Venoco Inc Q4 2007 Earnings Call Transcript

Mar.17.08 | About: Venoco, Inc. (VQ)

Venoco Inc (NYSE:VQ)

Q4 2007 Earnings Call

March 17, 2008 11:00 am ET

Executives

Mike Edwards - Vice President of Investor Relations

Tim Marquez - Chairman and CEO

Terry Sherban - VP Acquisitions

Analysts

Joe Allman - JPMorgan

Mike Gallo - Thomas Wiesel Partner

Marianna Krishna - Nomura Asset Management

Biju Perincheril - Jefferies & Co.

Ray Deacon - BMO Capital Market

Jim David

Eric Steve - Golden Tree

Gary Stromberg - Lehman Brothers

Operator

Good day ladies and gentlemen and welcome to the Fourth Quarter and Year-end 2007 Venoco Earnings Call. My name is Tanya and I’ll be your coordinator for today. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I’d now like to turn the presentation over to your host for today’s call, Mr. Mike Edwards, Vice President of Investor Relations, please proceed.

Mike Edwards

Hello, everyone. I am Mike Edwards with Venoco. Venoco issued a press release today on our fourth quarter and year-end 2007 results. We also filed our 2007 Form 10-K for the quarter and year with the SEC. On the call today to discuss the fourth quarter 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 the 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 Exchange 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. 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 that geological and engineering data demonstrate, 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 be potentially recoverable through additional drilling or recovery techniques, are by their nature more uncertain than estimates of proved reserves. Accordingly, they are subject to substantial greater risk of not actually being realized by the company.

Forward-looking statements made about the Hastings complex and the option contract with [Denbury] Resources, are subject to business risks and uncertainties not in Venoco’s control. They include but are not limited to the exercise of the option to purchase the implementation of the CO2 flood and the production results and reserves if the flood is implemented. Information regarding results from the hydraulic fracturing program in the Sacramento basin are based on the results to date, which are preliminary. Future results may differ.

All forward-looking-statements are made only of the date hereof and the company undertakes no obligation to update any such statements. Further information on the risks and uncertainties relating to forward-looking statements are set forth in our filings in the Securities and Exchange Commission. The earnings release and the relevant non-GAAP reconciliations are available on the investor relations page of the Venoco website, which is www.venocoinc.com. Now I'd like to introduce Venoco's Chairman and CEO, Tim Marquez.

Tim Marquez

Thanks, Mike, for the gripping overview. Welcome everybody who has called in to listen to our webcast. Today I'm pleased to review Venoco's results. We have a lot to talk about today with the fourth quarter and year-end results, our end of the year reserve reports, and 2008 outlook and activity.

Starting with production, year-over-year our total volumes are up 23% to 7.1 million BOE for the year. When we look at our growth and volume for 2007, we see approximately 27% was attributable to the properties acquired during the year, with the balance 73% resulting from organic growth. The key acquisitions of the West Montalvo field in California and Manvel field in Texas contributed to most of the growth from the acquisitions.

Production was up 11% quarter-over-quarter from last year to 20,100 barrels of oil equivalent per day, and down 3% from the third quarter of '07. This is attributable to both the lack of production we had expected from platform Grace, and delays in completing the Jackson wells in the Hastings field, to complement our increased fluid handling capacity.

For the year, we averaged 19,535 BOE per day, which is slightly under our revised guidance of 19,900 BOE per day. Before we go on, I want to explain the results from platform Grace as an impact of 2008 forecasts. Platform Grace was shut in by our predecessor in 1997 and is still producing approximately 850 gross barrels oil per day.

Our plan to return the platform to production included capital to revamp the process in the production facilities on the platform and re-drill the wells. We selected locations based on historic production, which is well documented. We twined the well locations meaning we milled out the original casing on the new well via the short systems within about 100 feet from the bottom of the original locations.

On the first well, we bottomed slightly deeper than the original well and believe we crossed the fault that channels a large volume of water into the well and overwhelmed the production. Because these completions are gravel packed, it's nearing possible to attempt to shut off the bottom water. The better alternative would be to re-drill the well. On the second well, we reached our target and completed the well within production. Initially our good result was making over 200 barrels a day and trending higher. Unfortunately, the casing collapsed in the well and we lost all the production. This is a surprise, as the field did have a history of clayed casing collapses, so we couldn’t anticipate this loss of the well.

The third well we drilled is -- clearly would have been the best well in the field. When we completed the well, it was better than anticipated, but is currently making about 80 barrels per day and increasing slowly but truly. But as of twin of the best one of our field, we expected at least -- production to have been at least 200 barrels of oil per day. After these three wells, we are planning to move in the rig to platform Gail. With our initial results we decided not to spend additional capital on Grace. We did a complete review of both the geology and the engineering associate with the project.

We backed it out all of our production from Grace out to our 2008 guidance. Although the project is still economic, we currently believe that at least as far as planning goes, we have to re-drill about 50% of the wells for optimal production. We think we have better placed investor capital at this point and want to see the results from our project review.

As we previously disclosed, in early February our 2008 production guidance is for 20,500 to 21,500 BOE per day. We know one of the biggest improvements we can make to share is managing expectations and meeting our guidance. We believe we have been conservative in setting this production guidance and are very focused on meeting our (inaudible).

Moving on to reserves: Our net-proved reserves were 99.9 million BOE as of December 31, 2007. This represents an increase of 14% over year-end 2006 reserves, which were of 87.9 million BOE. The company’s 19.1 million BOE reserve increase replaced [269%] of 2007 production. Finding and development costs for 2007 were approximately $23.51 per BOE, based on expenditures of $450 million including the acquisition.

Proved reserve value more than doubled to $2.4 billion to pre-tax. The CapEx investment platform grades on the facilities' work in Hastings did not result any material production or reserve as in 2007. In fact, in platform grades Santa Clara field we actually wrote down a 0.5 million barrels related to this field. We added approximately 11.9 million BOE from acquisitions for a $140 million per BOE cost of about $11.80 for BOE.

Capital expenditures for the year starting with fourth quarter capital expenditures were about $84 million, with approximately 43% in Sac Basin, 29% expense in Coastal California, and 20% in Texas. For the full year, our capital expenditure with acquisitions was about $450 million. We increased the CapEx budget in the fourth quarter to complete as much of the fluid handling facilities, water injection, and well conversions in the Hastings fields that we could by year-end. Some of the water injection well conversions had to be completed in the first quarter of 2008.

By completing most of the capital intensive work in 2007, we are able to reduce the CapEx for 2008 and expect to see continued production increases at Hastings this year. We spent an unusually large amount of CapEx on facilities in water injection in 2007. These projects are expected to yield production beginning this year. Our capital expenditure forecasts for 2008 remains flat; it remains at $235 million.

We had approximately $80 million in the budget for Grace, but these would be reallocated to other California projects, mostly to the Santa Clara field. Of the 2008 budget, approximately $130 million will be spent in the Sacramento Basin, $70 million in Coastal California, and $35 million in Texas.

We estimate $185 million will be spent on development drills; development drilling and well work, $25 million for facilities and $25 million on exploration. Though we continue to actively pursue acquisitions, we don't forecast expenditures for acquisitions. 2007 production expenses in G&A costs for the full year, production expenses averaged $16.74 per BOE, 11% above full year 2006 of $15.09 per BOE. We expect production expenses to decrease on a BOE basis in 2008, as a whole. This was due to reduced remedial activities in the Hastings complex and production volume increases from the Sac Basin, West Montalvo, and Manvel fields in the Hastings complex.

Full year 2007 G&A expenses were $4.46 per BOE, down 9% from full year 2006. Excluding FAS 123R charges, the company expects G&A expense in 2008 to be similar to full year 2007 on a per BOE basis.

Now, well individual field performance: Starting with Southern California, in the South Ellwood field, we are waiting to receive the draft EIRs, the environmental impact reports, which have been completed and are under review by the state lands commission, that is the California State Land Commission, prior to public release. After the draft EIRs release, the next part of the process is that the other agencies and the public will review the adequacy of the report and submit any comments prior to finalizing it. So, this will be ongoing throughout 2008. The report could be finalized around the third quarter and the approval process will begin with the board jurisdictions that are involved in the project.

We don't anticipate being through the approval process until some time in 2009 and the project will start immediately thereafter. The development program consists of extended reach wells drilled into the eastern portion of the field from our existing platform in the field; platform Holly. The project will actually reduce infrastructure on the coast by replacing the current barging operation, which currently transports our crude oil to market with about a 10-mile long pipeline. The new pipeline will connect the existing segment of all American pipelines near Exxon's Las Flores Canyon facility.

Talking about this [barging], this may not seem like such a significant thing to those who are not in California, but this is the last barging operation in Southern California, and it has been long sought after by the community to eliminate the barging. We've actually initiated certain capital expenditures in preparing pipeline [rideways] in anticipation of the approval of the project, which will be ongoing throughout this year.

Moving on to West Montalvo: Since acquiring the field early May, we drilled a new well from an onshore location to another offshore target. We reactivated injection wells to handle additional fluid volumes from upcoming development activity and repaired the work over several production wells. We've permitted, procured and are installing new artificial lift equipment related processes and facilities, which will handle production increases reactivating currently idle production wells in the field. We saw some production on the first group of these wells in the fourth quarter and we will bring on additional wells throughout 2008.

Regarding the [South Ell] field, as I mentioned before, we are going to allocate increased capital from the capital that we are no longer going to spend on platform Grace, Santa Clara field. We allocated that over to (inaudible), and most of these are related to our water flood. The water flood continues to work well. We are seeing additional responses from some of the producers, and in some cases, we have to actually let the submersible pumps feel that they can handle and take advantage of the water flood.

We are also be doing some water-injection work, adding some new water-injection locations during the year. So, nothing major excitement with that Water flood, its (inaudible) continues to perform quite nicely.

Moving to Texas, both our Hastings complex and nearby Manvel fields that we acquired last year were very active. We focus both fields on returning well production, converting gas of wells to ESPs that (inaudible) and adding fluid process and injection capacity. Our experience in Hastings is a great benefit to our re-completion work over activities in our Manvel field.

In the Hastings field, by the end of 2007, we were able to get capacity of our fluid handling facilities almost 500,000 barrels per day. So the surface equivalents cable was 500,000 per day, which is up from 150,000 barrels a day capacity from when we took over. So this is a major project.

As I mentioned, we are finishing up on the injection well, and it will allow us to dispose of resulting water. Currently, we have water disposal capacity of about 325,000 barrels a day. We have been able to bring additional wells onto production as each injection well is completed for continuing increased production from the field. The five-well program to evaluate the potential upswept and residual all that we have initiated early in the year isn’t attractive as the simpler RDT works. We are getting a lot more bank for work with return to production work and we will focus on that during the year.

We currently have about 200 wells idle in the field, so plenty of upside -- opportunity there. We continue to have discussions with Denbury Resources regarding their options for the Hastings complex and the implemented field two enhanced recovery project. We did receive the second installment payment on the option in the end of last year, bringing the total we received to $45 million of the total $50 million option price.

The final payment is due in November this year. Denbury can exercise the option in either November of this year or November of next year, so we continue work with technical staff to refine the development and plan to coordinate activities in the field. Denbury recently indicated the max size of option this year. They anticipate their CO2 pipeline will be ready to deliver CO2 in late 2009. Assuming they exercise the option, we have the choice of either selling them the property for cash, based on PV10 of the reserves, or enter into a volume-metric production payment arrangement. That being said, we're leaning toward taking the cash option. To give you some idea what this can mean, based on the formula on the agreement and using our 12/31/07 reserves, the sell-price would be more than $300 million after netting out some below market hedges. In other words, the sell-price is higher, but there is some below market hedges that accompany that production which nets it out to sell-price in excess of $300 million.

We expect our work in complexes this year will be able to drive higher proved reserved numbers in sell prices. Following Denbury's purchase of the field, Venoco will retain the overwriting royalty interest of 2% of the property. It will then back into working interest of approximately 22.3% in the CO2 project after Denbury recoups various costs and expenses. Denbury’s has shown publicly the CO2 project having a PV-10 value to them of about $1.7 billion, so that is $1.7 billion net to Denbury.

If we look at the CO2 flood, we have been able to recover 10% to 20% of the original oil in place, and our proportionate share at the low-end of the reserves would net us about $30 million barrels. Based on reserve values that you can calculate from our year-end 2007 reserve reports, 30 million barrels would have a PV-10 value of a little over $700 million.

In the nearby Manvel field, production is up slightly in the fourth quarter, as we continue to implement our work-over and re-completion program. Like in Hastings, our main focus is on increasing our fluid processing and injection capacity. We will continue to evaluate the field on a long-term basis with CO2 opportunities, since Manvel has the same geological characteristics as the Hastings field. We had discussions with several potential CO2 providers and are encouraged by the apparent number of opportunities for CO2 coming into the area.

Finally that brings us to the Sacramento Basin where we have some very exciting information to discuss. Since I returned to the company in 2004, we have increased our lease position, primarily in the Grimes and Willows areas almost seven-fold from about 30,000 net acres to over 210,000 acres. Over the last two years, we have drilled over 200 wells to further delineate the place, prove out more 40-acre infields, test 20 acre in-fields, and test other horizons.

We now believe that the two key potentials, based on internal estimates of the Sacramento Basin, are 500 BCF to 800 BCF net to Venoco. That compares to our current proved reserves of about 166 BCF. Needless to say, we are very excited about the potential in this basin. Our drilling and work-over program continued at full speed throughout the fourth quarter.

For the year, we spud 27 wells in the Basin and completed approximately 113 work-overs and re-completions. We continued to get more efficient in our drilling completions. So we are now drilling with five rigs and we will be able to drill roughly the same number of rig/wells of five compared to last year's six.

We are very encouraged by the initial results of the frac program that we kicked off in the fourth quarter. If you remember our call last November, we had just fraced our first three wells and had excellent initial production rates. Now, we not only have three months of production data from those two of those wells, we also have initial results from another dozen wells we have fraced since them. A typical completion in the basin, and particularly in our Manvel Willows and Grimes, there has been a set casing portrait to put the wells onto production naturally.

The majority of \ wells we produced are not completed in a big channel sense, rather into a thinner over bank and lenticular sand deposits. These sand lands are small, and in many instances covering only 10 to 20 acres. By perforating four to six holes per foot, we hope get the majority of these lenticulars. But from quarrying these wells, we know that we could be missing some of the thin sand intervals. We fraced, we not only hope to reach out for the well bore horizontally to connect more of these lenticulars, but also to reach vertically to capture these thinner zones that could lost behind pipes.

Let me show you some of the recent statistics based on production results to-date. Based on these results, we believe that 40-acres of wells that fraced has yielded about 0.65 BCF per well. All these figures by the way are net after royalty. So, 0.65 BCF per well for 40 wells acre that is fraced, and that's up significantly from 40-acres wells without the frac.

For the 20 acre wells, by the way, we have drilled now 25 20-acre in-field wells. We estimate that we would frac these wells will yield of about 0.5 BCF net per well. Our frac re-completions of our (inaudible) or existing wells are about 0.16 BCF net after royalty per frac. All and if you include all these projects 40 acre wells, 20 acre wells to be in field fracs of regular natural re-completions all development, costs a little over 250 per MCF. We have well over 2,000 projects in total that include the 20 acre wells, 40 acre wells and all the re-completion opportunities.

As we discussed, our focus over the last few years has been intel drilling on a 40 acre basin and initiating 20 acre into a program beginning to evaluate other formations. Now, that we have encouraging frac information to add our valuation in field and the basins, we now know that this is best way to develop the field. We will have to consider the drainage that we are able to achieve by fracing. Until we have better longer term data, we will continue with our current development plans and tracking programs. But we initially budgeted about 12 fracs in 2008. We have seen our costs coming lower than estimated and shifted some dollars to increase the budget for fracs.

Currently, we have 20 to 50 fracs budget for 2008, but if we continue to see the same positive results, we have unallocated dollars in the budget. The budget I mentioned before, the $235 million, we have unallocated dollars in that budget to frac up to 100 wells this year. We have over 500 wells currently in the basin, and over 410 of them are active. So, we will be aggressively moving the frac program forward to unlock the potential of the field. Many of these wells have multiple fracable zones, so we have very large inventory projects.

It is important to note that we do not have any reserves in the field attributable to these types of formations. A successful frac program can add a significant amount of reserves to our fields in the Sac Basin. All in all, we continue to be very excited about our core operations in the Sac Basin, as well as the tradition opportunities we see in our down space and frac programs, and evaluating other [rest costs].

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

Tim Ficker

Thanks Tim. I will take just a few minutes to cover some financial highlights from the fourth quarter and the full year of 2007. Our adjusted earnings were $6.2 million for the fourth quarter and $26.9 million for the full year of ’07. We have reported net losses for those periods of $60.4 million and $73.2 million respectively. But after adjusting for the after-tax effects of non-cash commodity and interest rate derivative losses, and loss on early extinguishment of debt from the second quarter, our adjusted earnings were the amount I just mentioned.

Adjusted EBITDA was $211.9 million for the full year of ’07 and $54.6 million for the fourth quarter of ’07. Both of those were up $45% from their corresponding 2006 periods. Oil and gas revenues were $337.9 million for the full year and $116.5 million for the fourth quarter of ’07, which both represents significant increase on a quarter-to-quarter and a year-over-year basis. Those increases are largely due to our production, which was up on an annual basis from 5.8 million BOE in ’06 to 7.3 million in ’07. We have also benefited from significant price increases which is were up about $8 per barrel and almost $0.60 per MCF.

The interest in production came from our organic growth in significant areas of operations as well as our acquisitions earlier in the year. I will mention, in the fourth quarter we recognized a slightly negative impact from one of our accounting adjustments, which lead us some earlier -- to one of our earlier acquisitions. We recognized about 130 barrels per day adjustment, like to adjustments.

The other significant component of our revenue section and our income statement is commodity derivative gain losses. In April you might recall that we discontinued hedge accounting for our commodity derivative contracts, which we knew might increase volatility in our income statement. As a result, there was a large movement in oil prices in ’07, and we have recognized a loss in this category of $147.3 million, compared to a loss of $2.4 million in ’06. Significantly I will note, however, that $122.9 million of the ’07 loss is due to the unrealized gains in fair value of derivatives and $11.5 million is due to a non-cash amortization of commodity driven premiums.

Production expenses increased from $87.5 million in ’06 to $119.3 million in ’07. This reflects the increase in the number of properties we operate as a result of our CapEx program and acquisitions, as well as the effects of our work over programs.

We expect that our production increases will decrease on a per BOE basis for 2008 as we reduce remedial activities in the Hastings complex and achieve production volume increases in Sac basin, West Montalvo and Manvel fields and the Hastings complex. G&A for the year was up slightly on an absolute power basis to $31.8 million in ’07 from $28.3 million in ’06.

During ’07, we increased our professional staff and related infrastructure to keep pace with our growth. We also recorded approximately $1.3 million related to settlement of employment contracts. Those increases were partially offset by an increase in the proportion of G&A that we capitalized as a result of the increased exploitation development and acquisition activities. On a BOE basis, G&A expenses, excluding FAS 123 charges, decreased about $0.56 from 441 -- $4.41 in 2006 to $3.85 in 2007. For 2008 we expect our G&A to be similar to ’07, on an absolute dollar basis, excluding the FAS 123 charges.

On the DD&A side, the biggest drivers in our $35.5 million increase from '06, but the increases are full costs, resulting from our acquisitions, early in the second quarter and our CapEx program.

Turning to the balance sheet, compared to year-end 2006, the items to note were increases in our (inaudible) debt, which were both up as a result of our 2007 CapEx program and acquisition. In addition, in July '07, we completed our secondary offering where we sold about 6.6 million common shares for net proceeds for $116 million.

We used the majority of those proceeds to pay down the outstanding balance in our revolving credit facility. Regarding our debt, I'll mention that in the context of our overall business strategy, we'd like to see our debt level in the 2 to 2.5 times debt-to-EBITDA range. When you consider our expectation for 2008 production growth, Op costs, and CapEx, along with our hedging profile, we believe that we can hit that target.

In addition, without considering acquisitions, when we factor in the estimated proceeds from the sale of the Hastings complex that Tim mentioned earlier, we believe we could see significant de-leveraging over the next year or so. That's a brief overview of the financial section.

Tim, I will turn it back to you.

Tim Marquez

Okay, now we would like to open to questions.

Question and Answer Session

Operator

(Operator Instructions) our first question comes from the line of Joe Allman with JPMorgan, please proceed.

Joe Allman - JPMorgan

Hey, good morning everybody.

Tim Marquez

Good morning Joe.

Joe Allman - JPMorgan

Hey, Tim, just to clarify, did you say that Denbury is leaning towards exercising debt options this year?

Tim Marquez

Well what they've said publicly as they intend to start injection by the end of next year, when asked the question, does that mean they exercise this year, they basically said so many words yet.

Joe Allman - JPMorgan

Okay that’s helpful. And then going back to the Sac Basin. So far it sounds like you have drilled up to 15 wells or you have re-fraced 15 wells?

Tim Marquez

We’ve fraced, not re-fraced, but we've fraced 15 wells, correct.

Joe Allman - JPMorgan

Alright. Okay, fraced 15 wells. And then, are those all new wells or could you break out how many are new wells, how many are kind of just going into the small well bores and fracing those?

Tim Marquez

Albeit, a couple of those were old well bores, but we have fraced two or three relatively new wells. But even those are wells that we drilled earlier last year. So they weren’t brand new fracs upon on initial completion.

Joe Allman - JPMorgan

Okay, and so with just a drilling program down there. You said you’ve drilled 25 wells down the 20-acre spacing. So, have you tested the fracs on any of those 20 acre wells?

Tim Marquez

Yeah, we’ve actually fraced a couple of the 20 acre infields and not surprising, the frac results are working well there. What we think we are seeing, Joe, as we try to explain is, I think we’re getting several benefits from the fracs. We have all this thinly-laminated sand. Like thinly-laminated sands, these are a quarter inch, half inch beds and if you are shooting four to six holes per foot, you are clearly going to missing some of those thin beds. And the vertical perm in those beds appears to be very low.

So by fracing, you’re going to counter all those thin beds. You’re also fracing out into the formation and encountering some lenses that aren’t even connected to the well bore there, and of course some information is just tight. We have a number of times when we re-complete the well that makes a 50 MCF, a day and it will have 2,500 pounds of pressure. So give pressure low rate and so we are getting several benefits out of fracing these wells. So we are very excited about the whole thing.

Joe Allman - JPMorgan

Got you. And you said you've got, you have about 500 wells that have been drilled in the field, 410 that are active and I guess most of those are down the 40-acre spacing. Is that right?

Tim Marquez

Yeah. I don't have exact calculations; yeah most of those are down 40 acres.

Joe Allman - JPMorgan

Okay. So it sounds like out of the 2,000 projects you have. When you said 2,000 projects, I think you mean, I think you meant 2,000 frac projects. So could you give us a breakout like that 2,000 means how many 40s, how many 20s and so forth?

Tim Marquez

Yeah. I'll give you an idea on that exactly I should say it's to supposed to be 3,000 projects, but to give an idea to explain that and we'll provide full in depth details in future conferences but to give you an idea we've about 100 to 150 wells on 40 acres basins that we think it would be completed without fracing. Another 175 to 300 wells, 40 acre wells would be completed with fracs. We've about 100 to 250 20 acre in-fills] that could be completed naturally and that’s made 250 to 400 wells, 20 acre wells would be fraced. We still have about 15 to 1,800 work over. So keep in mind some of our wells have multiple re-completion intervals. So 15 to 1800 workovers are now to completions. Another 4 to 550 wells of our vintage wells are existing wells to be fraced roughly one, one zone per frac, which I think is conservative and then we have approximately 100 plus delineation wells .We are still - this is an expanding area and we continue to do something that's what do you call the exploration delineation whatever, just still proving up some of the fringe areas and have some very nice results there.

Joe Allman - JPMorgan

Okay so in terms of incremental location to frac, it sounds like it's 425 to 700, just using kind of this -- what do I…?

Tim Marquez

Of new locations, the 425 on a high end it would be 700.

Joe Allman - JPMorgan

Okay.

Tim Marquez

Plus delineation wells.

Joe Allman - JPMorgan

Okay got you. And then lastly, so you said the 40-acres you are estimating 0.65 Bcf per well the 20 acres 0.5 Bcf per well and what was the 0.6 Bcf per well? Can you help me with that?

Tim Marquez

0.16 was the vintage well. The existing well per zone we think we added up 0.16 Bcf per zone.

Joe Allman - JPMorgan

So the 40’s and 20’s, those estimated reserves would be we just on new wells, right?

Tim Marquez

Those 40’s and 20’s that I mentioned are just on new well that are fraced right?

Joe Allman - JPMorgan

Got you, okay. And then okay and then again sort of delayed with this here, but the number of locations you mentioned say like the 175 to 300 was fraced. Is that just new locations or that would include going in to some of the old well bores?

Tim Marquez

That's new and I’m sorry, I know it’s a lot of information to throw out, but we have been very busy but that would be a 175 to 300 new 40 acre wells that would be fraced.

Joe Allman - JPMorgan

Okay, so any kind of going in the old well bores and fracing that would be incremental to these?

Tim Marquez

Right that. I quoted the number 400 to 550 vintage well fraced.

Joe Allman - JPMorgan

Okay. Got it, got you. Okay, good enough from me, I'll get back in the queue. Thanks.

Tim Marquez

Okay. Thanks, Joe.

Operator

Our next question comes from the line of [Mike Gallo] with Thomas Wiesel Partner. Please proceed.

Mike Gallo - Thomas Wiesel Partner

Good morning, guys.

Tim Marquez

Good morning, Mike

Tim Flicker

Good morning, Mike.

Mike Gallo - Thomas Wiesel Partner

Question on West Montalvo, that extension well that you drilled, did you see oil water content in that?

Tim Marquez

Not to say that the safety is kind of like our Forbes formation in Sacramento basin, it's very, very thick, it can be well over 2,000, 3,000 foot thick and multiple reservoirs. Some inner wells are less, but they are [web tie on] structures. So, there is no real easy way to answer that question, since we've really literally had many, many dozens of reservoirs. But I would say, all-in-all, none of the major sands were watered down on the wells.

Mike Gallo - Thomas Wiesel Partner

So expect to be able to extent further, it sounds like with the some…

Tim Marquez

Yeah, it was encouraging, as we've talked about before, unfortunately we don't have good 3D coverage over the field, although we intend to shoot to 3D over the onshore portion. It will give us some information about the offshore portion. We are trying to bid blind, kind to do in the delientation in the old fashion way, just one location at a time.

Mike Gallo - Thomas Wiesel Partner

Okay. And then your PV-10 value at Hastings was quite a bit higher than I had expected. Could you say what the proved reserves were associated with the field now? And where do you think that could go if you get all these 200 odd wells back on line?

Tim Marquez

Well, the proved reserves are what Terry.

Terry Sherban

Terry Sherban, 14.5 million BOE.

Tim Marquez

14.4. Of those we only added four returned to production wells and we got credit for those. Those are about 40,000 net barrels per well. And how many of the 200 we get credit for, I don't know. Obviously, our intent is not to give away any values. So we are working hard on returning those well to production as best we can.

Mike Gallo - Thomas Wiesel Partner

Okay.

Tim Marquez

I am trying to -- happen to make a few bolder production but we think there is significant upside potential to those proved reserves. Again, we only have put four of the 200 wells in our year-end reserve report.

Mike Gallo - Thomas Wiesel Partner

That gives me the idea. Thanks. And then on the second on the basin, what do you think you would take to get credit for with your reserve auditors on some of these opportunities and finally in terms of the downspacing, the fracs and even the re-completions.

Tim Marquez

Yeah that's Mike has always been one of our frustrations, one of the battles is just getting credit for the work we do. I don't know. After all these years, having drilled 200 plus 40-acre wells. We do get credit for -- 40-acre wells we get pretty good credit. I'd say we would probably get 50% credit for the future. The remaining 40-acre wells, we've always been very frustrated that our re-completions, we virtually get zero credit for those, even though we've by now over the years, we have re-completed right around 400, or to mention 400 wells. It is frustrating.

The problem with it is when you look at pay there, it just doesn't calculate as pay. And so it's -- we've been very comfortable and gotten good at identifying what is pay, but it's just uncalculated pay. We will continue to work with D&M issued on it. I think they are open-minded in looking at it; they are conservative, which is okay.

It's just something we just kind of have to work on. I don't think we will ever be at the point where we'll get a 100% credit. It will be a major step forward if we get 50% credit. So all I can say, we are very focused on it and we know that we are in a sense given a way some value not by giving that credit and we are very focused on trying to get reserve auditors to understand that. We have made progress over the years just not as much as we like.

Mike Gallo - Thomas Wiesel Partner

Understood that thanks. That's all I have. Thank you.

Operator

Our next question comes from the line of [Marianna Krishna] with Nomura Asset Management. Please proceed.

Marianna Krishna - Nomura Asset Management

Hi, I was wondering if you could provide some sort of bridge for per unit production cost from third quarter to fourth quarter, just so that we understand, what were the major factors that impacted production costs?

Tim Marquez

Yeah Marianne, I think that we incurred a lot of costs, we were trying to accelerate a lot of our activities into the fourth quarter. At Hastings, we incurred significant amount of expensed work over costs out there in the fourth quarter, again, just trying to get ready to go into '08. In addition, I think we incurred some additional cost bringing our work over programs at Montalvo and at Manvel and so on a per BOE basis, we certainly saw some increases, but we expect that to go down in this coming year as we see production increase there as well in the Sac Basin.

Marianna Krishna - Nomura Asset Management

Could you provide a more specific guidance for LOE cost for '08?

Tim Marquez

As far as what our LOE will be?

Marianna Krishna - Nomura Asset Management

Yeah. Your guidance (inaudible).

Tim Ficker

I think previously we said that it was in the 13, 15 BOE and I think that was when we put out our guidance in November.

Marianna Krishna - Nomura Asset Management

But since then those items has decreased, so would we expect, LOE would be safe, somewhat higher?

Tim Marquez

You know, I think that it probably would be somewhat higher. I think we'll have to get back to you in probably in our next presentation. I'll just have to sort of go back with you on that.

Marianna Krishna - Nomura Asset Management

Okay. Thank you.

Operator

Our next question comes from the line of Biju Perincheril with Jefferies & Co. Please proceed.

Biju Perincheril - Jefferies & Co.

Hi, good morning. Can you give us the -- you had some reserve revisions on the natural gas side. I think it was negative, and you also had some positives. Can you give us some details on how much was it price-related and how much was it performance related and in what areas?

Tim Marquez

Yeah, I'll let Terry Sherban answer that question. Terry is the one who handles our reserves.

Terry Sherban

Some of the oil clearly was -- we had positive revisions due to price-related issues. Some of the negative revisions on the gas were just adjustments on GOR type of performance-related issues. I guess I'm not sure how specific revisions due to some of the 20 acre stuff and other extensions was about 2 million barrels, that was all gas in the Sac Basin of course. I don’t know if that's answering the question. In the revisions, you've got pluses and minuses all over the place. However, the oil properties clearly had some impact due to price.

Biju Perincheril - Jefferies & Co.

Okay. So is it fair to say essentially all of the oil price -- the revisions on the oil side was price related?

Tim Ficker

1.5 million barrels was due to pricing.

Biju Perincheril - Jefferies & Co.

Yeah.

Tim Ficker

There is about 3.5 million barrels due to other revisions.

Biju Perincheril - Jefferies & Co.

Okay, okay.

Tim Ficker

But in those other revisions there were negatives on the GAAP as you indicated, they went up and down.

Biju Perincheril - Jefferies & Co.

Okay, okay, and then, can you say what's your production is averaging currently?

Tim Marquez

We are running little over 20,000, so we've been fairly flat with the fourth quarter so, posted around 20,200 to 20,300.

Biju Perincheril - Jefferies & Co.

Okay and then, at Hastings, I think you mentioned 200 wells that could be brought back. How many are you planning to bring back online this year?

Tim Marquez

We have about 40 in the budget.

Biju Perincheril - Jefferies & Co.

Okay and what are the incremental rates that you get from those wells?

Tim Marquez

On average, those RTPs, average around 15 gross -- 12-13 net barrels a day so, on the individual basis, they are not very exciting but when you add them together they work.

Biju Perincheril - Jefferies & Co.

Okay. Perfect. Okay, I think, that's all I had for now.

Tim Marquez

Thanks Biju.

Biju Perincheril - Jefferies & Co.

Thanks

Operator

Our next question comes as a follow up from the line of Joe Allman with JPMorgan, please proceed.

Joe Allman - JPMorgan

Yeah, Hi again everybody, just back to the LOE cost question, so it sounds like the fourth quarter is probably too high. But it sounds like your prior gone just might be little bit low. You just confirmed that, and I guess one of the issues that you described for the cost going up in the fourth quarter is just accelerating activity. And it sounds like, at Hastings, for example there is still an acceleration going on so, that's probably not going to decline but could you discuss like, what type of remedial work did you do in the fourth quarter that you probably are not going to be doing in 2008?

Tim Marquez

Let me answer the LOE first. There is many parts to that question you could have the second part [in that]. On the LOE there is a few factors on at on the one hand though shelving the Grace project, those are higher expense barrels and so that won't necessarily have an impact. On the positive side the gas project Sac Basin those are low cost barrels so to speak. And so that tends to drive it down what we are doing right now is just really revising all our forecast. We don't think the production numbers is going around with the expense to move around, I don't think it's going to be a significant if there is an increase I don't think it will be significant, but we want to just for right now reaffirm that guidance until we get all these numbers straightened out and see how many, we want to project how many fracs we are going to be doing for the year which could have a significant impact. So, we will have these updated numbers in any visions if there are any in fact here in a couple weeks, but right now we are holding that at 1350

Joe Allman - JPMorgan

Okay, just holding that. And I guess in terms of remedial work that you did in 2007, especially in the fourth quarter what you are going to do less of it in 2008?

Tim Marquez

We are going to do less overall water injection but we spend a lot of money on water injection both on -- well a huge amount on surface facilities on and Hastings and less it would be a lot of work on the disposed wells. The first quarter this year was continued to spend quite a bit on the water disposable wells and Hastings and then that will start to taper off and focus more on just purely production related activities in Hastings.

Joe Allman - JPMorgan

Okay. And those costs were LOE costs rather than CapEx?

Tim Ficker

They were a mixture, okay got it.

Joe Allman - JPMorgan

It was a mixture, okay got it. And then just back to Hastings. Two things one so at some point, like in October, I would say October 31st or is are you folks going to do a full reserve report for the Hasting field just so you get a kind of an up-to-date PV-10?

Tim Marquez

Joe the way the contract for December is to stop our year-end reserve report. So it would be a 12/31. Our usual reserve process, we start a little bit earlier than that probably August, September, October and probably get all the data and that sort of stuff and prepare that report. But it wouldn't be anything different than what we do typically.

Joe Allman - JPMorgan

So the activity at Hastings, does it pay for you -- I'm just trying to think it through. Does it pay for you to do a whole lot of activity at Hastings or is the volume of reserves pretty much determined already in terms of the sales price?

Tim Marquez

No, it would be at year end at the end of this year December 2008.

Joe Allman - JPMorgan

Okay, in 2008 okay. So the sales price if they exercise their option November?

Tim Marquez

That will be the 12/31 2008 reserve report.

Joe Allman - JPMorgan

Okay. Got you. Okay so there is incentive try to increase the value as much as possible?

Tim Ficker

Exactly.

Joe Allman - JPMorgan

Okay. And then you folks mentioned earlier on about kind of an offsetting hedge the PV-10 dive was a higher but I guess there is you are deducting a hedge, can you kind of give us the details on it? For hedges?

Tim Ficker

Yeah. You can look at our hedge schedules. I am going to give you the detail of what we are going to adjust with. But we are hedged in sort of PDP right now so should we sell a property likely basis still temporary would be able to get some hedges there to be appropriately hedge. Now there is a lot of other factors that go into, we've new reserve report at the time, we might have different hedging characteristics in our financials and some other things. But I guess we want to indicate to people they are probably a component of get rid of some of some hedges at the same time as the sale.

Joe Allman - JPMorgan

Would you allocate that proportionately, Hastings against that your total oil production in the Hastings hedges versus total oil hedges that would be proportionate?

Tim Marquez

What we've assumed in there Joe is the number we gave here is that our low prices lost to the ones that are included in the there are the ones those who want to or put it in place at the time we did the Hastings transaction. So those are the ones that have been calculated in there. Keep in mind all this has to be negotiated in their strait office if Denbury has got to accept for they are getting for some reason he didn’t like those bulk price slots and we can put in some of the higher priced ones but then there would be of corresponding increase in the purchase price. So lot is still to be negotiated, we wish we could say concretely this is exactly what it is but it’s the devils and the details.

Joe Allman - JPMorgan

Got you okay good. All right Tim but you didn’t introduce Bill, I never heard his voice answering the question, alright thanks guys.

Tim Marquez

Okay you are welcome, he was the other management.

Joe Allman - JPMorgan

Got you.

Operator

Our next question comes from the line of Ray Deacon with BMO Capital Market, please proceed.

Ray Deacon - BMO Capital Market

Hey Tim, I had a question on Montalvo, I guess is there anything else left to do there before you get the 3D and what do you see is has your view on probable reserves that have changed as a result of this first well.

Tim Marquez

No we are very encouraged by the first well, we put it on pump on in the fourth quarter, the pumping you know was undersized, we just last week put a bigger unit on it. The well was making close to 200 net barrels a day, net after royalty production. But we have a big unit so it too early to give results and we should start seeing that production come in, there should be a significant increase. So, we are very pleased with the results of that first well. We actually have a lot of work planned even before the 3D. We have at least a couple more wells to be drilled this year and then a lot of return to production work, and then recompletion works. So we're getting good results out of -- in a lot of ways this is somewhat analogous to the Forbes formation. Up in Sacramento basin, we have the massively big zone, it hard to identify exactly, the thin bedded reservoirs what is pay, what isn't. So, we've being popping more holes and have good success there.

And then there is lot of idle wells there and just returning those to production. It's expensive work, these RTPs run in about a $0.5 million a piece, because we have reestablish flow lines and put new pump and equipment in there and all. But these Montalvo wells may come on pretty good and then just have - it still has 5%, 6% decline and so it's just a good long-term asset. So, now we are going to be very busy in Montalvo this year.

Ray Deacon - BMO Capital Market

Great. And just two more quick ones. I guess with South Ellwood, where does the EIR stand? And then I guess just your thoughts on the MLP, I know the market is not very robust compare as what it was a year ago but it's still seems like the valuations are roughly doubled where your current trading multiples are. I guess what would it take for you to move forward on that or what do you think that the timing will be?

Tim Marquez

I just can't say anymore than -- you know we have filed our S-1. I would agree with you, but I can’t argue with you that the MLP valuations are double with the general market is, well Venoco is greater than that.

With regards to the EIR, the EIR has been completed but it's awaiting the final review by State Lands Commission before it’s publicly issued.

We are pretty encouraged by the whole thing, we, actually -- I am meeting with State Lands Commissioner tomorrow in Sacramento. I feel pretty good about the whole process and now that the EIR is ready to be issued the State Lands Commission has told that it is done. That’s really set in motion all the other meetings. Once that is issued then, all the other meetings start being scheduled for the review and ultimate approval.

It doesn’t mean that things can’t be challenged and delayed but, because this project is really a negative impact, in other words, barging goes away, you put a pipeline in, don’t take anymore infrastructure, drill wells, and it actually accelerates life of drill, and shorten life of the field. It is hard for anybody to really hate it then and then from the State of California’s perspective, it brings in about a billion dollars worth of new royalties and for the state it is $20 billion per year short of making their budget there.

It is a significant project to the state. That project from the outside world it looks like it hasn’t been moving very quickly and then I’d agree. But we have, the EIR has been, like I said, it has been completed. It should be publicly issued here very shortly. But we’ve also been doing engineering works, securing [idle ways], doing some work on the platforms in preparation of that project. So, it is a focus for us, even if we don’t talk that much about it, we have been working hard on that.

Ray Deacon - BMO Capital Market

Got it. Got it. So, just one more quick one is, when you talk about the recompletions and fracking wells on the Sac Basin. Is it -- what were the -- I know frac one per zone but are you talking primarily about frac in the fourth this year?

Tim Marquez

Yeah we will get back to it, but all the numbers, all the reserves is included in and this is where its all for is focused. We fraced one win per well that was one of the first three wells we've frac last year and although it had some I would just call analyzed result. The well made nothing before the frac and returned 200 Mcf a day afterwards, which obviously that's not a headline but it's not a bad start. In fact we are able to prove that you could frac it, but all the numbers we are talking here are purely Forbes related and we are going to very active. What we've been doing is fracing wells in bunches, four to five wells per week, every week two to three week. So next week we'll frac another five wells, so just a slow, steady spot processing and also playing around that the frac formula, we are trying small fracs, big fracs, large by-fracs. I mean just a whole bunch of different techniques to see which works the best and a lot of different things to evaluate. This is a very complex field that just so massively thick and just a characterization of the reservoir is very difficult but I will say all the fracs work, it just some seem to work better than others. So we are seeing incremental rates anywhere from 5 on the low tide, 300 or 400 Mcf data on a high tide, that is about 1.2 million a day. So they are working to just various degrees.

Ray Deacon - BMO Capital Market

Got it. Thanks very much.

Tim Marquez

(inaudible)

Operator

Our next question comes from the line of Jim David. Please proceed.

Jim David

Good morning. I have a couple of comments and questions. Well, I am seeking your clarifications with regards to stock underperformance related to commodity and the peer group. We have a great bull market in oil and gas prices yet the stock is underperforming. I might add that shareholders here are clearly sending a message to you, as this stock is the worst performing in the industry. Though mainly I'm seeking your clarification with regards to what's going on, and my question is, it's actually very straight forward to you, do you have confidence in your ability to create value and what specific actions you will take for the short and long-term, and because you, in many of your presentations claimed that the experience of the management and all that, so I just want to know what's going on here? So, I'll really appreciate if, I wasted my time honesty for this long, so I'll really appreciate if you could give us a little bit of clarification, it will help every shareholder. Thanks.

Tim Marquez

Yeah, of course I am the biggest shareholder of the company, so, its something I'm very focused on and as to the question, do I have confidence that we know how to create value I'd say, yeah. And that’s not misplaced, I started the company with $3,000 and built it up to, it certainly not a large market cap company, but we've been adding value for many years. This past year -- well let's talk about since we went public, you know production is up well over 30%, profitability is up 100%, reserves over the last few years have doubled, just in the last year the reserve value more than doubled, now a lot of that was pricing, but a lot of that is also reserve additions. We just talked about out Sacramento basin economics where we are talking proved and probable reserves of 530 Bcf to 800 Bcf. From a field that of when we took it over these two fields Willows and Grimes at about if I recall about 10 Bcf of proved reserves. Yes, we do know to add value, there is a huge disconnect no matter what analyst you look at when you compare the comps we are in an anomaly. I think that one of the last research reports I saw, I think our peers are trading at something like 1.2 to 1.3 times reserve value PV10 and we are at 0.4/0.5 times.

I think some issues are clearly we have missed guidance in 2007 and then when we had to cut out the Grace project. We started this year by cutting that project out. Again though as I said at the time when we cut it, this company is focused on value. We are not playing the volume game we are playing the value game and while Grace is still an economic project we are better placed to put money. What that meant is in the short-term, we reduce our guidance for this year. But we are still increasing value by reallocating that capital. So, yes I have plenty of confidence. I haven't sold any shares since we have been public. I am personally very bullish on the stock. I don't think the company has ever been positioned better. I think one of the thing that we are focused on is our debt, surely compare to our peers on a debt to EBITDA ratio we are higher than peers. But this year, we will be to achieve some significant production growth while drilling wells within cash flows at least according to our projections. And at the same we have potentially de-leveraged in advance with regards to seller hay schemes. You put those two factors together and we should be driving down our leverage ratio significantly.

I think when some of these things, when people start seeing, Denbury exercise and kick up the CO2 and South Ellwood field gets permitted when we’ve seen more results and South Ellwood -- in Sacramento Basin. I don’t think Sacramento Basin is an area where people haven’t understood what we’ve been up to there. We’ve been, I’ll say we have been fairly quite about it because we have been in the leasing position, a very competitive leasing position. we’ve increased our lease positing by a factor of 7, and until now haven’t talked too much about what the impact of that is, but I think you can see that the company has plenty upside and good execution over the years and not without stumbling here and there. But we have been adding value for 16 years since I started the company so I think we’ll continue to be of value.

We are focused in California where there is not a lot of competition, third biggest oil producing state in the country; I think it is the right place to be. There is a huge barrier to entry, on the California side, I don’t mind talking too much about it but that a place a lot of people don’t know how to operate but we’ve been thriving there for many, many years.

Jim David

Yeah, Thanks for the comments but I hope you keep your guidance for this year at least you know, because your current production is lower than what you are supposed to be producing for 2008. This kind of, and moreover you are stock action clearly gives you what is, people thinking about your company not the analysts. I don’t think they may or may not give you the actual picture. So, I just, if I just wanted to -- I know you and the management own significant portion of the company. That’s known to everybody but that is not the issue here. The issue is, underperformance relative to the peer group and the commodity, and everything, any metric you take, since you went public IPO, so that’s what you need to understand, I’m calling to convey this message because the analyst won't tell you all this they will have their own they want some this that like some data, but this fact is your underperforming relative to peer group and there is no respect in the market for the company's stock. So I want you to know that and I hope, I want to tell you direct so that you understand what people are thinking like myself. I appreciate your confidence. Anyway thanks.

Tim Marquez

I appreciate your comments and we understand the baby's stillness, the market is telling us that baby's ugly and we don't share that. I do want to point out that with regards to production. Production is nearly what already it's almost at the bottom end of our guidance and we still have plenty of development work to do during the year. So we should seeing production rise throughout the year.

Operator

Our next question comes from the line of [Eric Steve with Golden Tree], please proceed.

Eric Steve - Golden Tree

Hello, you mentioned in the response to the last question that you think your high leverage may be one of the reasons as the market is deciding a punitive valuation to your company which trust me is a very reasonable [bulk] process. So, I was hoping you can clarify some of your previous comments on your capital structure. You mentioned during the prepared remarks that you are targeting a debt-to-EDITDA ratio of 2 to 2.5 times. And that's you feel that you can stay within that band even before a potential Hasting sale to Denbury. To the extent that that sale does become a reality and you are already in that 2 to 2.5 times range. What would you anticipate doing with the proceeds? It sounds like you think de-levering could be a positive accounts for the stock, but it is not obvious. I guess I just had a little more clarity in terms of what you would do with the proceeds? Thank you

Tim Marquez

Sure we are an acquisition company, we are always in a hunt for acquisitions we are looking at a lot of acquisitions now. We are not crazy, we are not going to do anything major until we get some clarity on what's going to happen Denbury, but certainly we are in the mark. We have plenty of liquidity with our line of credit to do some acquisitions, but on the other hand we don't want to lever up too much but certainly we are looking forward towards more acquisitions during the year. Ideally it would be nice if we could do a 10/31 with Denbury and use those proceeds to plot another acquisition to deal with the deferred taxes and that would be our optimal scenario. The market in California’s is very good for acquisitions, so can’t get much more specific in that but that would be the general strategies, we are an acquisition company.

Eric Steve - Golden Tree

So it sounds like you are certainly willing to go about 2 to 2.5 times EBITDA to do a attractive acquisition?

Tim Marquez

Yeah and we have been we have been over three times but our goals always get it back down and we don't mind being up there for a short period of time, of course we hedged to account for that increased risk profile is to hedge more, we hedge 80% of our PDP three years out, so we complete the night but yeah we have no problems of getting up to three times debt to EBITDA but as Tim Picker said our goal is to get that down long term lower, so I think you could expect over the years our debt to EBITDA is going to kind of run one half to three times debt-to-EBITDA.

Eric Steve - Golden Tree

Thank you

Tim Marquez

Sure

Operator

Our next question comes from the line of Gary Stromberg with Lehman Brothers. Please proceed.

Gary Stromberg - Lehman Brothers

Hi, Eric. Just asked my question. Thank you.

Tim Marquez

Okay, thank you.

Operator

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

Joe Allman - JPMorgan

Sorry about that guys. Just back to the Sacramento Basin. Tim, did you say that the locations that you've talked about those are just Forbes locations and so you are not really talking about the (inaudible)?

Tim Marquez

We are not -- we are still bit under raps, it's still an exploration target, so this all Forbes.

Joe Allman - JPMorgan

Okay. And then you gave some numbers and I missed those, and you gave some other numbers, you said something about 300 to 400 Mcf minimum to like 1.2 million a day, are those results you're seeing so far?

Tim Marquez

Correct, Joe, yeah.

Joe Allman - JPMorgan

Okay. Are these results on any particular type of frac or on the 20s and 40s and the reentries?

Tim Marquez

No, I would say not surprise any of the thicker, cleaner type sands, seems to have the higher response. So the more channel looking sands, you might say the better send body's that are tight seem to have better response. Whereas some of these really think micro beds that look like shale's on logs, those tend to be at the lower range but we've had some crappy looking stuff that had good results, and had some good stuff that's towards the lower end of the range. What we really need is a lot more data points here and I guess being an engineer I think we would all like to sit on this information for two years and analyze two years worth results before we said anything, but we also realize that we got to communicate. It still very early, we only have two wells that have been on production for three months. We've got another small one that been on production for a month. And we also try to balance that would being conservative with our estimates and we hope that the actual result will exceed what we are seeing here.

Joe Allman - JP Morgan

And when you giving these IP rates, what kind of length of times or these falling at these rates, like 300 or 400 or $1.2 million?

Tim Marquez

What we are seeing is, it's really a mixture when we a frac a well we immediately clean the well up and stabilize production. And then usually we have -- leave the well shut in for a couple weeks while we get the blessing from PGNE, who as a purchaser have to put on production. They want to make sure the nitrogen is out of the system and it just kind of slow cumbersome process. By the way we are working on a process to speed that up, but what we are seeing is that the initial stabilized rate, the few weeks to one month stabilized rates are consistent with the initial production rates immediately following the frac.

Joe Allman - JP Morgan

Got you. Thanks.

Tim Marquez

The only one that we saw tail-off was when the well that had 200 Mcf a day test and then when it is put on production I think about three weeks later it didn’t give up any gas. That was a bit of a head-scratcher.

Joe Allman - JP Morgan

Okay. Got you. And I think you said that you increased your acreage quite a bit in the Sac Basin, could you tell what's your current acreage position is there?

Tim Marquez

I guess about 210,000 net acres.

Joe Allman - JP Morgan

Okay. Got you. And then is there anyway you kind up break up the acreage and say okay kind of like to the south its more centers or micro beds. I mean is there any way to sort of what percentage of acreage is perspective for this frac program. Which one is -- what part has better acreage and how much of that?

Tim Marquez

One way to answer that is roughly about 30,000 acres I think it's our net acres position, towards islet area, which is down near Rio Vista, to the west of Rio Vista. That's where we had some [terra] wells that we drilled and completed back a couple of years. The bulk of the rest of that acreage, we had roughly 180,000 acreage by far the bulk of the that is in an around the Grimes and Willows field. So virtually all of that would be perspective for fracing, its all kind of a very thick Forbes especially when you get more to the middle of the Grimes and Willows fields acreage it gets towards the end you don't have as many of these stacked sands but still it's very thick even on the edges. So by far the bulk of that acreage is Grimes and Willows and actually allow that leased acreage that we drilled over the years. It's taken us a long time do it because it's been actually leased in some large part in the middle of field. People who would had some piece of Grimes field, Willows field and walked away from it, at a time people didn't understand that but what the law about this is private land is and a lot of that acreage position or two acres, five acres, 10 acres and it's just very slow process and leasing it is not like federal acreage where you pick up 50,000 acres at a whack.

Joe Allman - JP Morgan

Got you. And then just two more quick ones. CO2 any kind of plans to try to access some source of CO2 in particular for the Manvel field?

Tim Marquez

Yeah we've had discussions with several parties. There are several parties who are looking for some [Venoco] build spring CO2 in the area, aside from Danbury and most of these projects are or anyway from a few years up to a several years off and some of it's industrial gas and some of its other CO2 gas and I would say Manvel realistically is probably at least five years away from in CO2 flood but nevertheless we -- it is a very large target and we are very focused on trying over the next years or 1-2 years to line up definite CO2 contract.

Joe Allman - JP Morgan

Got you and then lastly what you see in these days with drilling and completion cost, what’s the trend here?

Tim Marquez

We have seen pretty well steady. Out in the Sacramento basin we are just seeing economies to scale, not so much the rig rates coming down but just we are getting more efficient with it. We certainly are seeing a big drop off in our frac cost as we increase the number of fracs we are doing in and just seeing the efficiencies of mowing and de-mowing equipments. All our frac equipments comes from Baker's field and its not near where you want to frac one all the time, but by fracking five wells at a time we see some economies there. But all in all we never saw the giant run up in cost that you saw in the rest of the country nor are we seeing big decreases or significant decreases like you see in other parts of the country. So California has stayed more or less that at least in onshore drill they stay more stable, we haven't seen the big swings that other parts of country have seen.

Joe Allman - JP Morgan

Okay, very helpful, thank you.

Tim Marquez

Thank you.

Operator

There are no other questions at this time.

Tim Marquez

Thanks everybody for questions, for listening in today's call, a lot of good questions there. We continue to be really excited about Venice’s prospects for 2008 and long-term prospects. There is still some of which are under wraps. We expect our capital expenditures will allow us to live within cash flow and pay down debt, allowing us to meet or beat our guidance.

In the year since I started Venoco in ’92, this for me is the most exciting time period. It is frustrating with our recent stock performance but nevertheless we feel very good about where the company is and where it’s gone. We think the Hastings CO2 flood transaction could be a big step change for the company, South Ellwood, the draft EIRs is finally near issuance and its moving towards completion. We've got some exciting exploration projects coming together this year and Sacramento Basin that of course continues to produce new opportunities with solid results and just a lot of excitement around here.

We are hoping to have an Analyst day. We scheduled it for our next quarter, where we'd be able to go over in greater detail, each producing area and the project related to each.

So, again, I want to thank everybody for joining us. A replay information of this call will be posted on the website and have a good day, everybody.

Operator

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

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