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Venoco, Inc. (NYSE:VQ)

Q4 2008 Earnings Call

March 05, 2009 11:00 AM ET

Executives

Michael G. Edwards - Vice President, Investor Relations

Timothy Marquez - Chairman and Chief Executive Officer

Timothy A. Ficker - Chief Financial Officer

Gale Wright - Reserves Manager

Analysts

Joseph Allman - J.P. Morgan

Sven Del Pozzo - C.K. Cooper

Michael Scialla - Thomas Weisel Partners

Stephen Berman - Pritchard Capital Partners

Jeffrey Robertson - Barclays Capital

Marianna Kushner - Nomura Asset Management

Operator

Good day ladies and gentlemen, and welcome to the Fourth Quarter and Full Year 2008 Venoco Inc. Earnings Conference Call. My name is Lacy and I'll be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question and answer session towards the end of this conference. (Operator Instructions) As a reminder this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for today's call, Mr. Mike Edwards, Vice President. Please proceed sir.

Michael G. Edwards

Hello everyone, I'm Mike Edwards with Venoco. Today Venoco issued a press release today on our fourth quarter and full year 2008 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 fact 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 reserved estimates that geological engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under 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 estimates of proved reserves and accordingly are subject to substantially greater risk 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, at venocoinc.com. Now I'd like to introduce Venoco's Chairman and CEO Tim Marquez.

Timothy Marquez

Thanks, Mike and welcome to all of you who've called in or are listening to the webcast. Today I'm very pleased to review Venoco's fourth quarter and full year results. Before launching the details of results, I want to update everyone on Venoco's financial position, and the steps we've taken in recent months to weather the current financial markets and global economic downturn.

Credit markets, of course remain uncertain but they're signs that likely (ph) several energy companies have accessed the market with high yield issues and seemed positive interest in their offerings. With our existing of post Hastings sale balance sheet, we don't have a current need to access the market. None of our term debt instruments mature until late 2011. We have a mechanism to push maturities out on the term debt until 2014.

Senior credit facility has been reduced from 200 million to a 125 million with a re-determination curve with the Hastings sale and based on new bank pricing. We believe that it to be a conservative borrowing in this (ph). We've about $5.5 million total on the revolver solely to have our variable rate debt match our $500 million interest rate swap. We have $35 million cash on our balance sheet and we don't expect to draw additional significant amounts on our revolver, after an acquisition this year.

On the cash flow front price remained low but we have a 101% of our forecast 2009 production hedged with oil prices averaging $54 barrel and gas for 701 per Mcf. Finally, we reduced our 2009 capital budget $150 million as we have stated we have the flexibility to reduce it much further should it become prudent. Having said that all of our 2009 development projects are very economic at $40 oil and 550 gas.

So a take away from this is we have no need to access the markets at present. The Hastings sale proceeds allowed us delever concurrent with the re-determination of our volume base. We remained very flexible on capital spending and we've hedged 101% of our 2009 production guidance as well 90 plus percent of anticipate 2010 production at favorable prices and I want to emphasize this is 101% of total production not just PDP production but total production.

Talking about productions, I already (ph) stated production for the quarter was 22,674 barrels of oil equivalent per day. That's an all time high for us. This is a 3.3% increase over third quarter of 2008 of 21,949 BOE per day. And a 13% increase over fourth quarter of 2007 of 20,100 BOE per day. Our 2008 annual production guidance was to exceed 21,500 BOE per day and we hit that by averaging 21,674 BOE per day for the year. That represents 11% increase from full year 2007 of 19,535 BOE/day. The acquisitions we made during the year were inconsequential so the growth was essentially all organic. Our capital expenditures for the fourth quarter, capital expenditures were $92 million with a little over half of that spent in the Sac Basin, 27% spent in Southern California and 10% in Texas. For the year our capital expenditures were 301 million which is right on target with our guidance of 300 million.

Moving to operating expenses and G&A; fourth quarter lease operating expenses were 19 to 21 per BOE which is an increase of 7% from third quarter of 1789. The increase in the fourth quarter is really an accounting function, its counts for the reversal -- the inventory build we had at the end of the third quarter, Tim Ficker will provide a more detail about that later. For the full year LOE was 1686 per BOE, an increase of 12% over full year 2007, of 1505 per BOE for pro forma for the Hastings sale, LOE was 1432 per BOE. The Hastings production was by far our highest cost production. So back of that cost that's gives a much better idea of the LOE associating with our remaining assets

Fourth quarter G&A expenses were 558 per BOE up, from the 507 per BOE we had in the third quarter. Excluding non-cash FAS 133 charges. Our G&A in the fourth quarter was 521 per BOE compared to 480 in the third quarter. For the year our G&A was 543 per barrel up 22% from 2007 of 446 per barrel. Tim Ficker will have additional detail on expenses later in the call.

Now lets go on to some operating highlights; starting Southern California the West Montalvo field, we've seen no production increase in more than 75% or about 480 barrels per day in 2008 as a result of our ongoing efforts of returning oil wells to production, upside on that capacity, upgrade in surface facilities and drilling new wells. We continued to convert certain wells to water injection, which allowed us to handle the additional water volumes from our skilled revitalization. We're also doing facilities work to increase our gas handling capacity which is constraint to more oil production.

To begin to drilling into a well, late in the third quarter and that had good initial results. We'll continue our efforts in the field by drilling another couple of wells this year, including other one we just tided (ph) offshore earlier this year. To date our average onshore well is right about $3.5 million with almost to 0.5 million barrels through well. With IPs, close to 400 barrels a day with a stabilized rate around 152 barrels a day, and that $40 oil, 550 gas price have a rate of return of around 35%. The offshore wells are going to run another $1.5 million on top of that with reserve is about 10 to 20% higher then on the onshore well. With IP's well of access of 200 barrels a day, in the stabilize rates should be around 200 barrels per day, with rate of return of close to 30% at 40 and 5.

Turning to offshore, the water flood and Sockeye -- by the way those prices I quoted, those are NYMEX prices, so we actually received less in fuel, but we've taken those differentials into account. Turning to offshore, the water flood and Sockeye Field at platform build (ph) continues to perform well in the fourth quarter and we saw it gross oil rates around 4800 barrels per day. We've planned some facilities worked this year that will allow to process additional gas volumes and we will be drilling a new well soon in the second quarter, there will be a dual completion with one zone for production and other for water injection, to expand and enhance the water flood.

In the South Ellwood field, we're still working out on our full field development project. As those of you followed the plains exploration nodes (ph) the projects surrounding California offshore oil development were in the spotlight late in January. Our plans was before the California State lands commission seeking approval for project to drill from federal water platform in the state jurisdiction. The complicating factor was State of California would issue need to issue a new oil and gas lease which it hasn't done in more 40 years. Three member commission voted two to one against the project.

The vote on the Plains is not positive for our project however, our project is very distinct from the Plains proposal and that we already have the State lease, all we are doing is expanding the boundaries of that lease. We are producing from that lease actually and draining the full field. We are mainly asking for adjustment to lease find fully encompasses South Ellwood field, which has been producing for more than 40 years. By using extended lease drilling from existing platform we'll be able to recover additional reserves, but the primary benefit would be that we accelerate ultimate recovery from the four fields by several decades.

Couple of positive factors for us is we placed the existing barge in operation with the pipeline and we'd accelerate the life of the field which is all positive from an environmental standpoint. We are moving cautiously in light of the Plains decision and are in the process of evaluating the situation. We expect to have a better idea of the path forward one way or another in the second and third quarters.

In Texas production covered in the fourth quarter from the effects of hurricane Ike in mid-September. Most of production is back within the first few weeks of the fourth quarter. We stayed focused in both the Hastings and Manvel fields on returning wells production, converting gas with wells to electrical submersible pumps and added fluid processing and injection capacity.

In Hastings, with the pending sale to Danbury, we focused on projects that maximized reserves. We've been very pleased with the work in these two fields this year. We worked with Danbury resources throughout the fourth quarter in January to close the sale of the Hastings Complex and facilitate their implementation of CO2 enhance recovery project. The sales prices determined for the year-end 2008 reserve report using the year end NYMEX five year strip pricing, and the last 12 months of operating cost, resulting in the sales price of $201 million.

Year-end reserves at the SEC price, were 7.7 million barrels of oil and the complex averaged a little over 2500 barrels a day, so implied sales matrix from 80,000 per daily barrel. Danbury took over operations on February 2nd, and we retained a 2% overriding royalty interest in the existing field production. We also retained a 100% deep rights over which we expect to run 3D seismic survey in the coming years. We also retained a reversionary interest, back into 22.3% working interest in CO2 project, after Danbury group's various costs and expenses.

Although we don't have any reserves currently booked to the CO2 front, we think ultimate reserves net to Venoco related to the backend could be upwards of 30 million barrels net to the company. Manvel field presents a similar opportunity as Hastings with CO2 flooding potential, because of its similar reservoir and fluid characteristics. We're currently designing a potential CO2 flood at Manvel and we're exploring potential CO2 sources.

Danbury has announced separately that they intend to have the pipeline to the field by late 2010 and then told us they plan to begin injection in the Hastings build (ph) in 2011. Moving to Northern California, Sacramento Basin, our activity levels remained high in 2008 in Sacramento Basin, this has just been a great story for Venoco. We've been focusing primarily on our in field drilling program the Greater Grimes and Willow field. We drilled 112 wells in the basin, 81% were productive and performed 144 work-overs and re-completions. We fracked 70 wells in 2008 in the basin. We've seen rig costs down a couple $100,000 per well which depending on Willows and Grimes is about 15 to 20%. So order of magnitude, we've seen well costs come from about 1.15 million down to about 950,000.

Those costs don't reflect the forth coming drop in steel prices, because prior to steel work off inventory from last year we anticipate additional savings as much additional 100,000 savings on well cost by the end of the year. We remained encouraged and continue to analyze result in order to optimize future fracs in the basin. We think there's a lot of promise in the basin and continue to see a bright future for Venoco in the Sac basin.

I want to touch on the purchase and sale agreement, we signed a couple of weeks ago to acquire additional production acreage in Sacramento basin from Aspen Exploration. Aspen is publicly traded sort of company because they're selling virtually all their assets in this transaction. They have to complete a shareholder process before we can finalize that transaction. In addition, there are a number of individual owners who invest in the Aspen wells, as working interest owners. They may also elect to show to their interest in the Aspen controlled California interest.

We signed the PSA with Aspen and Partners which represents about 70% of the ownership of these assets. If both the owners elected to sell their interest the total purchase price would be about $25 million. These assets are in the Greater Grimes area, so it'd be easily integrated in our operations. As I mentioned, Aspen is a public company so we believe the process takes several months to close. Because the transaction involves a substantial portion of a publicly traded company, we're not in a position to go into detail about the assets today. We can say they're -- if we're able to close a deal, we use cash and other revolver to fund the purchase price. All-in-all, we continue to be very excited about our core operations in the Sac basin, as well as additional opportunities we see in our downs (ph) basin efforts, frac program, deep rise into both on acquisitions.

Sac basin, the drilling, even if these low price continues to be very economic as a result of this reduced drilling cost, currently our rate of return on our projects as current prices is around -- it's in excess, well in excess of 50%. So these projects are still very economic.

Moving to 2009 capital budget. We reduced our 2009 capital budget in January to $150 million. About half of that goes to Sacramento Basin, quarter to Southern California worth roughly an impeach (ph) to exploration and capitalize G&A. A few million dollars go to projects in Texas. I'll reiterate our budget is very flexible to be able to make further reductions if circumstances dictate. We also have some inventory projects ready to go, if we see some strengthening in their prices.

We've maintained our production guidance for year at 19,000 barrels a day, which is flat with production 2008 adjust for the sale of Hastings. We've had a great start for the year on production and are optimistic about the year. We've also focused on every aspect of our revenues and expenses to maximize cash flow in order to come closer to drilling within cash flow.

Moving onto reserves, as previously announced our total crude reserve -- oil and gas reserve as of December 31st, were 97.5 million BOE using SEC pricing compare to our year-end 2000 reserves of 99.9 million barrels of oil. We've produce about 7.9 million barrels oil equivalent in 2008, acquired about 0.5 million BOE, at extension discoveries of 11 million BOE, and negative revisions of 6 million BOE. On the negative 6 million BOE of revision it is made up of 11 million barrels we lost due to price differences between '07 and '08, and the 5 million BOE we got that due to better performance.

When we look at the net impact by region, we had a 5.7 million BOE approved reserves in Southern California assets, with the majority of the additions coming at the West Montalvo field. In Sac basin we had a 7.8 million barrels of proved reserves. In Texas, we saw the majority of the price related revisions and reserves decline at total of 8 million barrels primarily at Hastings where we lost 5.8 million barrels. Our pre-tax PV-10 value of the company's reserves using year NSCC pricing 44.60 per barrel of oil and 562 per million Btu for gas at $617 million. Our estimated reserves using year-end NYMEX five year strip pricing is 108.2 million BOE. The pre-tax PV-10 value using that NYMEX five year strip pricing is $1.6 billion.

Now the pro forma year-end 2008 reserves for the sale of Hastings Complex, we get 89.8 million barrels of oil which after subtracting a pro forma 2008 production of 7 million barrels represents a 13% increase from pro forma to December 31, 2007 reserves of 85.5 million BOE. This is a reserve replacement of 161% of pro forma production. Pro forma for the Hastings sale our 2008 oil and refinery development cost, better future, asset retirement obligations were 2549 per BOE.

When you exclude the price related revisions pro forma F&D costs were 1962 per BOE. Our pro forma organic F&D cost which excludes crude to and unevaluated property acquisitions and leasehold costs were 2266 per BOE excluding price related revisions they were 1726 per BOE. We had a good year adding reserves from our California assets and we think that our Texas assets have got some upside that we're going to be looking at this coming year.

With that I'd like to introduce our CFO, Tim Ficker who'll go over the financial highlights.

Timothy A. Ficker

Thanks Tim. Well despite the decline in commodity prices we saw in later half for the year and the tough credit environment we had a really solid year and I'll briefly cover some of the financial highlights.

Our earnings for both the fourth quarter and the full year were impacted by a non cash ceiling write down of 641 million as well as sizable unrealized gains from our commodity derivatives. After adjusting for those items (inaudible) loss on our interest rate derivative and a non cash write off of MLP cost in the second quarter we generated adjusted earnings of 5.3 million for the fourth quarter, which is a 60% increase over fourth quarter 2007. For the year adjusted earnings were a 55.3 million or 176% increase over 2007 adjusted earnings of 20 million.

Our adjusted EBITDA increased to 68.7 million for the 2008 quarter from 53.8 million in the 2007 quarter and for the year adjusted EBITDA increased 42% from 210 million in '07 to 300 million in '08. Oil and gas reserves were 94 million for the quarter which represents an 18% decrease over the 2007 quarter and the decrease was driven by a reduction in commodity prices where we saw a decrease in our realized oil price of over $30 barrel and a decrease in realized gas price of about a dollar per mcf as were partially offset by increases in our sales volumes of 7% for oil and 20% for gas.

For the year oil and gas revenues were 556 million which represents a nearly 50% increase over 2007 and that increase was also largely due to pricing where we saw a 40% increase year-over-year in realized oil prices, a 24% increase in realized gas prices, and we also benefited from production increases of 3% for oil and 22% for gas. LOE per BOE increased about 5% from the '07 quarter, and 12% for the year, and I'll note that the 2008 fourth quarter amount includes the reversal of an LOE credit which relates to the normalization of our inventory levels, which we'd built up at the end of third quarter. Excluding that amount, our fourth quarter LOE would have been about flat compared to the 2007 quarter.

On a pro forma basis, excluding the Hastings Field and adjusting for the credit I just discussed, LOE per BOE would have been 15.32 for the fourth quarter of '08 and 14.32 for the full year. And I'll remind and reiterate what Tim said that our Hastings field was our highest operating cost property with LOE in the high $30 per barrel. As such when we look at our 2009 LOE guidance -- when we look at 2009, which will all include Hastings for one month of the year we're very comfortable with a $15 per BOE guidance.

I'll also note that, we are focused on managing operating costs at our other properties and believe that we will be able to achieve cost reductions there as well which gives us further comfort with our 2009 LOE guidance. Obviously 19,000 BOE a day projected production guidance of 7% or $1 decrease in our per BOE cost would increase EBITDA by 7 million. SG&A increased in both the year and the quarter resulting primarily from a 2.7 million non cash write-off of MLP cost in the second quarter, certain severance costs were recognized in fourth quarter and additional cost associated with increase in the special staff and related infrastructure. On a BOE basis G&A expenses excluding FAS 123 R charges severance cost, and a non cash MLP write off were $4.62 in the fourth quarter and $4.64 for the year. And as with LOE we are very focused on managing our G&A costs closely throughout 2009 and believe our BOE expected in 2009 will be $4.50.

As I previously mentioned in the fourth quarter we recorded a non cash sitting write down of 641 million to the lower year end prices -- low year end commodity prices. We have a very solid hedging program in place and the value of these contracts which is about $90 million at December 31st, was not included in that filling (ph) test calculation because we do not follow hedging accounting treatment for our derivatives.

As a result of the write down however, we revised our 2009 DD&A guidance down to $12 per BOE. Commodity derivatives gains and losses is the other significant component of our income statement, as a result of the significant downward movement in commodity prices at quarter end, we recognized a pretax gain in this category of turning 53 million for the quarter and that amount is composed of $29 million in realized gains and 224 million in unrealized change in fair value derivatives and non cash amortization of commodity derivative premiums. But I should point out that the realized gain of 29 million includes, 21.5 million we realized in December when we restructured a portion of our hedging arrangement. And I'll cover that bit more in just a second.

For the year we've recognized a pretax gain in this category of 170 million, which is composed of a 178 million of unrealized change in fair value derivatives and non cash amortization of commodity derivative premiums and that was partially offset by $61 million of realized losses. So, as I mentioned earlier our hedging program is very solid, as a result of the December restructuring we have a 101% of our 2009 production guidance hedged; over 90% of our anticipated 2010 production hedged and over 60% of our anticipated 2011 production hedged. Net strip pricing our hedges are worth about a $140 million.

Turning to the balance sheet at year-end we had debt of 800 million which consisted of our $500 million term loan, our $150 million senior notes, 135 million drawn under our revolving credit facility and the balance was made up of differed derivative premiums. And as Tim mentioned earlier none of our debt instruments mature before 2011.

It's quite meaningful to discuss our debt and liquidity after giving affect for the Hasting sales and in connection with that sale we proactively saw the re-determination of our borrowing based under the revolving credit facility. And as a result effective with the sale our borrowing base was reduced from 200 million to 125 million. And after applying the sale proceeds of a 201 million, we were un-drawn on our revolver, had paid down approximately 6 million on our term loan and had $50 million of cash on the balance sheet.

Quickly from the liquidity perspective we believe we're in a very strong position. And when we combine that liquidity with our hedging program we believe we're well positioned to face the challenging economic times. I'd like to turn it back to you Tim, I'd also like to point out that we only have two covenants in our credit facilities, our credit ratio and a debt to EBITDA ratio. And we feel very comfortable that we'll be incompliance with both of those covenants throughout 2009 especially given the potential outside we see in production and cost savings. That's a brief overview of the financial section Tim. I'll turn it back to you.

Timothy Marquez

Thanks Tim, let's open it up to questions now.

Question-and-Answer Session

Operator

(Operator Instructions) Your next question will come from the line Joe Allman with J.P. Morgan. Please proceed.

Joseph Allman - J.P. Morgan

Yes, thank you good morning everybody.

Timothy Marquez

Hey Joe.

Timothy Ficker

Hi Joe.

Joseph Allman - J.P. Morgan

Hi. In terms of your reserve revisions on the performance side, it was plus $5 million of oil equivalent. Could you tell us, was that mostly pre-developed or prior than what was that in particular if you can give us that breakdown?

Timothy Marquez

I'll let Gale Wright skilled at our reserves and Gale, let you answer all these reserve detailed reserve questions.

Gale Wright

A lot of the performance -- the reserves that we are seeing in a positive side, they are a combination of the PUDs (ph) that we booked and they are also some the performance that we've seen at West Montalvo and Sac Basin.

Joseph Allman - J.P. Morgan

And of the 5 million barrels, any kind of rough estimate of how much was pretty whether too much all par it was basically or some of the pretty developed.

Gale Wright

I would say its probably about 50-50 at this point.

Joseph Allman - J.P. Morgan

Okay, got you. And then in terms of the price related revision, I have the same question there, minus 11 million barrels of oil equivalent. What would be your estimate in terms of prude developed revisions versus PUDs?

Gale Wright

Again, I have not calculated that exactly. I know that we took about 1.2 million of fixed due to pricing there moved to probable and those were PUDs. I would say which seeing in he 5 million, 6 million cut at Hastings that was all PDP, majority of cuts were in the PDP side.

Joseph Allman - J.P. Morgan

Okay that's very helpful. And then...

Timothy Marquez

We'll send you a little e-mail after this and just update you more exact numbers there.

Joseph Allman - J.P. Morgan

Okay, I appreciate that. And then on South Ellwood, any recent discussions with any of the -- like the California lands commission, or about a timetable when they might actually deal with the South Ellwood extension?

Timothy Marquez

We're looking at, yeah. Yes we have regular conversation with them and we're looking at second quarter of this year, by late second quarter to go to the commission.

Joseph Allman - J.P. Morgan

Okay. Alright, very helpful. Thank you very much.

Timothy Marquez

Thanks Joe.

Operator

And our question will come from the line of Sven Del Pozzo with C.K. Cooper. Please proceed.

Sven Del Pozzo - C.K. Cooper

Yeah, hello. My main question regards the Sac Basin, I just -- what can you tell us about the prospectivity of the region after having accumulated drilling data after an intense year of drilling in 2008 and I'd like to know little bit more about prospectivity of the deeper zones and also regarding the Sac Basin in reference to the rate of return quoted of in excess of 50%, what are some of the key assumptions embedded in that percentage rate of return?

Timothy Marquez

The figure I quoted you say that's solve that question first, that represents current drilling price with a 12 months drift of somewhere close to $5 NYMEX. Now as I also indicated though we expect that to improve during the year as we see in particular steel costs are definitely coming down, they are just lighting to the price we're actually getting right now. Plus we're also just improving our efficiency. So I would expect our drilling cost to come down at least 10 more percent by the end of the year.

So, those economics will continue to get better. And of course I'm not taking into account our hedge price, we're actually receiving over $7 per MCF and we have some positive basis swaps in the Sac Basin typically we probably average $0.10 positive to NYMEX up there. In terms of prospectivity in Sac. Basing, overall this basin just keeps getting better and better. We've we really like the Aspen acquisition comes with not only some nice in field development but they've got nice or exploratory land position, nice big chunk of acreage there. The we've also being doing additional leasing during 2008 or I should say we did it -- quite a bit of additional leasing, we did a seismic shoot in Sac Basin, we're not going into any details where it was in and we really like what we see.

In terms of the deeper zones Sac Basin you are referring to the Glenda (ph) probably -- the Glenda (ph) we drilled probably about 20 wells into the Glenda (ph) to last year and we continue to see good log response good open -- good log response, good positive indicators of gas.

We fracked about five wells last year there, as the good news, bad news situation the bad news is we didn't achieve the results we like to achieve. We had more wells coming in 500 MCF per day post-frac, the other well perform less than that. The good news is I guess not most of our post-frac analysis show that the fracs weren't really fracking into the zone. We were fracking out of zone. I think personally, I think what we're going to need to do in the Glenda (ph) is drill some horizontal wells in the Glenda (ph) coupled with the frac. I mean there's just no doubt there is lot of gas in place which just haven't figured it out how to get it out yet, So we are still very optimistic about that Glenda (ph) and continue to move forward on that.

Sven Del Pozzo - C.K. Cooper

Okay so just to a verify you didn't use the $7 gas price for your hedges in order to come with the greater than 50% internal rate on return on drilling a brand new well in the Sac Basin?

Timothy Marquez

No in fact, give you a little more color there. At current prices generated 25% rate of return it takes about four and a quarter per MCF, again unhedged, that just actual 425 NYMEX gas price at current drilling cost and I said before we expect to get those drilling costs down -- I mean they will come down through the balance for the year. And I think we get -- our economic gas price is judged by a 25% rate of return. We can get that into the by the high threes by the end of the year.

Sven Del Pozzo - C.K. Cooper

Okay I'd like to get in touch with you guys later to little more information on that anyway thanks?

Timothy Marquez

Sure thing.

Operator

And the next question will come from the line of Mike Scialla with Thomas Weisel. Please proceed.

Michael Scialla - Thomas Weisel Partners

That was kind of close. Can I get a diluted share count for the quarter?

Timothy Marquez

I got the Dan's response on that Mike. And I have the annual and I did not get response on the quarterly, so I'll get back to you.

Michael Scialla - Thomas Weisel Partners

Okay. In terms of you're -- the senior notes if you do get that refinanced, is that automatically extend the term loan or are there any strings attached there that...?

Timothy Ficker

It automatically extends it to 2014.

Michael Scialla - Thomas Weisel Partners

Okay. And then what is your current production rate?

Timothy Marquez

We don't give out current rates Michael, what we will say we're very pleased with the how the year is treating us so far. Although now with baseball game, we're in the second innings so we don't want to get overconfident about a victory but we like to way the year start now.

Michael Scialla - Thomas Weisel Partners

Okay fair enough. Can you talk at all about the severance tax issue in California and what impact that might have in your spending if the higher rates get approved?

Timothy Marquez

That appeared to be a done deal. California passed their budget their new budget two weeks ago, and we were left out of that. So there's no impact on severance taxes and you know there's been communities around State -- California is in tough position financially and communities, sort of the small communities, counties are as well, Beverly hills had a referendum to increase the severance tax there and that was be quite heavily 80 to 20. So there people are surprisingly realistic about the negative impacts that higher severance taxes have, so as you recall two years ago state wide referendum that was handily beat, the state wide level with this legislative action there was a proposal, they had increased severance tax 10 % that was beaten down so. we continue to win these battles.

Michael Scialla - Thomas Weisel Partners

That's good. I have got a few more but I'll jump back in the queue, see if anybody else has any.

Timothy Marquez

Okay thanks Mike.

Operator

And our next question will come from the line of Stephen Berman, with Pritchard Capital Partners. Please proceed.

Stephen Berman - Pritchard Capital Partners

Good morning guys. Tim you gave some specific color on costs cost decoys (ph) in the Sac Basin and can you give us some more numbers in -- down in Southern California, what you are seeing there?

Timothy Marquez

You know we don't drill nearly as many wells down there Steve. Sac Basin is a manufacturing process with the hundreds of wells we've drilled there, so it's real easy to see specific cost. We've drilled, I think four wells in Montalvo, so it's really and there are -- there is no true alikes (ph). It's little hard to see. We do see the contact rates coming down. So I expect it will be about inline with Sac Basin. And not only drilling, but as Tim mentioned, we are seeing all our expenses coming down and of course that's nothing new. That's just the way the oil business works. So oil prices -- the oil and gas prices go up, expenses go up. Oil and gas price go down, expenses go down. There is a very well established relationship there and that actually kind of laps.

The other day, we had a -- one of our chemical suppliers proposed a 3% decrease in prices last week and we kind of laughed because kind of fell like they're probably missing a digit, they probably need to be looking at 30% decreases. So, we're seeing all expenses come down. But I would expect Southern California drilling cost to come down, Sac Basin is just lot easier to monitor because we drill so many wells up there.

Stephen Berman - Pritchard Capital Partners

Okay. So, let's talk a little bit more about the Sac Basin in terms of your refracs what you've been seeing there lately, because as good as the economics are from drilling new well and I think the stock we had been even better with the refracs company so can you build into that a little bit more?

Timothy Ficker

Yeah, our most economic projects following the way are recompletion and we're actually going to ramp those up in Sac basin this year. So those are most economic and the fracs as a whole you're right, a very economic that's probably the second most economic play there. We're taking little break right now to realize we fracked over 70 wells last year, and we're using this little bit of slowdown, relative slowdown. I should say it's not-- the guidance Sac Basin write off like its going too slower rather than 3286 six production rigs work over rigs. And so in the first quarter we're not going frac anything. We're going to look at the success as to try and figure out why they went well and the failures, why they went wrong and then get back to frac and later this year.

Stephen Berman - Pritchard Capital Partners

Okay and the balance sheet question is there's no eminent need to do this. But just in terms of your hedges being so far in the money and it's just that your thoughts on possibly monetizing some of those and down any more debt?

Timothy Ficker

We certainly discuss hedges pretty much on a daily basis path to go forward. We are in the process of trying to strengthen our 2011 hedge position even 2012 we're looking at what we want to do out there. We've always been pretty conservative with our hedge and we did reduce some hedges in December. We might just in hedge position this year but I don't think we just monetize, just to monetize; we feel the need to do that Steve.

Stephen Berman - Pritchard Capital Partners

Okay thanks.

Operator

And our next question will come from the line of Jeff Robertson with Barclays Capital. Please proceed.

Jeffrey Robertson - Barclays Capital

Thank you Tim. With regard to the full field development project itself, I believe there were a couple of exceptions mentioned during the Plains hearing under the State law of about granting leases do all qualify of do you think you will qualify for one of those?

Timothy Marquez

Yes. Categorically yes.

Jeffrey Robertson - Barclays Capital

Can you talk a little bit more about where -- which exception do you all qualify for or is it just that re-drawing the state lease?

Timothy Marquez

Yeah. There was a law passed number of years goes its really -- I called that South Ellwood law because its really drafted with our field in minds specifically. And it basically says if, if you can prove that your fields extends are done in acreage. If you are in state list then you can prove your fields extend in state, un-leased acreage. And you can develop that field from an existing platform -- I mean it really describes our South Ellwood operation because that's what the law was passed for. Then the state can grant you that lease extension. And it is important to note, that it isn't a new lease.

As you may know, people follow that story, the controller John Chiang that was one of the things he was concerned about is entering into a new lease. State -- this is a very hot topic in California when President Bush lifted the moratorium on drilling offshore California federal waters, there is a adverse reaction by some people in California, some of the federal politicians and they put a lot of pressure on the State politicians, not to grant a new lease because their position was well how can we tell Central Government we don't want more leasing activity offshore if we are ourselves leasing onshore.

So it's important to note the difference between a new lease and just extending the boundaries on the existing one. The fact is Jeff, we'll give the bulk of model -- we will get the bulk of that oil out from our existing operation. Yeah obviously that would just take us a lot longer, so it really is in everybody's best interest to draw an accelerated, reduces the fuel life and gets rid of the pipe gets rid of the barging operation, reduces emission, generates a lot of money earlier on for the State and a counties so, it really is a very good project.

Jeffrey Robertson - Barclays Capital

Thanks Tim.

Timothy Marquez

Thank you Jeff

Operator

And our next question will come from the line of Catherine Sibolski (ph) with Jefferies. Please proceed.

Unidentified Analyst

Hey good morning, could you go over the price deck that your banks used when they set your borrowing base to 125 and do you expect that there could be a further reduction?

Timothy Ficker

No, Catherine our bank groups they don't all use necessarily the same price decks, but I think its safe to say that they were in low 40s to begin with for '09 and then it escalated up, but I don't think it escalated up significantly. And I think that when we had our borrowing base predetermined in February, 125 million as Tim mentioned earlier we think that that was a conservative number. So I don't think that -- we don't expect to see any decrease in that, in conjunction with our normal re-determination which happens in April and November of each year.

Unidentified Analyst

Okay. Great and on the gas side, was it also a conservative number?

Timothy Ficker

Yes I think it was kind of in low 40's and then 450 for gas, kind of starting point.

Unidentified Analyst

Okay great thank you very much.

Timothy Ficker

You bet.

Operator

(Operator Instructions) our next question will come from the line of Michael Scialla, with Thomas Weisel. Please proceed.

Michael Scialla - Thomas Weisel Partners

Yeah, could you talk a little bit about your Manvel exploration. You did drill an onshore well there and got plans to do anything in that play?

Timothy Marquez

Yeah Mike we're -- we drilled one vertical well and actually had -- half of these results that I repeated over 100 barrel today, don't want to get too specific about because of -- because it is exploratory. We have leased about 100, 000 acres and we been able to get that acreage right where we think the best parts are going to be. You know it's a one of the overlooked resource play's in the country. We are going to drill at least one, probably a couple moderate wells this year.

It'll either be a horizontal well, so a multi stage frac, so give a chance to really evaluate it. Surprisingly as far as we can tell people haven't used what is now I guess traditional type, shell type wells and the big long horizontals multi-stage fracs; just haven't seen that in California. So, we think it's a still got a lot of potential and we can lease in this areas where we know the moderate we've got the lighter oil so, we think we're in the right spot and we're actually drilling our first moderate well this year in the second quarter of this year.

Michael Scialla - Thomas Weisel Partners

And those one to drill this year plan to be horizontal?

Timothy Ficker

Yes. They'll both be horizontal.

Michael Scialla - Thomas Weisel Partners

Okay. And then did you guys ever drill the -- you were looking at the Estoria basin and also down Texas, (inaudible) county. Do you every drill those, exploratory wells?

Timothy Marquez

The (inaudible) County one was just semi-dry. We actually had a good go but then we got just stuck in the hole and we just gave up on that well ultimately. Estoria basin is interesting, we'll have our second well there, don't want to talk too much about it but I guess you can, for something from that going on our second well and we'll be testing our first well here next week.

A: Michael Scialla:} Okay. I guess one last one, you mentioned a little bit about Aspen, and I know you don't want to talk to much about it but, are there any other opportunities in Sac Basin like that to a consolidate up this more?

Timothy Marquez

Yeah. There are...

Timothy Ficker

The big one of course, but they've said that they are not planning on selling. The others drop up and size pretty rapidly, we've done a consolidating. I think our area of upgrade is growth is going to be in additional (ph) leasing both, we can continue to drill in, in field positions just acreage that's expired over the years and then also restart right next to our fields and as I said before I just continued to be very happy with the Sac Basin. It's probably got some of the best economics than anything in, gas in the country.

I mean there's not a lot of plays that work in the high $3 range and the Sac Basin does. Its not exciting stuff for a lot of people but it really works and we will continue to grow that area for many years to come. We're excited about the exploratory potential in the Aspen stuff and the 3D shield we did last year. We're excited about that as well.

A: Michael Scialla:} Great. Thanks a lot Tim.

Timothy Ficker

Thank you Mike.

Operator

And our next question will come from the line of Marianna Kushner with Nomura Asset Management. Please proceed.

Marianna Kushner - Nomura Asset Management

Hi, I just wanted to clarify the Aspen properties. What are the reserves in production associated with it?

Timothy Marquez

Well we can't disclose our estimated reserves at this point Marianna. But we can tell that they are making about 4 million net Mcfe.

Marianna Kushner - Nomura Asset Management

Okay. And then just generally, I know macro question, given that you're comfortable with your covenants. But by my calculation, it's going to be pretty close and seems like it's the year where it's important to preserve liquidity and at the same time you still focusing on acquisitions. Could you please kind of discuss how you're going to balance these two issues, especially since it seems like you, you will be outspending cash flow under current CapEx?

Timothy Ficker

Yeah let me -- there is several issues you bring out there. I hinted that we're well I did more than hint I said that we're, our cash flow from our internal estimates are much higher than the analyst's -- and as long as that just we've given very conservative guidance and as I indicated, we think we can come close to drilling within cash flow, even at a very low price deck. In fact literally its zero dollar oil, zero dollar gas, because of our hedge position, it really doesn't change our cash flow a lot. So we feel comfortable there.

In terms of our covenants as Tim indicated, we feel very comfortable there. I know if you look at our guidance numbers it calculates that its going to be pretty tight but that indicate that we've given pretty conservative guidance out there, so our internal numbers we feel very comfortable with that. In terms of acquisitions you know you are seeing some very strong some very reasonable acquisition prices that we're very conscious of not tripping any of our covenants and we don't we wouldn't want any covenant we wouldn't make an acquisition that would trip a covenant. So without saying too much, you know, you can do the math. We're just, we're not going to be in a position where we are paying six times cash flow for an acquisition.

Timothy Marquez

And we might also mention that we said before that our CapEx program is very flexible and we have certain projects out there that don't have production associated with them that we can dial back if we needed to in order to remain in good credit shape.

Timothy Ficker

Yeah it is worth reemphasizing. I think we've mentioned this before certainly in some of the conferences that we have really no essentially no obligatory drilling to speak of. Our joint contracts are such they're kind of layered in there that if we want to, for whatever reasons start dialing in back we could quite easily. So we're very flexible of course the offshore rigs we own, essentially almost all the rigs out there. So, we're in a very good position in terms of our flexibility.

Marianna Kushner - Nomura Asset Management

Okay, thank you.

Timothy Ficker

Thank you.

Operator

And a next question is follow-up question from the line of Sven Del Pozzo with C.K. Cooper. Please proceed.

Sven Del Pozzo - C.K. Cooper

Yes, just briefly in Aspen's filings you've mention something about just not having drilled very aggressively for quite a while and in production, because of that production is in decline. So, do you intend to increase production from the properties in the near term or are you acquiring it more for the geological qualities or the properties that you feel you can unmark the value latter rather than sooner?

Timothy Marquez

I would say this would fall in the category sooner rather than later. I mean we -- when we make an acquisition we never make it with the idea of just trying to buy something cheap or whatever. We always like something flood (ph) upside like Montalvo where we've come close to tripling production -- well more than double production. We it's a scenario we know well, if you look at where the Aspen acreage is it just fits right in, right in that Southwest corner of Greater Grimes there. So it's, gotten surround (ph) as we know the geology well so we're very comfortable with its acquisition.

Sven Del Pozzo - C.K. Cooper

Okay. Thanks, I give a -- I will call you guys in a bit to ask about the internal rate of return assumptions for the Sac Basin if you don't mind.

Timothy Marquez

Sure.

Sven Del Pozzo - C.K. Cooper

Thank you.

Operator

And your next question as a follow up question from the line of Joe Allman with J.P. Morgan. Please proceed.

Joseph Allman - J.P. Morgan

Yes, thanks again. See a, in terms of the Aspen production Tim gave along 4 million cubic feet a day net did that include Aspen and the other operators assuming that you would be able to buy as much as you can?

Timothy Marquez

That would be through the 100% working interest.

Joseph Allman - J.P. Morgan

Okay. And then in terms of reserves, I know you can't give a number but are the reserves -- are they mostly pre-developed or are they bunch of present (ph) there as well?

Timothy Marquez

I really don't want say too much just I hope you can understand that, we've got about 70% of the working interest signed up and but there is 30% out there and so if I give too much information it will be negotiated against ourselves.

Joseph Allman - J.P. Morgan

Okay. And I appreciate that, thank you.

Operator

And at this time, I show we have no questions in queue. I would like to turn the call back over to Mr. Tim Marquez for closing remarks.

Timothy Marquez

Thanks everybody for your questions and for listening to today's call. We're very pleased with the fourth quarter and full year results. Based on our solid hedging program, a balance sheet and largely un-drawn capacity on the revolver and looking forward strip (ph), we don't foresee any near-term liquidity issues.

We're excited about the opportunities that come to us in a low price environment and we're well positioned to take advantage of these strategic opportunities. You know I have been in the business 30 years and this is the third down cycle I've been through and I just know that this is a great opportunity for Venoco. We did very well in the last down cycle in the late 90s. So I maybe the only guy out there, but I'm very excited about our growth prospects this year.

Even at lower gas prices we're excited about our position in Sac Basin. Last three years we've drilled more than 300 new wells there and many of those wells are now solid work over candidates this year. The near term benefit from selling our Hastings Complex has been great enhancement liquidity. Long-term with successful CO2 PUD, we feel backend is a big addition to reserves and production. There might be that those reserve additions would be at essentially zero cost because we've got carry from tampering (ph) on those. We clearly scaled back our exploration projects this year, but we still believe we have the potential longer term to provide additional areas to the company's funds production and reserves. And I will say we are while the exploration does go back the wells that are drilling there this year, will be some potentially some very meaningful wells.

We are very close to having a final EIR with South Ellwood fulfill development and are cautiously optimistic that the regulatory bodies in California will treat the project fairly. It's probably some opportunity for the state to receive well north of billion dollar in royalties alone, depending on your price for gas of course, and should also benefit for the county of Santa Barbara to receive several $100 million in royalties. Project Ellwood we placed in the pipeline, we place current barging operation with the pipeline and as I mentioned before, it showed a lack of the platform. So there's a lot of good environmental benefits and that was the reason we scrapped (ph) the project from where it is. Thanks everybody for joining in with us today and we will look forward to discussing first quarter results here in a few months.

Operator

Thank you for your participation in today's conference. This concludes your presentation. You may now disconnect. Good day everyone.

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Source: Venoco Q4 2008 Earnings Call Transcript
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