Tim Marquez - Chairman and Chief Executive Officer
Timothy Ficker - Chief Financial Officer
Mike Edwards - Vice President, Investor Relations
Jeff Robertson - Barclays Capital
Gary Stromberg - Barclays Capital
Venoco, Inc. (VQ) Q3 2008 Earnings Call November 6, 2008 10:00 AM ET
Good day ladies and gentleman and welcome to the third quarter 2008 Venoco incorporated earning conference call. My name is Kenisha and I will be your operator for today. (Operator instructions)
I will like to turn the call over to your host, Mr. Mike Edwards, Vice President of Venoco. Please proceed sir.
Hello everyone, I’m Mike Edwards with Venoco. Venoco issued a press release today in our third quarter 2008 results, we also filed our third quarter forms 10Q at the SCC. 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 statements made in this conference call, other than statements of historical fact are forward looking statements within the meaning of section 27A of the securities act, 1933. And section 21E of the securities exchange act in 1934. These statements are subject to a wide range of business risks and uncertainties including adverse developments in financial markets and general economic conditions.
Any number of factors could cause actual results to differ materially from those presented in the forward looking statements, including but not limited to the timing and extent of changes in oil and gas prices. The timing and results of drilling activity. The possibility of delays in completing production, treatment and transportation facilities. Difficulty obtaining third party services including transportation and higher than expected production costs and other expenses.
The SEC permits oil and gas companies to disclose their filings within their filings with SEC only prove reserves, which are reserve estimates that theological 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 potentially be recoverable through additional drilling or recovery techniques are by their nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the company.
Forward looking statements made about the Hastings Complex and the contract with Danbury Resources are subject to business risk and uncertainties not in Venoco’s control including but not limited to the purchase price and Venoco’s use of proceeds; the implementation of a CO2 flood, and the production results and reserved if the flood is implemented. Information regarding results from hydraulic fracturing program in the Sacramento Basin is based on results to-date, which are preliminary and future results may differ.
All forward looking statements are made only as of the date hereof and the company undertakes no obligation to update any such statement. Further information on the risks and uncertainties relating to forward looking statements are set forth on our filings with the Securities and Exchange Commission, including under the heading risk factors in our annual report on form 10K for the year-ended December 31st, 2007.
The earnings release and the relevant non-GAAP reconciliations are available on the investor relations page of the Venoco web site, which is www.venocoinc.com. Now I’d like to introduce Venoco’s Chairman and CEO Tim Marquez.
Thanks, Mike and welcome to everybody’s that called into the webcast. I’m very pleased today to review Venoco’s third quarter results, before I get into details, I’d just like to make a few observations about the market. I know I’m not telling anybody anything new here when I say capital markets are bit in disarray, and of course credit markets are tough right now.
The good news is, we have no current needs to access them. None of our term-debts instruments mature until late 2011. Our senior credit facility is relatively small, about $200 million. And our bank groups appeared very solid and borrowing base conservative, Tim Ficker will talk more about that later.
In addition, we’re expecting significant cash-inflows early next year related to sale of our Hastings Field to Danbury.
On the cash-flow front, prices have been volatile but a significant portion of our oil and gas our ahead. Our 2009 oil floors averaged about $58 with CAPS around $74 a barrel. On the gas side, our 2009 floors averaged over 785 per MCF and CAPS are at 1140 per MCF.
Finally, we’re reducing our 2009 capital budget to $300 million and we have the flexibility to reduce it much further should it become prudent. Talk a little bit more about our reductions here in a little bit.
So take-aways, we have no plans to access the markets at present. The Hastings sales proceeds will provide due-leverage and we have significant flexibility to adjust our capital spending and we have plenty of hedges to protect against erosion of commodity prices.
So I’ll dive right in now a little more detail starting with production. Our average daily production for the quarter was 21, 949 barrels of oil equivalent per day, which as we discussed in our second quarter conference call, was up as expected from our first half average of 21,030 BOE per day.
We have scheduled downtime in the second quarter we estimated affected second quarter production by about 500 BOE per day. We expect production to increase in the fourth quarter, we remain on target to hit our forecast for full-year 2008 of more than 21,500 BOE per day.
Report of production for the third quarter was up 6% year-over-year in third quarter 2007. While year-to-date reported production is up 10% compared to the 2007 period.
With third quarter CapEx expenditures, we’re $66.7 million, with approximately 61% spend in the Sac-Basin 19%, spend in Southern California, and 13% Texas. For the first nine months of this year, our capital expenditures were $210 million, which puts our pegs slightly below our forecast for the year of $300 million.
Moving to operating expenses and G&A costs, third quarter leaks operating expenses were 1789 per BOE, which is an increase of 16% from second quarter of 1540. An increase in third quarter expansion is primarily due increase work over activity in our Sockeye Field and higher powered costs in Texas. We also had additional property tax in California.
Third quarter GNA expenses were 507 per BOE, down from the 636 we saw in the second quarter, although that number included a one time charge we incurred when we withdrew our application to form an MLP. Excluding non-cash FAS-123 charges our G&A in the third quarter is 450 per BOE compared to 439 in the second quarter, excludes a one time MLP charge and the non-cash FAS charges.
Tim Ficker will give you additional detail in expense later in the call, now we’ll move to operations. Starting in Southern California, the Westman Tobol Field (ph) field, we’ve seen production increase nearly 50% year-to-date as a result of our ongoing effort to (inaudible) wells to production. Up side in our lift capacity and upgrading service facility. So things are going quite well there.
We continue to convert certain wells to water injection, which allows us to handle the additional water volumes from our field revitalization. In addition to well work products, late in the quarter we initiated drilling in field wells that bottomed beneath the on shore portion of the field. Keep in mind, this is the field that straddles the coastline and last year we drilled wells to the off shore portion and these wells now are going to the on shore.
We expect the first of these wells to perforated and online by the end of this month. We pushing back our plans to do a 3D seismic survey over the acreage until sometime next year.
Moving offshore, the water flood and Sockeye Field at platform continues to perform quite well and we are seeing gross oil rates around 5,520 barrels a day. I’ll remind you from last quarter’s call that first reserved report after required the asset 99 predicted by now, we’d be down about 2,300 barrels a day, so the bulk of that difference you can see is the water (inaudible) has been quite successful.
We did have some expensive work over in the quarters, unwell to dual completions, which pushed production expenditures much higher for the quarter, so those are generally non-reoccurring costs there.
In the South Ellwood Field, we completed some facilities where we’re concluding the installation of a new crane that will benefit existing operations, as well as our project to expand the lease boundary. As we mentioned on the second quarter call, the State Lands Commission released a draft EIR to public in June and we provided comments to the commission by the due date late in August. Now the state lands commissions is working to finalize EIR taken into count all of the comments they’ve received.
We don’t anticipate a final EIR until after the first of the year, so early 2009. So the earliest we can be in front of the State Lands Commission, the lead agency here, is February of 2009. After approval by the State Lands Commission, other jurisdictions, primarily the county of Santa Barbara and the City of Goleta can schedule hearings.
We believe the approval process can be completed by mid-2009. Afterwards, the project would be ready for immediate start up. The first item in the project is construction of a 10-mile on shore pipeline, along with facilities at our on shore processing plant and on platform Holly. Actually drilling from the platform could commence after some of the facilities in the pipeline work or completed, which we hope will be in the latter half of 2009.
The development program consists of wells drilled in the eastern portion of the field, as well as the current least bit portion of the field. Using our existing platform and extended reach drilling technology. Again I emphasize that the project actually reduces infrastructure on the coast by replacing the barging operation that currently transports our crude oil to market. It will be replaced with a pipeline.
The new pipeline will connect to existing segment of all American pipeline that Exxon Las Flores Canyon facility. Maturing pipeline ride-aways an anticipation to approval to projects continues and we’re initiating certain capital expenditures to long-wait items.
Moving to Texas, we some effects from downtime related to Hurricane Ike in mid-September. We had no major damage but did have power poles and lines down throughout our Hastings and Mandeville fields. Although we were able to get power restored from the utility companies in a little over a week, we weren’t able to get back to full-production by the end of the quarter. Our focus in both fields continue to be returning wells to production, converting gas as well as electrical submersible pumps and then adding fluid processing injection capacity.
In Hastings, due the pending sale to Danbury, we’ve focused on projects that maximize reserves. We’ve been very pleased with the work in these two fields this year, so everything really continues to go quite well there.
We’re working with Danbury resources regarding their purchases of the Hastings field and the implementation of a CO2 enhanced recovery project. Danbury exercises option to purchase the Hastings field and we continue to meet regularly with our technical staff on CO2 development plan. And to coordinate our activities in the field and prep for the closing on February 2nd, 2009.
Unless we reach an alternate agreement with Danbury by December 1st, we look to the formula in agreement to determine the sales price. As a reminder, the formula calculates a present value discounted at 10% for the field, based on the total proved reserve from our year-end 2008 reserve report. Using a five-year nine (inaudible) strip as a 12/31/08 for prices and other factors relating to operating expenses. As a reminder in our investor presentation October 1st, we gave some indications of the sales value would be of Hastings at different pricing areas.
As an alternative to taking cash, we may elect to receive a volume metric production payments plus some cash. We continue to evaluate these two options based on credit market conditions, commodity prices and other factors. Regardless, if we take cash in the VPP, we will retain an overriding royalty interest of 2% in the properties. The deeper rights and back into a working interest of approximately 22% in the CO2 project after Denbury various costs and expenses.
As we said previously, the backing is very valuable to us. We think ultimately reserves net to Venoco related to the backing could be upward of 30 million barrels, which is significantly more than we’re selling to Denbury in the aforementioned sale.
Manvel Field presents a similar opportunity as Hastings of CO2 flooding potential because of its similar reservoir and crude characteristics. We’re currently designing a potential CO2 flood at Manvel and exploring potential CO2 sources.
Moving back to Northern California and Sacramento Basin, everything continues to go quite well in Sacramento Basin. Our activity levels remain very high where we continue to drill in field wells in the greater Grimes and Willows fields. We have five drilling rigs and five work over completion rigs working the basin but at 84 well, completed 61 wells, and performed 98 work overs and recompletions in the first nine months. For the full-year, we expect to drill about 120 new wells, perform 125 work overs and recompletions.
In addition to recompletions, we continue the hydraulic factory program that we’ve been discussing through the year. Today we fraced 47 wells through the first nine months and we’re very encouraged by the initial success of the program, which began less than 12 months ago. We’re still on pace to perform about 75 fracs in the basin this year. We’ve also implemented multi-stage fracs, which we expect will enhance the efficiency of the overall program.
We’re working to understand all the signs and makes of various formation and pace these fracs the best. On the fracs that have been successful, we’ve seen the average IP several times higher than the pre-frack rate. Some of the successful fracs have been on wells an considered to be depleted.
We’ve added to our acreage position in the basin and now have more than 200,000 net acres. During the third quarter, we started 25 wells, performed 43 work overs and recompletions. Production is up in the third quarter by almost 1.2 million cubic feet a day second quarter and up over 10 million, that’s 23% compared to third quarter 2007.
All in all, as I said before, everything is going quite well in Sacramento Basin and continue to see more opportunities, continue to see improved performance from the frac, so still just as excited as ever before. And still, we’ve talked a little bit about the Glenda (ph). We expect to be doing some work on the Glenda in the fourth quarter in terms of fracing to see if we can unlock the potential there.
On the exploration front, on the second quarter call, we talked about some of our exploration efforts. We continue to see the longer term strategy to discover new fields and expose companies to prospects with larger upside. We continue to build acreage positions in several basins new to Venoco to play to our core competencies as well as expanding our position in Sacramento Basin. All told, we have about a half-a-million acres in various prospects and various stages in the process. The situation, particularly basins, is still competitive so we won’t go into too much detail in those.
On the specific initial drilling targets we’ve identified, we’re continuing the permitting process and the plan’s sped up to two wells by year end. One of the wells we expect to spout here in a couple weeks is another prospect in the Pacific Northwest that we discussed in some detail in our last call. We do like to say this is not the Columbia Basin.
This is much shallower towards the coast, Astoria Basin, and so we’re pretty excited about the large potential here. Well departers on the well into Pata County Texas (ph), it was spouted late in the third quarter, which is successful, would be run by our local Houston office.
Moving to the 2009 capital budget, as I mentioned earlier, we’re dropping our capital budget for 2009 to 300 million. Obviously in a lower price environment, acquisitions take precedent over drilling and what we’ve always done for 16 years is beef up acquisitions in low price environment and drill more when prices get higher. Not exactly a revolutionary strategy, but one of the main reasons we’re dropping our CapEx budget.
The splits among our various operating regions are roughly the same as the original budget. This budget should allow us to achieve production in the 20,000 to 21,000 barrels per day range for 2009, about a 10% growth rate pro forma for the sale of Hastings. I want emphasize again, that’s 20,000 to 21,000 net of the sale of Hastings. This budget allows us to maintain our current level of activity in the Sacramento Basin, demands of South Ellwood fuel field development project and continue our Monterrey and Pacific Northwest exploration programs.
We also proceed with our development plans in the Manvel Montalvo field go to slower rates than originally planned. As I mentioned earlier, our budget maintains sufficient flexibility to further reduce the budget as we proceed in 2009. With that, I’d like to introduce our CFO Tim Ficker, who’ll go over our financial highlights.
Thanks Tim. Looking at our earnings of 221 million for the third quarter I’ll note that that includes a sizeable non-cash unrealized gain for our commodities derivatives, about 210 million after tax, which resulted from the significant swing in commodity prices from June 30th to September 30th. When we adjust for that as well as the non-cash gain on interest rate derivatives, we generated adjusted earnings of $11 million for the third quarter.
Our adjusted EBITDA was down from 84 million in the second quarter to 71 million in the third quarter. And both our adjusted earnings and our adjusted EBITDA were impacted by builds in our inventories, which reduced reported revenues and higher production expenses. I’ll give a little more detail on those shortly.
Oil and gas revenues were $158 million for the third quarter, which represents a 5% decrease over the second quarter. That decrease was driven by a production and commodity prices where we saw a decrease in our realized oil price of about $5.30 per barrel and decrease in realized gas price of about $1.50 for MCF compared to the second quarter. It was also driven by a decrease in our sales volume.
Now, here’s where I want to give a little color on our inventory build during the quarter. Our revenues are obviously a function of the commodity prices we received and the volumes that we sell as contrasted with the volumes that we produce. Typically we don’t have a significant difference between our sales volumes and our production volumes.
During the third quarter, our oil inventory grew by around 88,000 barrels, which means that we produced more barrels than we sold. As a result, our reported revenues for the quarter were reduced by about 7.2 million to reflect revenues for only the volumes sold. This inventory build during the quarter was largely driven by oil shipment delays, including delays in picking up oil produced from our South Ellwood field, which resulted from our plant maintenance events on the barge that transports that oil. And we expect the majority of the inventory impact to reverse in the fourth quarter.
Our production expenses increased about 28% in the second quarter to about 42 million in the current quarter. And I’ll remind everyone that our production expenses are composed of lease operating expenses and production and property taxes. And during the third quarter we incurred increased LOE as a result of the higher power cost in Texas as well as the additional work over activities as Tim mentioned earlier in our Sockeye Field.
With respect to our production and property taxes, we recognized additional property taxes in California as a result of our increased development program as well as increases in property value. Now the additional taxes that we recognized in the third quarter include catch-up supplemental investments of between a million-and-a-half and $2 million that we don’t expect to see again in the fourth quarter.
Turning to G&A, the G&A decreased to $10 million in the third quarter from 12 million in the second quarter, resulting primarily from $2.7 million non-cash write-off for the deferred MLP cost that we recognized in the second quarter, which is partially off-set by additional cost associated with special staff and relate infrastructures made to accommodate our growth.
On a BOE basis, our G&A expenses excluding FAS 123R charges and the non-cash write-offs were 450 for the third quarter compared to 439 for the second quarter. Commodity derivatives gains loss is the other significant part of our income statement. And as a result of the significant downward movement in oil prices between quarters, we recognize the pre-tax gain in this category of 303 million for the quarter. And of that amount, 339 million was due to unrealized change in fair value and that was partially off-set by $34 million of realized losses and $1.6 million of non-cash amortization (inaudible) of our commodity derivative premiums.
Turning to the balance sheet, the biggest changes there were our PP&E, which was up as a result of our CapEx program and some small acquisitions and debt, which was up as a result in a swing in our working capital as well as our CapEx program in those small acquisitions. And then also, commodity derivatives and interest rate derivatives saw sizeable increases from year-end resulting from increasing commodity prices between year-end and 9/30, which were slightly off-set by our interest rates.
Regarding our debt, I’ll mention a couple things. First, as we previously disclosed, Lehman Commercial Paper is one of the lenders in our revolving credit facility. They’re the smallest lender in our group at about four-and-three-quarters percent of the facility. And as you can probably imagine, they’re no longer funding borrowing requests made under our revolver.
Currently we owe Lehman a little under $5 million and as a result, the availability under our $200 million borrowing base is effectively 195 million. We will continue to seek to replace Lehman in our facility; however, we don’t view the Lehman situation has a significant impact on our liquidity.
Next, I also want to point out that we believe that our borrowing base is very conservative and our asset base supports a much higher borrowing base, although we haven’t asked for our banks to increase that. So overall, I’ll reiterate what Tim said earlier. As a result of our cash on hand and the existing availability under our revolver, we don’t face any near-term liquidity issues. That’s a brief overview. Tim, I’ll turn it back to you.
Thanks Tim. With that, I’d like to open it up to questions.
(Operator Instructions) And your first question comes from the line of Jeff Robertson from Barclays Capital. Please proceed.
Jeff Robertson - Barclays Capital
Thanks Tim. In the guidance you all have for 2009, do you have any contribution in it for the exploration program or for South Ellwood?
No, good question Jeff. I’m glad you asked that. We never budget for any exploration success. Although we hope to have some, we don’t budget for anything. And then South Ellwood, although we do think we could have some production on by the end of the year, we don’t have any production forecast for that as well.
Jeff Robertson - Barclays Capital
Then secondly, on the capital program, you talked a little bit about acquisitions, would you all defer some of your own activity if you found the right acquisition?
Yes, like I said, we’re opportunistic. I like the low oil price times. It’s obviously when we can make our best acquisitions. Historically that’s when Venoco’s done its best. And so, if we do see some good strong acquisitions, and we definitely are seeing a change in sentiment out there. People, I think, are much more realistic than they were this past year. Being in an oily state, it was very frustrating this last year with prices at $140 and sellers thinking it was going to go to 200, we just weren’t there acquisition-wise in terms of value.
But we’re seeing some reality come to the market and are more optimistic now about getting some acquisitions done. Obviously if we do, we’d probably defer some CapEx, probably skinny up some of the exploration. So we do have a lot of flexibility in our CapEx program depending on the success of acquisition efforts.
Jeff Robertson - Barclays Capital
You’re welcome Jeff.
And your next question comes from the line of Gary Stromberg from Barclays Capital. Please proceed.
Gary Stromberg - Barclays Capital
Hi, good morning.
Gary Stromberg - Barclays Capital
Could you guys just help reconcile on Hastings? Denbury, I think, early this week said that they expected a $150 to 250 million purchase price I guess of prevailing prices versus what was in your October presentation. And then number two, the waterfall of how you’d proceed with those funds, whether you’d take out the $70 puts which look pretty good right now.
Yes, I’ll let Tim or Bill Schneider address the waterfall, but in terms of the price, in our October 1st presentation, we still felt comfortable with those numbers and in that presentation we put different prices depending on prevailing oil and gas prices so I’d refer everybody to those.
Denbury has their opinion. We have ours. We feel these are solid numbers there in the presentation. So if you could refer to that, I hope that’ll help. In terms of waterfall, Tim, do you want to talk him through that?
Yes, I think you’re right. The $70 puts look pretty good right now given where the credit markets are. We take a hard look at any hedges. To take out any hedge, we would have to take out a portion of those hedges if we sold the volumes to get in between our 70 to 80% requirement under our credit facilities, but we take a hard look at that. And then after that, as far as the waterfall goes on the use of proceeds, we use half of it.
We can designate half of it to reinvest and then half of it is required to pay down debt. And that would go to pay down our revolver first to 75% of the borrowing base and then the remaining portion would go to the term. But then obviously we could use the other half that we reinvest to pay down the revolver and keep some dry powder.
Gary Stromberg - Barclays Capital
Okay, great, thank you very much.
(Operator Instructions) At this time there are no more questions in queue, I will now turn the call back to Tim Marquez for closing remarks.
Thanks for the questions and thanks for everybody for listening to today’s call. We’re pleased with our third quarter results and where we are after three quarters of the year has finished. Despite the down turning commodity prices, we’re still at a price level—I’ve got to remind everybody—that are higher than we’ve seen for about 90% of the company’s history. So, I’m still bullish on pricing. I think these are actually pretty healthy prices for Venoco.
I think we’re better positioned than ever before in terms of growth opportunities when you look at the CO2, the South Ellwood, the Sacramento Basin drilling program near Manitoba, just our exploration for the longer term growth. I feel very good about where we’re positioned right now. Based on our hedging program and looking at the forward strip, we don’t foresee any liquidity issues.
We’re excited about the opportunities that we have: the results of the in the sell of the Hastings complex, an opportunity to reduce our debt levels, provide funding for 2009 capital expenditures, position the company to take advantage of strategic opportunity and we’re excited about a position in the Sacramento Basin as a result from our activities there. We see a lot of existing opportunities to end fuel wells, drill new step out wells, frack wells, re-complete work over wells, as well I mentioned before to unlock the deeper upside, primarily in the Goleta formation.
I didn’t mention, but about half our wells in the Grimes area continue to go down to the Goleta. On paper these all look very good. We expect to frac a few Goleta wells in the fourth quarter here to see if we can unlock that potential.
The short-term benefits of selling our Hastings production to Denbury will have a lot of benefit to reducing our debt and enhancing liquidity. Long-term, with a successful CO2 flood there, we see our back end as a big addition to reserves. We’ll move cautiously in our exploration projects.
We believe they have the potential in the longer term to provide additional areas for the company to find production and reserves. We’re moving very close to having the final EIR on the South Ellwood fuel field development project and looking forward to beginning and hopefully completing the approval process at the various stages of 2009.
Thank you all very much and look forward to talking to discuss year-end results early next year.
Thank you for your participation in today’s conference. This concludes the presentation. (Operator Instructions) Good day.
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