Venoco Q3 2007 Earnings Call Transcript

Nov.12.07 | About: Venoco, Inc. (VQ)

Venoco, Inc (NYSE:VQ)

Q3 2007 Earnings Call

November 12, 2007 12:00 pm ET


Mike Edwards - Vice President Investor Relations

Tim Marquez - Chairman and Chief Executive Officer

Tim Ficker - Chief Financial Officer

Mark DePuy - Chief Operating Officer


Nicholas Pope - JPMorgan

Ray Deacon - BMO

Gary Stromberg - Lehman Brothers

Jeff Robertson - Lehman Brothers


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

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

Mike Edwards

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

On the call today to discuss the third quarter results wehave: Venoco's Chairman and CEO, Tim Marquez, CFO, Tim Ficker, and othermembers of the Venoco management team.

Before we get underway, allow me to make a couple ofcomments regarding forward-looking statements. All the statements made in thisconference call, other than statements of historical fact, are forward-lookingstatements within the meaning of section 27A of the Securities Exchange Act of1933 and Section 21E of the Securities Exchange Act of 1934.

These statements are subject to a wide range of businessrisks and uncertainties. Any number of factors could cause actual results todiffer materially from those presented in the forward-looking statements.

Including, but not limited to: the timing and extent ofchanges in oil and gas prices, the timing and results of drilling activity, thepossibility of delays in completing production, treatment and transportationfacilities, 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 datehereof and the company undertakes no obligation to update any such statement.Further information on the risks and uncertainties related to theforward-looking statements are set forth in our filings in the Securities andExchange Commission.

The earnings release and the relevant non-GAAPreconciliation’s are available on the investor relation's page of the Venocowebsite which is

Now I'd like to introduce Venoco's Chairman and CEO, TimMarquez.

Tim Marquez

Thanks, Mike, and welcome to everybody's that's called in onour 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 ofall, we'll start with production. We had continued production growth thisquarter over both last quarter and year-over-year.

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

Net production for the third quarter averaged 20,701 barrelsof oil equivalent per day, which is an increase of 5.5% compared to secondquarter of 2007. As you know in the call two weeks ago, our production guidancefor the full year 2007 is 19,900 BOE per day and we're forecasting of 15% to20% increase in production for full year 2008. And 19,900 our full year 2007growth is expected to be 25% compared to 2006.

Moving on to capital expenditures, CapEx for the quarter wasabout $89 million, with approximately 46% being spent in Sacramento Basin, aquarter being spent in Coastal California and about 31% in Texas. For the fullyear, we're now estimating CapEx to be about $320 million. The increase is due primarilyto 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 theHastings field fluid handling project. We'll discuss more of the operationaldetails in that in just a little bit, but we're now confident that the projectwill be complete in 2007 and we'll be handle 500,000 barrels of water per dayby 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 ourguys for getting that project wrapped up by the end of this year.

Capital expenditures for 2008 are forecast to be $235million; approximately $130 million will be spent in the Sac Basin, $70 millionin Coastal California and $35 million in Texas. We estimate about $185 millionwill be spent on development drilling and well work, $25 million for facilitiesand $25 million on exploration. Though we actively pursue acquisitions, wedon'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 2007production expenses reflect a full quarter of West Montalvo and Manveloperations, where expenses increased as remedial efforts accelerated in bothfields. These efforts coupled with production curtailment at West Montalvo forfacility vessel inspections and repairs resulted in an increase in productionexpenses per BOE.

The company expects production expenses to decrease on a perBOE basis in 2008, as a result of reduced remedial activities in the Hastingscomplex and that also as we realize production volume increase in the SacBasin, Santa Clara field, at platform Grace, Hastings as well as the WestMontalvo and Manvel fields.

G&A for the quarter were $3.97 per BOE, sorry, for thefirst nine months its $3.97, 2007, excluding charges under FAS 123R of $0.70per BOE. Excluding FAS 123R charges, the company expects G&A expenses in2008 to be similar to full-year 2007 on a per BOE basis.

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

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

Staying on the coast in the South Ellwood field, we continueworking on the permitting process for the full field development project, whichincludes an extension of our existing leases from the state of California. Thedraft environmental impact report is expected to be out around the first of theyear. Following approvals, we anticipate project start-up in 2009.

The development program consists of extending reach wellsdrilled into the eastern portion of the field from our existing platform in thefield, that's the platform Holly. The project will actually reduceinfrastructure on the coast by replacing the current barging operation, whichcurrently transports our crude oil to market with about a 10-mile longpipeline.

The new pipeline will connect the existing segment of allAmerican pipeline near Exxon's Las Flores Canyon facility. It's also importantto note that none of these reserves from the extended reach drilling arecontained in our current reserve reports. So there's a lot of upside with thisproject.

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

We're in the process of permitting; procuring and installingnew artificial lift equipment and related processing facilities, which willhandle production increases from reactivating currently idle production wellsin the field.

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

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

We're planning our experience in Hastings in both the designand execution of our recompletion and workover plan for our Manvel field. InHastings, 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 processingfacilities in place to handle 500,000 barrels per day.

This is up from about 150,000 barrels per day from when wetook over. So this is a very large facility project to increase fluid handlingfrom 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 ofby now we are producing about a 130 wells and we still have something around170 idle wells that most of which can be returned to production. We just had tohold off on that until we got this fluid-handling project in place.

We continue to evaluate the potential of unswept andresidual oil through the five well program we initiated earlier in the year.We're employing special case hold logging and evaluation tools to help betterevaluate the pay. We had constructive meetings with temporary resourcesregarding their option to acquire the Hastings complex and implement a CO2enhanced recovery project.

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

Assuming that Denbury does exercise the option, we'll eithersell them the property for cash, based on PV-10 of the reserves or enter into avolume metric production payment arrangement. That being said we're leaningtoward taking the cash option.

Following Denbury's purchase of the field, Venoco willretain overriding royalty interest of 2% of the property then we're back intoworking interest of approximately 22.3% in the CO2 project after Denburyrecoups their investment cost.

We continue to implement our workover and re-completionprogram in the nearby Manvel field and saw production increase in the thirdquarter from that work. We remain focused on increasing our fluid processingand injection capacity there.

On a longer term basis we believe the Manvel field has thesame opportunity for CO2 flooding as Hastings does, and we're moving forward onseveral fronts on that to be able to capture that upside. Moving back toCalifornia, 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 bedrilled as I mentioned earlier and now expect to drill at least 130 new wellsthis year. We spud 33 new wells in the basin third quarter, which brings ournine-month total to 101.

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

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

Venoco's been in the basin for 10 years, having acquiredMobile's operations in the basin back in late 1996, the main fields beingWillows and Grimes which are respectfully the third and second biggest gasfields in California.

At the time the operations were grossing less than 10million cubic feet per day and the feeling was that these fields were on theirlast 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 veryeffective and the recompletions I should say has proved very effective over theyears. With the electrical crisis in California in 2001, gas prices spiked andwe initiated what we thought was an acceleration program of in-field drillingfrom 40-acre space from down from 40 acres.

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

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

We've drilled; on top of that, we drilled about a dozen20-acre wells this year. It's going to take a while to fully evaluate the20-acre wells, as I mentioned before it will probably take until the middle ofnext year as we really need to evaluate the reserves from the originalcompletions, and to get back in after initial completion and do severalrecompletions and evaluate those results.

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

Switching focus a bit, at the time I started Venoco, Istarted Marquez Energy in 2002, we focused on Sacramento Basin, and acquiredacreage and production, it was later merged into Venoco in 2005. Thoseacquisitions have been proved very instrumental in helping Venoco in itsgrowth.

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

Because of the lenticular sands we don't have a typical wellin the basin. No two wells are alike. Initial completion in the well may haveinitial 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 overthe life of the well and then they level out at a lower but steady rate for anumber of years.

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

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

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

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

It will take several months to determine what the impact onreserves 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 programand we budgeted 12 fracs through 2008. But if the results turn out positive wewill certainly increase this number substantially.

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

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

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

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

A successful frac program can add a significant amount ofreserves 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 veryexcited about our core operations at the Sac Basin, as well as the traditionalopportunities we see in our down space and frac programs.

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

Tim Ficker

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

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

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

That an increase is largely due to production, which was upfrom 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 thedifferential of approximately $8.50 from NYMEX for the quarter.

And gas prices were down slightly, about $0.12 for thequarter and again that reflects the differential of approximately $0.45 offNYMEX for the quarter. And I'll note that those prices don't reflect the impactof our hedges and we don't follow hedge accounting for our derivativeinstruments. And the increases in production came from organic growth in oursignificant areas of operation as well as the recent acquisitions that Timmentioned 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 primarilydue to increase in the number of properties we operate as a result of ourcapital 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-yearand production adds from lower cost gas wells in the Sac Basin.

As expected, production increases next year, we expect ourproduction 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 prioryear quarter.

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

And on a per BOE basis, G&A expenses excluding FAS123(NYSE: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 FAS123(R) charges.

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

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

And the Denbury transaction, if we elect a cash option wouldserve as a deleveraging event. And in addition to that our expectations arethat we would, our 2008 CapEx program would be well within cash flow, which allelse being equal would allow us to reduce our outstanding debt balances. That'sa 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 toquestions.

Question-and-Answer Session


(Operator Instructions) And your first question comes fromthe 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 someof the hydraulic fracturing work you're doing in the Sacramento Basin. Withthose three wells you're talking about, are those new wells are those are youre-entering new wells and I guess I'm not sure if you have any thoughts rightnow 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 spacedwells. The first one we did, we did frac the Gwinda well. The other two, thesecond two were Forbes wells. It's just way too premature to even make anyestimate on reserves.

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

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

Nicholas Pope - JPMorgan

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

Tim Marquez

Well, we've drilled one well and the results areencouraging. We initially completed the lower half of the ses, that's ourprimarily producing formation there. The well, that lower half is zoned IP'd itabout 170 barrels per day. We're now just finishing up the work over to add theupper 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 weekor so but that well, no real surprises. It was a good-looking well. I think aswe have said before, because we don't have 3D over the offshore portions of thefield, we're really going to be extending the limits of this field kind of on awell-by-well basis.

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

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

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

Nicholas Pope - JPMorgan

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

Tim Flicker

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

Nicholas Pope - JPMorgan

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


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

Ray Deacon - BMO

Yes. Hey, Tim. I was wondering, what kind of cost might beassociated with increasing the water floods at Manvel, or how much would be inthe 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 onManvel?

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 getmuch credit in your reserves this year for 20-acre down spacing in the SacBasin and probably not much for this well you announced this morning at WestMontalvo. Is that probably right?

Tim Marquez

That's an understatement, Ray. We can't even get full creditfor 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 forour 40 acres. So, I would assume we would get a very marginal amount for the 20acres.

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

Ray Deacon - BMO

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

Tim Marquez

I think you said Gail. I think you meant Grace. Yes, Gracewill 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 forgrowth.

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 51.104million, on the nine-month period we'll have 45,138 or 45.138 million basic anddiluted, and then share count at 9/30 was 50.261 million.


And your next question comes from the line of Gary Strombergof 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 theHastings sale at the end of '08 if it goes it was leveraging event. I guess twoquestions. One is, what debt would you repay, revolver borrowing or that youwould have revolver borrowings? Secondly…

Tim Marquez

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

Gary Stromberg - Lehman Brothers

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

Tim Marquez

Yes. We would look to repay the revolver, and then there'sactually some waterfalls within our term loan and our senior notes. And so itwould 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 byany chance, that you could share?

Tim Marquez

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

Gary Stromberg - Lehman Brothers

Okay. Thank you.


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

Jeff Robertson - Lehman Brothers

Tim, I missed part of the very first part of the call. I waswondering if you could walk through the 2008 guidance increase and just kind ofgive it in order of expectations by the different areas? Which areas are goingto 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 Manveland Montalvo. What kind of numbers are in the guidance for '08 for those newprojects?

Tim Marquez

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

Jeff Robertson - Lehman Brothers

And in terms of the production contribution from each, canyou kind of walk through where in related to the 20% increase, which areas youexpect the largest contribution, or is it going to be similar to the capitalprogram?

Tim Marquez

It will be fairly similar. I think we're going to get, thesingle biggest production increase will be Sacramento Basin and coastalCalifornia and Texas will contribute equally towards that production growth; soit's somewhat similar. It's a little bit skewed because in Texas we won't bespending money on facilities.

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

Jeff Robertson - Lehman Brothers

And secondly Tim, can you point to some of the milestonesalong the way of trying to get the approval for the extended reach at Ellwoodor 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, wehave, already have a preliminary schedule of meetings with the regulators, thedifferent regulatory bodies next year.

Those meetings start first through third quarters of nextyear; I think there was all of about six or seven already on the preliminarydocket 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 ofthe project will look for any weaknesses in the EIR not to kill it but just toslow it down, to make us readjust the EIR, redo the EIR. So, that's the wildcard right now.

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

We're encouraged by the fact that people actually, we've hadat least one environmental group, significant environmental group, has actuallycome out in favor of our project, which is kind of a first for me. I've seensomebody go in public records, to support a project like this, an environmentalgroup 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 walkthrough people all the details of all the different processes you have to gothrough. But that's really captures it pretty well, I hope. Does that makesense?

Jeff Robertson - Lehman Brothers

Yes, thank you.


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

Ray Deacon - BMO

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

Tim Marquez

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

So we need to now that we know they work, now we need tostart optimizing them. The chances that we hit on a perfect formula as astarting point are probably slim and none, so it's really optimizing. But theinitial ones are $300,000 to $400,000. I don't think they're going to vary toomuch 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-acrespacing in the wells you've drilled so far, I guess, how big of a percentage ofthe 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 testedon 20-acre spacing.

Ray Deacon - BMO


Tim Marquez

We tried to hit representative amounts of the field and moreof the central parts of the field. And obviously, I will say we've taken moreperspective parts of the field where we think it had a better chance ofworking. 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 abetter chance of working, is that or are those areas where there's, theselenticular sands are not connected at all or is it where you've got kind of themost gas in place, or?

Tim Marquez

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

You start getting on the fringe of the field, the grossthickness narrows down a little bit or thins out and certainly, the sandcontent goes down significantly as well. So, I'm sure that we'll have our best20-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 thenCO2 for that field, any progress there?

Tim Marquez

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

Ray Deacon - BMO

Okay. Got it. Thanks.

Tim Marquez

Okay. You're welcome, Ray.


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 cantell, we're very upbeat about the continued growth of Venoco. We remain focusedon increasing production throughout our operating areas and having a strongex-rate here in 2007.

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

Keep in mind we spent a lot of money on facilities thatdidn't directly have production attributed to it. So that's really pretty wellbehind 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 lotof good things going on in all those areas. We have the south Ellwood fieldthat 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'regoing to have strong organic growth for many years to come. We see 2008 as astrong year to grow the company organically, improve our financial leverage, aswell as take advantage of accretive acquisition opportunities.

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


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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to All other use is prohibited.


If you have any additional questions about our online transcripts, please contact us at: Thank you!