Venoco Q3 2007 Earnings Call Transcript

Venoco, Inc (VQ)

Q3 2007 Earnings Call

November 12, 2007 12:00 pm ET

Executives

Mike Edwards - Vice President Investor Relations

Tim Marquez - Chairman and Chief Executive Officer

Tim Ficker - Chief Financial Officer

Mark DePuy - Chief Operating Officer

Analysts

Nicholas Pope - JPMorgan

Ray Deacon - BMO

Gary Stromberg - Lehman Brothers

Jeff Robertson - Lehman Brothers

Presentation

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2007 Venoco Inc Earnings Conference Call. My name is Shantalay and I will be your facilitator for today's call. At this time all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference (Operator Instructions).

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the call over to Mr. Mike Edwards, Vice President of Venoco. Please proceed, sir.

Mike Edwards

Hello, everyone. I'm Mike Edwards with Venoco. Venoco issued a press release yesterday on our third quarter 2007 results. We expect to file our 2007 Form 10-Q for the quarter with the SEC tomorrow.

On the call today to discuss the third 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.

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 related to the forward-looking statements are set forth in our filings in the Securities and Exchange Commission.

The earnings release and the relevant non-GAAP reconciliation’s are available on the investor relation's 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, and welcome to everybody's that's called in on our webcast. Today I'm very pleased to review Venoco's third quarter results. We had our guidance call a couple weeks ago where we focused on 2008 guidance.

Today, we'll cover third quarter financials and production, and we'll reiterate guidance that we discussed a couple weeks ago. First of all, we'll start with production. We had continued production growth this quarter over both last quarter and year-over-year.

Production in the quarter was up 22% compared to third quarter of 2006, most of this production growth was organic, about two-thirds of that. The majority of the growth was from West Montalvo or the acquisition growth was from Montalvo and Manvel field in Texas. We'll talk a little bit more about later.

Net production for the third quarter averaged 20,701 barrels of oil equivalent per day, which is an increase of 5.5% compared to second quarter of 2007. As you know in the call two weeks ago, our production guidance for the full year 2007 is 19,900 BOE per day and we're forecasting of 15% to 20% increase in production for full year 2008. And 19,900 our full year 2007 growth is expected to be 25% compared to 2006.

Moving on to capital expenditures, CapEx for the quarter was about $89 million, with approximately 46% being spent in Sacramento Basin, a quarter being spent in Coastal California and about 31% in Texas. For the full year, we're now estimating CapEx to be about $320 million. The increase is due primarily to the additional Sacramento Basin wells, now estimated to be about 130 wells, up from the 120 that were originally budgeted.

The biggest factor was the accelerated CapEx for the Hastings field fluid handling project. We'll discuss more of the operational details in that in just a little bit, but we're now confident that the project will be complete in 2007 and we'll be handle 500,000 barrels of water per day by the end of December, by the end of next month.

This is in part is why we're able to reduce CapEx for 2008, because we moved a lot of that project from 2008 into 2007, so kudos to our guys for getting that project wrapped up by the end of this year.

Capital expenditures for 2008 are forecast to be $235 million; approximately $130 million will be spent in the Sac Basin, $70 million in Coastal California and $35 million in Texas. We estimate about $185 million will be spent on development drilling and well work, $25 million for facilities and $25 million on exploration. Though we actively pursue acquisitions, we don't forecast expenditures for these.

2007 production expenses in G&A costs summary, production expenses average $14.90 per BOE in the third quarter of 2007, compared to $14.53 per BOE in the second quarter of 2007. Third quarter 2007 production expenses reflect a full quarter of West Montalvo and Manvel operations, where expenses increased as remedial efforts accelerated in both fields. These efforts coupled with production curtailment at West Montalvo for facility vessel inspections and repairs resulted in an increase in production expenses per BOE.

The company expects production expenses to decrease on a per BOE basis in 2008, as a result of reduced remedial activities in the Hastings complex and that also as we realize production volume increase in the Sac Basin, Santa Clara field, at platform Grace, Hastings as well as the West Montalvo and Manvel fields.

G&A for the quarter were $3.97 per BOE, sorry, for the first nine months its $3.97, 2007, excluding charges under FAS 123R of $0.70 per BOE. Excluding FAS 123R charges, the company expects G&A expenses in 2008 to be similar to full-year 2007 on a per BOE basis.

Now, to talk more about specific fill performance, we're going to start in Southern California. On platform Grace, in the Santa Clara field, we've now drilled and completed our first well and are working to establish first production. We moved the drilling rig onto the second well and expect to spud the second well shortly.

Reactivating and re-entering the first spots and challenges well more than decade of the platform being inactive. We expect experience and information from the first well will allow us to be more efficient as we move forward with the program. With the first well completed we're also able to fine-tune the process in equipment and platform. Though we expect to see production in the fourth quarter, we don't expect production for platform Grace to be material until next year.

Staying on the coast in the South Ellwood field, we continue working on the permitting process for the full field development project, which includes an extension of our existing leases from the state of California. The draft environmental impact report is expected to be out around the first of the year. Following approvals, we anticipate project start-up in 2009.

The development program consists of extending reach wells drilled into the eastern portion of the field from our existing platform in the field, that's the 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 pipeline near Exxon's Las Flores Canyon facility. It's also important to note that none of these reserves from the extended reach drilling are contained in our current reserve reports. So there's a lot of upside with this project.

Since acquiring the West Montalvo field in early May, we've drilled a new well from an on-shore location and offshore target, reactivated injection wells to handle additional fluid volumes from upcoming development activity and repaired or worked over several production wells.

We're in the process of permitting; procuring and installing new artificial lift equipment and related processing facilities, which will handle production increases from reactivating currently idle production wells in the field.

We expect to see production from first group of these wells during the fourth quarter. The initial wells we've returned to production we've been very pleased with the results. They've been averaging in the order of 40 to 50 barrels per day for return to operation. So pleased with those results and we see significant growth coming up in 2008.

Moving to Texas, I talked about Hastings and nearby Manvel fields we acquired earlier this year. We remain very active in returning wells to production, converting gas lit wells to electric submersible wells, as well as upsizing existing ESPs and adding fluid processing injection capacity as I discussed earlier.

We're planning our experience in Hastings in both the design and execution of our recompletion and workover plan for our Manvel field. In Hastings, our current fluid capacity is a little over 300,000 barrels per day. But, as I said earlier, by the end of this year, we'll get to processing facilities in place to handle 500,000 barrels per day.

This is up from about 150,000 barrels per day from when we took over. So this is a very large facility project to increase fluid handling from 150,000 barrels a day to 500,000 barrels a day. It's an enormous project, one of the biggest projects of its kind actually in the lower 48.

Project though has great economics. To give you a sense of by now we are producing about a 130 wells and we still have something around 170 idle wells that most of which can be returned to production. We just had to hold off on that until we got this fluid-handling project in place.

We continue to evaluate the potential of unswept and residual oil through the five well program we initiated earlier in the year. We're employing special case hold logging and evaluation tools to help better evaluate the pay. We had constructive meetings with temporary resources regarding their option to acquire the Hastings complex and implement a CO2 enhanced recovery project.

Of the $50 million option, we've received the second installment bringing us to $45 million received and leaving the final $5 million payment due next November. Denbury can exercise the option, either one year from now or two years from now, so November 2008 or 2009. So we continue to work with our technical staff to refine the development plan and coordinate activities in the field. All around good things happening in Hastings.

Assuming that Denbury does exercise the option, we'll either sell them the property for cash, based on PV-10 of the reserves or enter into a volume metric production payment arrangement. That being said we're leaning toward taking the cash option.

Following Denbury's purchase of the field, Venoco will retain overriding royalty interest of 2% of the property then we're back into working interest of approximately 22.3% in the CO2 project after Denbury recoups their investment cost.

We continue to implement our workover and re-completion program in the nearby Manvel field and saw production increase in the third quarter from that work. We remain focused on increasing our fluid processing and injection capacity there.

On a longer term basis we believe the Manvel field has the same opportunity for CO2 flooding as Hastings does, and we're moving forward on several fronts on that to be able to capture that upside. Moving back to California, moving to Northern California, talk about the Sacramento Basin, where our drilling workover program continued at full speed.

We are ahead of projections of the number of new wells to be drilled as I mentioned earlier and now expect to drill at least 130 new wells this year. We spud 33 new wells in the basin third quarter, which brings our nine-month total to 101.

It’s important to note that due to our increased drilling efficiency, we've been able to carry out this program even after releasing one rig during the quarter. In addition, as planned, we expect to rework 100 wells in the basin this year. We reworked 29 wells in quarter, which gives us a nine-month total of 71.

We're going to start doing on our quarterly calls is going area by area and providing a little more in-depth flavor for our operating areas. This month, this quarter we're going to talk a little more about Sacramento Basin operations.

Venoco's been in the basin for 10 years, having acquired Mobile's operations in the basin back in late 1996, the main fields being Willows and Grimes which are respectfully the third and second biggest gas fields in California.

At the time the operations were grossing less than 10 million cubic feet per day and the feeling was that these fields were on their last legs. Our main focus when we acquired the field were recompletions, identifying low resources that we paid and recompleting the wells.

To stem the decline of the fields, which has proved very effective and the recompletions I should say has proved very effective over the years. With the electrical crisis in California in 2001, gas prices spiked and we initiated what we thought was an acceleration program of in-field drilling from 40-acre space from down from 40 acres.

As it turned out, when we completed these down space wells we found that they had original reservoir pressure. What that told us was that producing reservoirs was not made up of continuous sand, as previous operators had thought, but was rather made up of lenticular sand, sand lands of much smaller aerial extent.

As we evaluate the wells, we found the most of these zones were draining less than 20 acres. All of this led to our current infield drilling program where we are primarily focused on drilling 40-acre spacing wells.

We've drilled; on top of that, we drilled about a dozen 20-acre wells this year. It's going to take a while to fully evaluate the 20-acre wells, as I mentioned before it will probably take until the middle of next year as we really need to evaluate the reserves from the original completions, and to get back in after initial completion and do several recompletions and evaluate those results.

So it's a time consuming process. But I would say that at this point we're very encouraged by the initial wells we drilled and we will drill some more 20-acre wells before the year's up.

Switching focus a bit, at the time I started Venoco, I started Marquez Energy in 2002, we focused on Sacramento Basin, and acquired acreage and production, it was later merged into Venoco in 2005. Those acquisitions have been proved very instrumental in helping Venoco in its growth.

Another significant event for us in the basin was the acquisition of TexCal in March of last year with the substantial acreage in production, joined much of our existing acreage in production. We have a lot of operational synergies, and our geologists and geophysicists now have a much bigger data set with which to work.

Because of the lenticular sands we don't have a typical well in the basin. No two wells are alike. Initial completion in the well may have initial production anywhere from 300 mcfs a day to well over a million a day. Our wells in the basin typically have three or more workover opportunities over the life of the well and then they level out at a lower but steady rate for a number of years.

All of the completions have been natural completions. That is, they don't require any stimulation to produce these rates. Though there were discoveries in the basin as early as the 1930s, the real development was by the majors in the 1950s and '60s. Their standard completion technique was for conventional cased and appropriate completions. As I said before then, natural completions.

This development focused on prolific channel sands in the field. When previous operators didn't hit these channel sands they generally P&A'd the wells. In many cases they didn't understand the geology or the interpretation these low region beds there. Very likely that most of these wells that we completed productive today would have been P&A'd as noncommercial wells years ago. We understand the geology now and are able to identify productive zones that previous operators missed.

We talked a little bit about Gwinda [ph] in the past, I was just going to give you an update now. By now we've drilled nine wells into the Gwinda, which is below our predominant produce information before us. The Gwinda is a tight, high-pressured zone that has great gas but very little production with conventional completions.

We think the Gwinda's a great candidate for frac, along with some of the low permeability Forbes zones. We did initiate our frac program last week and are encouraged by the early results. The combined initial rates from these wells are over 3 million per day gross.

It will take several months to determine what the impact on reserves will be from the frac and what the decline rate is from these wells, but we're very encouraged so far. Our plan is to continue with the frac program and we budgeted 12 fracs through 2008. But if the results turn out positive we will certainly increase this number substantially.

We hope to get in and frac some additional wells by the end of this year and continue right into 2008. From the geology in the area, as well as our initial drilling, the Gwinda is extensive within our lease-hold area.

Let me back up one step. I should mention that one of the three wells that we did frac was the Gwinda, so we are pleased that we have been able to establish commercial production in Gwinda for the first time.

Now, I'll talk a little bit more about the Gwinda. As mentioned earlier, we drilled nine wells into the Gwinda. Based on the information we have, the Gwinda appears to be extensive within our leasehold area, which has grown to 235,000 gross acres. We have over 500 wells in the basin, over 300 of which are active. So aggressively as we move the frac program forward to unlock the potential of the field.

Most of the existing wells in the field have multiple zones that appear to be frac candidates. It is important to note that we do not have any reserves in the field attributable to these type formations, that's both the low permeability, Forbes and all of the Gwinda. of this has any reserves attributed to it.

A successful frac program can add a significant amount of reserves to our fields in the Sac Basin to keep us on the growth trajectory, high growth trajectory for years to come. All in all, you can tell we're very excited about our core operations at the Sac Basin, as well as the traditional opportunities we see in our down space and frac programs.

With that, I would like to turn it over to our CFO, Tim Ficker, who is going to go over the financial highlights.

Tim Ficker

Thanks, Tim. I'll briefly cover some financial highlights for the quarter. We reported net income of $500,000 for the quarter, which compared to net income of $16.2 million in the previous year. And the '07 net income includes the after tax effects of $5.2 million in unrealized commodity derivative losses and $5 million in unrealized interest rate derivative losses.

And without the effects of those items, our after tax adjusted net income was $10.7 million. Adjusted EBITDA for the third quarter was a company record, $62.1 million, which is up nearly 9% from the second quarter and up nearly 70% from the third quarter '06 adjusted EBITDA of $36.6 million.

For the nine months '07, adjusted EBITDA was $157.4 million, and we expect adjusted EBITDA to grow in the fourth quarter and throughout '08 as expected production increases. Oil and gas revenues for the third quarter were $97.3 million, which is up from $75.9 million in the '06 quarter.

That an increase is largely due to production, which was up from about 1.6 million BOE in the '06 quarter, to about 1.9 million BOE in the '07 quarter and we also benefited from oil price increases, which is up about $5.50 per barrel from the '06 quarter to the '07 quarter. That reflects the differential of approximately $8.50 from NYMEX for the quarter.

And gas prices were down slightly, about $0.12 for the quarter and again that reflects the differential of approximately $0.45 off NYMEX for the quarter. And I'll note that those prices don't reflect the impact of our hedges and we don't follow hedge accounting for our derivative instruments. And the increases in production came from organic growth in our significant areas of operation as well as the recent acquisitions that Tim mentioned earlier.

Production expenses for the quarter were $28.4 million, which is up slightly on an absolute dollar basis from the third quarter '06, but down about 14% on a per BOE basis. The gross dollar increase is primarily due to increase in the number of properties we operate as a result of our capital expenditure program as well as acquisitions, but on a per BOE basis, that increase is more than offset by the 22% increase in production year-over-year and production adds from lower cost gas wells in the Sac Basin.

As expected, production increases next year, we expect our production cost, excluding production taxes, to average $13.50 per BOE in 2008. G&A for the quarter was $7.6 million, which is up $200,000 from the prior year quarter.

The 2007 amount reflects an increase in our professional staff and related infrastructure resulting from our growth and approximately $600,000 related to settlement of an employment contract and those numbers are partially offset by an increase in the proportion of G&A we capitalize as a result of our increased exploitation, development and acquisition activities.

And on a per BOE basis, G&A expenses excluding FAS 123(R) charges decreased about $1.07 from the '06 quarter to the '07 quarter. We expect our 2008 G&A to average about $3.75 per BOE in '08 excluding FAS 123(R) charges.

On the DD&A side, the biggest drivers in the $7 million increase from quarter-to-quarter were increases in our full cost resulting from our acquisitions in the early in the second quarter and our capital expenditure program.

Turning to the balance sheet, compared to year-end '06 the items of note were increases in PP&E and debt, which were both up as a result of our '07 CapEx program and acquisition. Now I'll note that as Tim mentioned, we have the Denbury transaction coming up, probably this year or maybe next year, but part of our focus for next year will be in managing our debt level.

And the Denbury transaction, if we elect a cash option would serve as a deleveraging event. And in addition to that our expectations are that we would, our 2008 CapEx program would be well within cash flow, which all else being equal would allow us to reduce our outstanding debt balances. That's a brief overview for the quarter, Tim, so I guess I'll turn it back to you.

Tim Marquez

Okay. Thanks, Tim. With that I'd like to open it up to questions.

Question-and-Answer Session

Operator

(Operator Instructions) And your first question comes from the line of Nicholas Pope of JPMorgan. Please proceed.

Nicholas Pope - JPMorgan

Good morning, guys.

Tim Marquez

Good morning.

Nicholas Pope - JPMorgan

I was hoping you could get in a little more detail on some of the hydraulic fracturing work you're doing in the Sacramento Basin. With those three wells you're talking about, are those new wells are those are you re-entering new wells and I guess I'm not sure if you have any thoughts right now on what kind of incremental reserve you might see from this kind of stuff, so?

Tim Marquez

Yes. These are relatively new wells, these are down spaced wells. The first one we did, we did frac the Gwinda well. The other two, the second two were Forbes wells. It's just way too premature to even make any estimate on reserves.

We can draw some analogies from other fields, mainly the Piceance Basin. It is a very exciting step forward, something we talked about for a while. We felt for a long time that there's no reason why fracs couldn't work.

There is certainly conventional wisdom we've been finding for years as fracs somehow magically don't work in California, bit we're very encouraged that these have had good initial results. I don't want to over hype it because it's just we've had a few days of production so far. There's only been one other field that's seen any significant amount of frac. It’s so this is a big step forward for us.

Nicholas Pope - JPMorgan

Thanks, and I guess in West Montalvo, with these first wells, any idea what the results look like there so far?

Tim Marquez

Well, we've drilled one well and the results are encouraging. We initially completed the lower half of the ses, that's our primarily producing formation there. The well, that lower half is zoned IP'd it about 170 barrels per day. We're now just finishing up the work over to add the upper half of the ses b, which should be the better part of the ses b.

So we won't have results on that for probably another week or so but that well, no real surprises. It was a good-looking well. I think as we have said before, because we don't have 3D over the offshore portions of the field, we're really going to be extending the limits of this field kind of on a well-by-well basis.

Really all we have now is regional geology, which we're encouraged by. We think that we can continue to drill substantially further offshore, but it will be just a well-by-well basis. So each well we'll add just reserves attributed to that one well or maybe one adjacent well.

So, each well will not add a lot of reserves. It's going to take a number of wells before we can collectively increase the reserves. On the reworks, I think I said two. We've actually done three re-completions and these have turned out very well.

Incremental rates of over 50 barrels a day per well. And we have a lot more of those to come. I think we have something in the order of magnitude, 20 more re-completions to come on that. So, a lot of good things going on at Montalvo.

Nicholas Pope - JPMorgan

Sounds good. And real quick. Share count for the quarter, do you have that number?

Tim Flicker

A little over that number's in the Q and we haven't released that yet. We apologize, but that will be filed in the Q.

Nicholas Pope - JPMorgan

All right. Thanks, that's all I have. Thank you.

Operator

And your next question comes from the line of Ray Deacon of BMO. Please proceed.

Ray Deacon - BMO

Yes. Hey, Tim. I was wondering, what kind of cost might be associated with increasing the water floods at Manvel, or how much would be in the 2008 budget for that, I guess?

Tim Marquez

Most of our, you want the split between Hastings and Manvel?

Ray Deacon - BMO

Well, I was just curious. I mean is it a big number or ?

Tim Marquez

It's not that big. Mark, can you do you have that number on Manvel?

Mark DePuy

Yes, Manvel is probably around $10 million.

Ray Deacon - BMO

Okay. Got it.

Mark DePuy

Or less.

Ray Deacon - BMO

Got it. Got it. And I guess, so I wouldn't expect you to get much credit in your reserves this year for 20-acre down spacing in the Sac Basin and probably not much for this well you announced this morning at West Montalvo. Is that probably right?

Tim Marquez

That's an understatement, Ray. We can't even get full credit for the 40-acre spacing wells, despite the fact we drilled 250 40-acre infills. We consider additional inventory, about 500. We can't even get full credit for our 40 acres. So, I would assume we would get a very marginal amount for the 20 acres.

It seems like we're always working a couple years in arrears on getting reserve credits. And that will go with the frac too. It will take a long time to get reserve credit for these. So we will ultimately get it. It's just going to take a while to get it.

Ray Deacon - BMO

Great. Got it. And I guess just looking out the next couple of quarters I mean the sequential growth is going to come from basically Hastings, the Sac Basin and also Gail being returned to production. Is that basically right as far as visible production adds in your term.

Tim Marquez

I think you said Gail. I think you meant Grace. Yes, Grace will return to production. And I think the Montalvo field will be not insignificant. But you're right those first three you mentioned are the big drivers for growth.

Ray Deacon - BMO

Great. Got it. Thanks a lot.

Tim Marquez

Thanks, Ray.

Mark DePuy

Hey, Tim. I might mention what the share count is. For the quarter, we'll have basic shares outstanding of 49.735 million and diluted of 51.104 million, on the nine-month period we'll have 45,138 or 45.138 million basic and diluted, and then share count at 9/30 was 50.261 million.

Operator

And your next question comes from the line of Gary Stromberg of Lehman Brothers. Please proceed.

Gary Stromberg - Lehman Brothers

Hi. Good morning.

Tim Marquez

Good morning, Gary.

Gary Stromberg - Lehman Brothers

A couple questions on the debt side; you mentioned that the Hastings sale at the end of '08 if it goes it was leveraging event. I guess two questions. One is, what debt would you repay, revolver borrowing or that you would have revolver borrowings? Secondly…

Tim Marquez

Hey, Gary, can you speak up? We can barely; we can't even hear everything that you're saying. I know you asked about the debt, and I think what I heard you ask is if we take the cash option from Denbury, what we would use that cash for. Is that the question?

Gary Stromberg - Lehman Brothers

Yeah. Tim just what debt you'd look to repay with that cash option?

Tim Marquez

Yes. We would look to repay the revolver, and then there's actually some waterfalls within our term loan and our senior notes. And so it would depend at that time on how those waterfalls worked out.

Gary Stromberg - Lehman Brothers

Okay. And then do you have an updated PV10 for the field by any chance, that you could share?

Tim Marquez

We don't. We're working on that, we'll have something obviously for year-end. We'll be able to provide an update at that point in time.

Gary Stromberg - Lehman Brothers

Okay. Thank you.

Operator

And your next question comes from the line of Jeff Robertson of Lehman Brothers. Please proceed.

Jeff Robertson - Lehman Brothers

Tim, I missed part of the very first part of the call. I was wondering if you could walk through the 2008 guidance increase and just kind of give it in order of expectations by the different areas? Which areas are going to contribute to the most to the guidance that you're laying out for '08?

And also, with respect to some of these new initiatives, like fracing wells at Sacramento, and some of the things you're doing at Manvel and Montalvo. What kind of numbers are in the guidance for '08 for those new projects?

Tim Marquez

We haven't provided any detail in the 235, other than I gave percentages by area. So, if I pull back my notes on that, we're going to spend about $70 million coastal California, $35 million in Texas, and $130 million in Sacramento Basin. But we didn't drill down deeper below that.

Jeff Robertson - Lehman Brothers

And in terms of the production contribution from each, can you kind of walk through where in related to the 20% increase, which areas you expect the largest contribution, or is it going to be similar to the capital program?

Tim Marquez

It will be fairly similar. I think we're going to get, the single biggest production increase will be Sacramento Basin and coastal California and Texas will contribute equally towards that production growth; so it's somewhat similar. It's a little bit skewed because in Texas we won't be spending money on facilities.

It will be all on reworks where we get a lot of bang for the buck. A good part of that is on rework and return to production, where we get a lot of bang for the buck. Coastal California we're spending a significant amount of money on facilities. And then of course, Sacramento Basin, that's almost all drilling and reworks.

Jeff Robertson - Lehman Brothers

And secondly Tim, can you point to some of the milestones along the way of trying to get the approval for the extended reach at Ellwood or the lease extension at Ellwood?

Tim Marquez

Yeah. The next milestone, we've already been through a few. The next milestone we'll be getting the draft environmental impact report, we have, already have a preliminary schedule of meetings with the regulators, the different regulatory bodies next year.

Those meetings start first through third quarters of next year; I think there was all of about six or seven already on the preliminary docket for that. So it's fairly well regimented, the process, the next one is, when we go through all the draft EIR.

All the reviews on this, the question is the opponents of the project will look for any weaknesses in the EIR not to kill it but just to slow it down, to make us readjust the EIR, redo the EIR. So, that's the wild card right now.

And assuming that the EIR has been done properly then you'll go from the review period, and comment period finalize the EIR. Then you'll actually get the final votes from all the regulatory bodies.

We're encouraged by the fact that people actually, we've had at least one environmental group, significant environmental group, has actually come out in favor of our project, which is kind of a first for me. I've seen somebody go in public records, to support a project like this, an environmental group anyway.

So we're encouraged by the project, but that's the process. At some point here we're going to schedule some more detailed meetings and walk through people all the details of all the different processes you have to go through. But that's really captures it pretty well, I hope. Does that make sense?

Jeff Robertson - Lehman Brothers

Yes, thank you.

Operator

(Operator Instructions) And your next question comes from the line of Ray Deacon of BMO. Please proceed.

Ray Deacon - BMO

Yes, hey, Tim, just as far as the fracing costs, I know it's very early days, but what is your estimate on what it's going to cost in the frac, in the Sac Basin to do a frac?

Tim Marquez

We're, these initial fracs are in the $300,000 to $400,000 range. I think over the coming six months, we'll be optimizing that, so we'll probably try some fracs a little bit bigger. We're going to play and these are some who might have back own fracs, we'll be playing with some different frac techniques that some may be a little more expensive.

So we need to now that we know they work, now we need to start optimizing them. The chances that we hit on a perfect formula as a starting point are probably slim and none, so it's really optimizing. But the initial ones are $300,000 to $400,000. I don't think they're going to vary too much from that. It's more the cost's a little varied, not the gross amount.

Ray Deacon - BMO

All right. Got it. Got it. And when you look at 20-acre spacing in the wells you've drilled so far, I guess, how big of a percentage of the 200,000 acres that you have, have you tested at this point?

Tim Marquez

Oh, I would say probably 10% of the acreage has been tested on 20-acre spacing.

Ray Deacon - BMO

Okay.

Tim Marquez

We tried to hit representative amounts of the field and more of the central parts of the field. And obviously, I will say we've taken more perspective parts of the field where we think it had a better chance of working. So, yes, it's no more than 10%, though.

Ray Deacon - BMO

Got it. Got it. And, the areas where you feel like it has a better chance of working, is that or are those areas where there's, these lenticular sands are not connected at all or is it where you've got kind of the most gas in place, or?

Tim Marquez

I guess most gas in place where we have the most stacked sands. Certainly in the Grimes field, in particular, you stay in the center of the field you have the gross thickness 3,000 to 4,000-foot of interval in the Forbes, just the Forbes alone. And you have a lot of stacked sands in the central areas.

You start getting on the fringe of the field, the gross thickness narrows down a little bit or thins out and certainly, the sand content goes down significantly as well. So, I'm sure that we'll have our best 20-acre wells in the more central parts of the field.

Ray Deacon - BMO

Right. Got it. And just one last one on the Manvel and then CO2 for that field, any progress there?

Tim Marquez

Yes. We made some progress because we're in discussions with different parties. I don't really want to say anything now, but we definitely have had progress and we're encouraged by these discussions.

Ray Deacon - BMO

Okay. Got it. Thanks.

Tim Marquez

Okay. You're welcome, Ray.

Operator

At this time, there are no further questions in the queue, and I would like to turn the call back over to Mr. Tim Marquez, CEO of Venoco. Please proceed sir.

Tim Marquez

Yes. Thank you all for listening on today's call. As you can tell, we're very upbeat about the continued growth of Venoco. We remain focused on increasing production throughout our operating areas and having a strong ex-rate here in 2007.

As we mentioned before, we're forecasting 15% to 20% growth in production for 2008. We have some very exciting opportunities in 2008, whether that's the 20-acre infields, the fracing program, the Gwinda up in Sacramento Basin, returning Grace to production, all the reworks in drilling at Montalvo to come, the Hastings field, now that we've got our big fluid handling project behind us.

Keep in mind we spent a lot of money on facilities that didn't directly have production attributed to it. So that's really pretty well behind us. And now we can concentrate on returning more wells to production, both there and at Manvel.

We've got the CO2 project coming up in Texas. There's a lot of good things going on in all those areas. We have the south Ellwood field that permitting is moving through, got some other projects, smaller projects, permitting, offshore California as well.

So these projects in total should lead us to believe we're going to have strong organic growth for many years to come. We see 2008 as a strong year to grow the company organically, improve our financial leverage, as well as take advantage of accretive acquisition opportunities.

Thanks for joining us. Replay information on this call will be posted our website on the investor relations page. Thanks, and have a happy Veteran's Day.

Operator

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

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