance hedged. We saw price fall out on the gas side while oil was above our floors. We configured our derivative contracts falling over last week to better reflect our view of 2010 market. We re-set 2010 and 2011 natural gas selling lower which partially funded raising a portion of our 2010 ceiling by over $10 a barrel. So we are taking our ceilings from $72.88 per barrel to $83.32. We did not make any changes to our floors.

With that I would like to introduce Tim Ficker, our CFO to go over the financial highlights.

Tim Ficker

Thanks Tim. The third quarter was another strong quarter and I will cover some of the financial highlights.

Adjusted earnings for the quarter was $5.7 million and adjusted EBITDA for the quarter was $48 million, both of which represent increases from the second quarter but decreases from the comparable 2008 quarter. The decrease were largely due to a significant decline in oil and gas revenue partially offset by an increase in realized commodity derivatives and a decrease in lease operating expenses.

Oil and gas revenues were $69 million for the quarter compared to $158 million in the 2008 quarter, decrease was due to prices which were down from the 2008 quarter about 47% to $58.09 per barrel for oil and down about 64% to $2.17 per gas, partially offset by production which was up slightly/ Pro forma for the sale of Hastings does result drilling and workover activity in the Sacramento Basin and West Montalvo field.

I would like to remind everybody that we have got a robust hedging program in place with a significant portion of our production hedged on the downside for the next two years and we expect to layer in additional hedges for 2012 when we see opportunistic pricing. Because we do not follow hedge accounting, we see significant unrealized gains and losses from quarter to quarter, and included in unrealized gains and losses on our income statement is the amortization of derivative premiums that we pay. I wanted to point that out because it appears that some of the analysts’ estimates we see do not include that amortization in their models. As such last quarter, we began to disclose the future amortization of those derivative premiums in our hedging footnote in our 10-Q.

Turning to lease operating expense, it decreased about 30% from the 2008 quarter and the most significant reason for the decrease was the sale of our Hastings property, which was one of our highest operating cost properties. Excluding Hastings on a BOE basis, LOE decreased 10% from $15.04 in the 2008 quarter to $13.55 in the 2009 quarter. The pro forma per year decrease is primarily the result of our focus on managing operating cost at our properties. LOE for the first nine months of 2009 was $12.59 per BOE, which compares favorably to our annual guidance of $13.50 per BOE.

G&A expense for the quarter decreased to $9.6 million from $10.2 million in the 2008 quarter and on a BOE basis, G&A expense excluding stock-based compensation charges was $4.82 in the third quarter and $4.34 for the first nine months. Our 2009 guidance calls for G&A of $4.50 per BOE excluding stock-based compensation charges and we believe we are on track with our guidance.

On the DD&A front, the decrease we saw from $16.31 per BOE in the 2008 quarter to $11.39 per BOE in the 2009 quarter was driven by the ceiling writedown we recorded at year-end in the accounting to the sale of our Hastings steel, both of which resulted in decrease (inaudible). Our DD&A rate for future quarters will depend primarily on our capital expenditure program and the determination of our reserves but we expect our rate to average $12 per BOE for the year. The first nine months of 2009, our DD&A rate was $11.49 per BOE.

Turning to the balance sheet, compared to the year-end 2008, the biggest changes were in PP&E and debt, both of which were down as a result of the Easter proceeds and the sale of our Hastings property. Regarding debt, I will mention a few things. In October, we issued $150 million in aggregate principle amount of senior unsecured notes which are due in 2017 and we used the net proceeds of this issue along with additional borrowings under our revolving credit facility and cash on hand to satisfy and discharge our existing senior notes. As a result of that refinancing, the maturity of our second lean term loan facility will be automatically extended from September of 2011 to May of 2014. So we have no maturity on any of our term debt for over four years.

Next subsequent to the refinancing, we had an (inaudible) interest rate swap agreement which extended the terms of our existing interest rate swap through May of 2014, that is the new maturity date of the term loan. As a result, amounts borrowed up to $500 million will effectively bear interest at a fixed rate of 7.8% until May of 2014. Finally, I will mention that now that we had extended the maturity on both of our senior notes and our term loan, in the next few months, we expect the maturity of our revolving credit facility to 2013 from the current maturity date of March of 2011.

That is a brief financial overview, Tim, I will turn it back to you.

Tim Marquez

Thanks Tim. With that, we will open it up for questions.

Question-and-Answer Session

Operator

Your first question comes from the line of Mike Scialla of Thomas Weisel Partners. Please proceed.

Mike Scialla – Thomas Weisel Partners

Good morning guys..

Tim Marquez

Good morning Mike.

Mike Scialla – Thomas Weisel Partners

Can you give us a sense of what the competitive landscape looks like now for the Monterey, are you seeing any new entrants in what our acreage cost is looking like now?

Tim Ficker

Yes, I do not want to get into acreage cost, I will say they are certainly attractive compared to the other shales. We are seeing a little competition there, our team is definitely busy out there. There is still plenty of acreage to go but, yes, we are seeing some competition.

Mike Scialla – Thomas Weisel Partners

Okay and then in the $26 million plan, it sounds like that is if you go to loan, if you were not to get a partner, if you do get a partner, does that $26 million get redirected to other areas in the company or do you speed things up in the Monterey with drilling and buying additional acreage.

Tim Ficker

Yes, the plan right now is if we got the partner in, our net CapEx would go down but our drilling activity in the Monterey would go up by factor two to three times the rate but our tentative plans would be just to reduce our CapEx budget if we bring the partner in.

Mike Scialla – Thomas Weisel Partners

Okay, I did not quite catch it, I think you went over it, but the break out of that $26 million it sounds like it was for five wells including quarrying and was some of that boasting for additional acreage as well?

Tim Ficker

That would be just for the development work, it would not include the land cost but yes, $26 million will be for five wells and try not to overanalyze that too much because, you know the first wells are going to be quite a bit (inaudible) will ultimately will be teared down but, yes, the initial wells are precisely $26 million for five wells.

Mike Scialla – Thomas Weisel Partners

Okay, just one last one for me, I will get back in the queue, the Sockeye the first frac there, how are you planning on designing that, is that going to be just a single stage or multi-stage, is that going to be a two horizontal or just a directional well?

Tim Ficker

Yes, it is going to be a multi-stage, it will be a true horizontal and just kind of remind people, people not familiar with the story, when we started drilling the Monterey and the M2 offshore, the initial wells are more or less vertical there. Of course you generally will get one vertical well on a platform but they are more or less pretty vertical and then a few years ago – well those wells came in 100 barrels a day to 150 barrels a day. And then a few years ago, we started drilling horizontal wells in the Monterey M2 and we saw substantial improvement, we saw the rates go up to 600 barrels a day to 800 barrels a day IPs but those were unstimulated.

And now, we are going to come in and do a multi-stage frac on these wells and hope for – science says there should be substantial improvement to both that. And then as indicated on the call, the Monterey out here in Sockeye is pretty analogous to what we see onshore at least (inaudible) performance. Typically the onshore Monterey wells, vertical wells in the areas we are leasing, IP kind of tie average of around 80 to 100 barrels a day and which is more or less analogous to what we are seeing up there in Sockeye. So we think that what we learned in offshore can translate into onshore and vice versa. Some of the ideas we are coming up with onshore helping us kind of re-look at the Monterey offshore.

Mike Scialla – Thomas Weisel Partners

Thanks Tim.

Tim Marquez

Thanks Mike.

Operator

Your next question comes from the line of Steve Berman of Pritchard Capital Partners. Please proceed.

Steve Berman – Pritchard Capital Partners

Good morning guys.

Tim Ficker

Good morning Steve.

Steve Berman – Pritchard Capital Partners

A couple of things you talked about the Analysts’ Day, anything new there, feasibility of horizontal Sac Basin drilling, exploration in the Guinda, any further thoughts there?

Tim Marquez

Yes, we are probably going to slow down the pace of riskier projects in that base and we are still very optimistic. I think, I have always felt that the Guinda could potentially be a very big deal for the company but it is very over-pressured, it is going to be one that takes a little thought and this kind of price environment $5 gas, it just does not seem the right time to do it. So in fact, based on our focus and for the most part on just standard, routine in-fill drilling. Now we are drilling, we have a couple of exploration areas. We shot 3-D over and the anomalies look very nice. We are going to be drawing some of those but those are vertical wells, they are relatively shallow, pretty cheap, quick wells to cost you infrastructure, so it would not take much in the hook up. So I think the Guinda is going to be a lot of potential but a challenge.

Steve Berman – Pritchard Capital Partners

And how are you balancing doing workovers up there versus regular in-fill drilling?

Tim Marquez

We are going to drill close to 200 wells up there compared to 60 plus wells in drilling, now cost wise those workover cost are very, very low. In fact – once we clean up a well bore, in other word when we acquired well bores, like when we acquired Aspen, when we acquired Texaco [ph], lot of those guys said, it's very complicated well bores and one, two, three factors and so, we got in initially and had to clean out all that junk.

So our initial work over in Sac Basin maybe 100 plus thousand per well. Once we cleaned it out and we come in and set (inaudible) didn't come in, while I [ph] appropriate to these wells. So, we can work over well there for almost little $5000 to $10,000 per well, which is almost nothing. So that 200 workover is done at an attractive rate and that cost per well goes down with time, because we only have to clean up the well bore once and then it has got a clean well bore the rest of its life. So, in the order of magnitude there should be 2000 workovers, we'll add about same amount of production in 16 new wells.

Steve Berman – Pritchard Capital Partners

Okay. And one more question, on the Hastings you talked about marketing the probable reserves there, can you bring us up-to-date on that process?

Tim Marquez

We have been working on that. We haven't launched it yet. Probably going to launch that process towards the end of the month, but we don't expect to be in a position to announce anything before the end of the year. It's bit of a head scratcher; it's from our perspective its probable PDP reserve. It's a very valuable reserve contemporary (inaudible), and as we've indicated before, we're talking something 30 plus million barrels of PDP reserves and in the one hand you would hate something that is valuable but on the other hand we are not in (inaudible) mission equity at what we consider to be depressed prices.

So we won't realize any cash flow in Hastings for, depend on oil prices cost [ph] four to six years. So, we are going to test the market, but I can tell you it will not be a fire, so we won't be selling these cheap. If we get what we consider to be acceptable prices having a probable resources the market normally does, and we would sell, but if not we won't have any problems just to hold on to them.

Steve Berman – Pritchard Capital Partners

Okay. Thanks a lot. I will let someone else come.

Tim Marquez

Thanks, Steve.

Operator

Your next question comes from the line of Sven Del Pozzo of C.K. Cooper. Please proceed.

Sven Del Pozzo – C.K. Cooper

Yes, Sven Del Pozzo. Good morning. I was wondering about – forgive me if any of these questions if you have already dealt with this, I had to patch in from another call, but the gas production increases from the second quarter to third quarter, I guess I was little surprised by that because of the basic strategic shift to oil from gas and I was wondering if that is tied to a more intense workover program in the third quarter than the prior quarter. Just correct me if I am wrong?

Tim Marquez

Sven, that was really entirely due to the acquisition of Aspen and the close at beginning of the third quarter.

Sven Del Pozzo – C.K. Cooper

Okay. Then on to the platform, Gale, I was wondering about the technical challenges that will be tackled by you guys, so give me an idea what's its technical risk of drilling these wells. I basically understand that M2, is it the M2 unit that you would like to produce from, and then beneath that there is a M4 unit, which is a water-bearing zone. What kind of technical challenges might this have for you guys and how do you overcome it?

Gale Wright

First of all the M4 is not a water-bearing zone, it's an oil-bearing zone, and it's better productive capacity, so we don't have to stimulate so much. The M2 really the technical challenge for drilling the well are not that much. We drilled four, five horizontal wells into the M2, but this will be the first frac. It's more impacting; it's more – just of the logistic thing. If this is onshore it wouldn't be any challenge at all but platform unlike onshore then they have a lot of acreage to go with it, about one acre versus small drill (inaudible) couple of acres. So it just a matter of logistics given the equipment out there, other than that it's about the same. And then like the Gulf of Mexico we just don’t have the workforce to frac these wells. So, we don’t anticipate any, any real challenge the horizontals in the M2 drill up pretty nicely. We never really had any difficulties drilling them. Having said that (inaudible) the well. But it drills up nice, it’s just a matter of logistics of trying to position all the equipment with limited deck space.

Sven Del Pozzo – C.K. Cooper

Okay and so things do go well there. And I understand there is only two budgeted but what kind of the bigger picture can I have in terms of, lets say you do get a better IP rate because of the stimulation, how much running might you have?

Gale Wright

We’re talking of potentially about 10 additional wells.

Sven Del Pozzo – C.K. Cooper

Okay. And then any, okay so if you do frac into the M4 that’s not a big deal, it’s a oil and water bearing zone you would just produce the oil from both zones and then separate the water from the oil on the platform?

Gale Wright

Correct.

Sven Del Pozzo – C.K. Cooper

Okay and could you give us an update on how much money does, on Hastings where you have reversionary working interests, how much CapEx does (inaudible) have in their, did they need to recover as part of the payout calculation there?

Tim Marquez

Bill you are close to that, Bill Schneider, can you answer that question?

Bill Schneider

Yeah, they raised it when they purchased the field there, I must say it is approximately a $100 million from the purchase price that they would recover, beyond that it would be the capital based spend in the field that gets grossed up at about 30% I think the current estimate of that will be around $250 million of total spend so that’s plus the 30% growth, so your round number that comes to about $400 million or so.

Sven Del Pozzo – C.K. Cooper

Okay. And lastly tomorrow are we supposed to have an election tomorrow that might influence the outcome of the South Ellwood lease expansion?

Bill Schneider

No,, well, there is the elections is today, the only thing that indirectly would happen is, the lieutenant governor is running for a congressional seat and that election takes place today. If he is the outright winner then he would no longer be the lieutenant governor, and there would be a new lieutenant governor appointed.

Sven Del Pozzo – C.K. Cooper

Okay and is there any way you could help me to I mean is there any thing to read into here or is it just highly speculative this type of political risk how it might influence your extensional lease of South Ellwood?

Bill Schneider

It really depends on who the new lieutenant governor is, it’s important, there are only three people in the State Land Commission so every vote is important. And quite often Lieutenant Governor is a swing vote. Our project is quite a bit different and it’s really hadn’t been that controversial, I have always – it’s always been the case in Southern California for 30 years.

All these projects end up getting approved, it is just a matter of timing and the way I handicap it, I think we have a 50% probability of getting it approved next year and then diminishing probabilities after that. But, we don’t hang all our hopes on one individual vote and usually it really doesn’t come down to that. Our project is like I said just really not that controversial, the pipeline is not controversial. One project is there but it is on the lease extensions it really its there’s very limited oppositions but it still does move slow through the process.

Sven Del Pozzo – C.K. Cooper

All right okay thank you gentlemen.

Bill Schneider

Thanks Sven.

Operator

Your next question comes from the line of Jeff Robertson of Barclays Capital. Please proceed.

Jeff Robertson – Barclays Capital

Thanks. Back to the Monterey shale, can you talk a little about the timing of when you hope to be out in the fields drilling in 2010 and what’s left to do on the prospects in terms of science and also permitting to get wells ready to drill.

Tim Marquez

Okay, well our first, our next Monterey well will be offshore we will spud that well by some time early December. And then onshore the Monterey, our first well be spud in the beginning of January, sometime around January 1st. In terms every – we have number of different areas some have good (inaudible) more signs than others some have – all of them had a number of wells drilled some are more complete than others, some have course some don’t and so it depends on area-by-area. Permitting wise, we are permitting a lot of wells right now in all the different areas. Mike, Gale, how many do have total permitted right now throughout the state?

Gale Wright

We've got throughout the state about 12 permits right now.

Tim Marquez

So, we want to build that inventory up so that if it comes in as we expect and hope that we can really accelerate the drilling. So it will be – the first half of the year as I hope it plays out will be relatively slow because we want to take the cores, get the cores analyzed, and then get the fracs done, and then have some time to evaluate the results. And then second half of the year is when I really see us really ramping up the pace of drilling.

Jeff Robertson – Barclays Capital

Thanks. And Tim on the permits, are those good for a certain length of time and how much leeway do you have to modify locations and things like that with the permits?

Tim Marquez

Yes, it depends on what County you're in, but generally once you get a permit issue, you have at least a year to drill and then to that extent is really not a big deal. And then also once you get a well permit, again, depends on where you are, you have pretty good latitude in moving around, it is easy to move bottom hole locations around, moving the surface location around takes a while.

But onshore California I think is generally about as easy place as an place in the country to drill. I mean, keep in mind last three years we drilled 100 wells a year and permit is just not the same issue in state waters.

And again, I'll remind you on federal waters it very easy to drill here in California, onshore is very easy to drill in California. State water is the one that takes little bit of time now. We drilled in work over wells, we got a pretty active work over program in South Ellwood but the least extension, a new lease or extended lease and that takes a little bit of time. But offshore California that’s a non-issue, you don’t want to wait till last minute to get your permits but as far as you plan your business ahead you can get the wells permitted.

Jeff Robertson – Barclays Capital

Thanks Tim.

Tim Marquez

Sure Jeff.

Operator

Your next question comes from the line of Joe Allman of JP Morgan. Please proceed.

Joe Allman – JP Morgan

Thank you and good morning everybody.

Tim Marquez

Good morning Joe.

Joe Allman – JP Morgan

In terms of the South Ellwood lease extension permit, at this point how much do you control the timing or is it in the hands of the State lands commission.

Tim Marquez

Yes, we don’t really control the time. All we can do is when they have questions on the application, we respond as quickly we can, but it's really in their hands now. They have limitations on how quickly we can respond to each phase, some phase they have six months review of EIR [ph] other times it is less than three months.

Unfortunately they use the full clock. I don’t think it's necessarily nothing against the oil companies. They are just bureaucrats, a nicer way to say that. The same problem in oil industry we have here in California is any type of development, any new activity. If you to talk to any land developers they have they same process. So, unfortunately we don’t control time other than like to say to respond as quickly as we can.

Joe Allman – JP Morgan

Okay. So (inaudible) asked a question about the election today and is in fact it appears we will get a new lieutenant governor in California, and if in fact that person would be favorable towards your lease and other leases. How much do you think you could push to get that on the agenda at some point next year or such that you can get a hearing next and potential get approved?

Tim Marquez

Well, whoever it is we'll almost certainly be on the agenda next year and if things right, we get approved first shot, if not sometimes they send it back and want you to address certain things. But I really can't envision a scenario where we are not on the agenda of the state land commission regardless who gets in.

Joe Allman – JP Morgan

Okay, that’s helpful. And then besides Hastings, in term of asset sales, besides the Hastings, were you looking at some additional asset sales too and if so, how are they coming?

Tim Marquez

No, I don’t think we've contemplated it at all right now, as Hastings it is just a – it’s an asset that gets no value in the marketplace, and yet it’s a very valuable resource, so something we felt that we could sell. Let’s put it this way, if people be willing to pay the same price it as we would pay for it, then we would sell it but we really are not interested in selling production right now, we are pretty happy with the assets we have.

Joe Allman – JP Morgan

Got you, thanks. And then, at the Analyst day you indicated that Dos Cuadras is working on a few initiatives, any update on those?

Tim Marquez

Just the one I have given where namely that part where we – JP Morgan is leading the process from the Monterey and it’s going quite well. We’ve contacted about a dozen people and given quite a few – got CA sign with quite a few people and given full technical presentation. And got very nice response, and so what I said at the analyst conference (inaudible) I don’t think it is going to be the dollar after would turn anybody away.

I think, if anything, you may come back some of these guys are pretty substantial companies that may insist on operating, although, nobody said that yet, but it is something that they have to be negotiating. There is something that we may not, let’s say, the effect of dollars, we may not want to concede. This is a very important thing to – these are all very smart companies we are talking with for us to turn over control. This is somebody else would be – we have to park it up to do that. So, we are getting very nice response and I am pretty optimistic that we will get something done, but this is not done yet.

Joe Allman – JP Morgan

Okay, very helpful.

Tim Marquez

As far as the other initiatives we are a few weeks behind on the pace. We would hoped to be on the Hastings sale, but kick up that process more formally by the end of the month.

Joe Allman – JP Morgan

So those initiatives are more a kind of asset modernization type things or…

Tim Marquez

Yes certainly the Hastings is, the Monterey is away to accelerate the overall project. I think at any time we should be – we are very NAV driven and selling down a piece of a third of it to accelerate the whole project is a good thing for us. So you can just move a lot quicker for bringing a partner.

Joe Allman – JP Morgan

Okay. Very helpful. Thank you.

Tim Marquez

Thank you.

Operator

(Operator instructions) Your next question comes from the line from Anish Patel of Credit Suisse. Please proceed.

Anish Patel – Credit Suisse

Hi. Good morning everyone.

Tim Marquez

Good morning. Hi.

Anish Patel – Credit Suisse

I was just reviewing the earlier comments and was wondering if you could review the potential upside project for 2010? I think one of them was Monterey exploration, and I was wondering what the others would be?

Tim Marquez

Well, if you go to offshore the upside project is we have got a pretty extensive work over programs from (inaudible). Again, some of the stuff we have actually learnt from onshore and reviewing our stuff, giving some new ideas and we think we can lay true horizontals in some of our South Ellwood stuff on our existing leases that would then take much (inaudible) and because some of them at Monterey, it is a very thick colony we have there at Monterey (inaudible) close to 2000 foot thick and some of the zone, we had very good recovery. Some would have very little recovery and we want to go back to some of the zones where there is very low recovery and laying for horizontal and initially complete a month (inaudible) the other producer may be come back and frac those later. So, I think those two projects at South Ellwood, have a very good upside, but we are budging, but they are quite riskier [ph] in nature.

And then at Gayle [ph] I really like the horizontal well we are going to be drilling in there with the frac, as I mentioned, we are going to be fracking a couple of wells. Never done that offshore. On paper you can predict what the results would be, and they look pretty good, but things don’t always work out according to what you have on paper. But pretty excited about the possibilities of fracturing some of the Monterey offshore and Montalvo we’ve got a pretty busy program there. Those wells have been very pleased with the performance there. We contemplated the possibility of drilling some horizontal wells there, which could turn out interesting. The well we are on now, as we mentioned, is actually testing a new (inaudible). So it’s too early to tell them that one, but that’s a pretty good upside there.

Moving to Sacramento Basin, for the most part, it is going to be just routine in-fill drill and it is very predictable well, lot of work obviously there, but we are also got a couple of exploratory areas that we are going to be drilling couple of wells there. I do truly want to get into more developments or exploration into the Guinda but now at the $5 price environment it is not the right time to do it. So those are the big areas besides from the Monterey, they have some pretty significant upside.

Anish Patel – Credit Suisse

And then, just to confirm, all those areas are not in your currency 2010 guidance?

Tim Marquez

Well, it’s now so [ph] we have a little bit of production showing for that but not much I think we could substantially improve it, same with the horizontal in the (inaudible) we have some production there but let us call it pretty conservative guidance. We never budget any exploration production, so the exploration that we’re going to be doing at the Monterey onshore in the Sacramento Basin, we had no production showing for that.

Anish Patel – Credit Suisse

Right, that makes sense. And then, looking at the Monterey leasehold expansion, the expectation of additional 100,000 acres, is there any way to frame the amount of dollars that will be required to get there, I know it’s very competitive but just to help us out on the dollars amount?

Tim Marquez

Yes, we will be shooting ourselves in the foot if we start telling people what our expectations are and I know it’s tough not to be able to that. All I can tell you is that substantially cheaper than the other shell gas plays but not as cheap as it was a couple of years ago either, I know there is big bracket but – I don’t want to shoot ourselves in the foot.

Anish Patel – Credit Suisse

And then if you were to get a partner in the Monterey, would they participate in the acreage ads [ph] as well, you already got, so would it be 100,000 acres, 30% of that they would be able to participate in or how is that works?

Tim Marquez

Yes, conceptionally would be the bigger thing to 200,000 is what we put on the table is going to be some upfront money, carry turn, one-third interest in the 200,000 exploratory acreage onshore.

Anish Patel – Credit Suisse

Okay. That’s all I had. Thank you very much.

Tim Marquez

Okay. Thank you.

Operator

You have a follow-up question from the line of Sven Del Pozzo of C.K. Cooper. Please proceed.

Sven Del Pozzo – C.K. Cooper

Yes, just a quick one, I probably missed this. What were the barrels that did not get produced owing to the temporary shutdown of the platform during the quarter?

Tim Marquez

I think it was about 250 barrels a day, average for the quarter.

Sven Del Pozzo – C.K. Cooper

Okay. Thanks a lot.

Tim Marquez

Welcome and that was a planned shut down and that was nothing – that was a budget from the beginning of the year.

Sven Del Pozzo – C.K. Cooper

Okay.

Operator

At this time, there are no further questions. I would like to turn the call back over to Mr. Tim Marquez for closing remarks.

Tim Marquez

Thanks everybody for the questions and thanks to those listening to the webcast. We're very pleased with our solid results for the nine months and believe we’ll meet or beat our annual guidance for the year.

We're excited about the opportunities in 2010, in fact, 17 years I've had been in Venoco, this is the year I am most excited about, looking forward to. With our oil focused inventory projects, we believe we’ll have another good year and Sacramento Basin just keeps getting bigger and better every year.

Our agents [ph] initiated drilling in our Monterey Shell prospects early next year. Hope we’ll have a partner to help accelerate development of the play. As always, we keep our acquisition team busy looking for opportunities but we remain patient for the right opportunity.

We intend to give a one-day conferences in New York, one next week, and one in the first week of December and hope to get out and visit with you at the time.

All right, I look forward to updating you in the fourth quarter year-end call in March. Thanks and have a good day.

Operator

Thank you for joining today’s conference. This concludes the presentation. You may now disconnect. Good day.

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