Venoco Management Discusses Q3 2012 Results - Earnings Call Transcript

| About: Venoco, Inc. (VQ)

Venoco (NYSE:VQ)

Q3 2012 Earnings Call

November 07, 2012 11:00 am ET


Michael G. Edwards - Vice President of Corporate & Investor Relations

Edward O'donnell - Chief Executive Officer

Timothy A. Ficker - Chief Financial Officer


Sean Sneeden

Gary Stromberg - Barclays Capital, Research Division

Eric Busslinger - Marret Asset Management, Inc.


Good day, ladies and gentlemen, and welcome to the Third Quarter 2012 Venoco, Inc. Earnings Conference Call. My name is Kathleen, and I'll be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Mike Edwards, Vice President. Please proceed.

Michael G. Edwards

Hello, everyone. I am Mike Edwards with Venoco. We issued a press release today and our third quarter 2012 results. Later today, we will also file our Form 10-Q with the SEC.

On the call to discuss the results, we have Venoco's CEO, Ed O'donnell; CFO, Tim Ficker, and other members of the Venoco management team. Before we get underway, allow me to make a couple of comments regarding forward-looking statements. All statements made in this conference call, other than statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are subject to a wide range of business risks and uncertainties, including adverse developments in financial markets and general economic conditions. Any number of factors could cause actual results to differ materially from those presented in the forward-looking statements, including, but not limited to, the timing and extent of changes in oil and gas prices, the timing and results of drilling and other development activities, the availability and cost of obtaining drilling equipment and technical personnel, risks associated with the availability of acceptable transportation arrangements and the possibility of unanticipated operational problems, delays in completing production, treatment and transportation facilities, higher-than-expected production costs and other expenses and pipeline curtailments by third parties. 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 with the Securities and Exchange Commission, including under the heading Risk Factors in our annual report on Form 10-K for the year ended December 31, 2011. Please see the earnings release for a disclosure about resource potential and other reserve estimates that do not qualify as SEC proved reserves. The earnings release and the relevant non-GAAP reconciliations are available on the Investor Relations page of the Venoco website, which is

Now let me introduce Venoco's CEO, Ed O'donnell.

Edward O'donnell

Thanks, Mike. Welcome to all of you who've called in or are listening to the webcast this morning as we discuss our third quarter 2012 results.

On October 3, the company closed the going-private transaction contemplated by its merger agreement with Tim Marquez and certain of his affiliates. The certificate of merger was filed with the State of Delaware on the same day and is provided under the agreement. The company is now a wholly-owned subsidiary affiliate of Mr. Marquez. As part of the transaction, the company entered into a $315 million senior secured second lien term loan agreement and an amended and restated $500 million revolving credit facility, with an initial borrowing base of $175 million and initial commitments of $156 million. While the Go-Private transaction was a long process for the company, I want to thank all our employees for staying focused on our core business, producing oil and natural gas in a safe and cost-effective manner.

I'll let Tim Ficker go into more detail on the transaction later in the call. In the third quarter, we remained focused on developing our oily legacy assets in Southern California, investing $48 million in capital. Of that total, approximately $32 million was for drilling and rework activities, $8 million for facilities and $8 million for land, seismic and capitalized G&A.

Capital expenditures in our Southern California legacy fields accounted for $25 million or 52% of total third quarter capital spending. We completed 1 well at our West Montalvo field during the third quarter. That well was spud in the second quarter. In the first 9 months of the year, we spud 4 wells and completed 6 at West Montalvo, which includes 2 wells spud in 2011.

During the quarter, we also completed 1 well at the South Ellwood field that was spud late in the second quarter, and then we spud another well in late September that is currently drilling. In the third quarter, we spent approximately $20 million or 41% of our capital expenditures on the onshore Monterey shale play.

In the first 9 months, we drilled and completed 5 wells in our Sevier field. We've also been processing and evaluating the data from a 28-square mile of 3-D seismic shoot in the Salinas Valley that we completed during the second quarter. The data is helping us identify faulting in the Monterey shale, as well as to evaluate the extent and potential of the deeper Vaqueros Sandstone formation.

The company's third quarter capital expenditures in the Sacramento Basin were $3.2 million, including approximately $820,000 incurred performing 33 recompletions. Our activity level in the Sacramento Basin continues to be significantly reduced from previous years due to continued low natural gas prices. We are seeing some relief, however, as PG&E Citygate prices in October are averaging just under $4 an Mcf. We don't expect to spend the full $255 million in capital that we originally forecast for 2012, and so we've reduced our capital budget to the range of $210 million to $220 million for the current year.

Our daily oil production volumes were up 20% in the third quarter compared to the second quarter and up 41% compared to the third quarter of 2011. The increase was mainly attributed to production increases in our South Ellwood field, partially offset by a scheduled maintenance shutdown at our Sockeye Field during the quarter.

Company-wide, our production averaged 17,899 BOE per day which is an increase of 5% from the second quarter of 2012. The decline in natural gas production rates from the Sacramento Basin continues to partially offset the higher oil production rates from Southern California. Recall that we also sold a small oil property in Santa Clara Avenue field in Ventura County early in May that had been netting us just over 140 BOE per day in 2012. Otherwise third quarter production would've exceeded 18,000 BOE per day.

Our production mix in the third quarter was 51% oil, up from about 45% in the second quarter and up from less than 40% at the beginning of the year. Though it is great to see some recovery in natural gas prices, oil prices bring in roughly 5x as much revenue as natural gas equivalent barrels. So even with higher operating cost for oil properties, an oilier mix greatly improves EBITDA. We expect a reduced capital spending for 2012 to impact our forecasted production by a few hundred barrels, so we anticipate that production will average between 17,150 and 17,500 BOE per day for the full year of 2012.

Lease operating expenses increased 8% to $13.90 per BOE as compared with $12.93 per BOE in the second quarter. The main reason for the quarter-to-quarter increase was our scheduled maintenance shutdown at Platform Gail on the Sockeye Field. Our first quarter operating expenses averaged $15.42 per BOE as a result of nonrecurring maintenance at both Platforms Gail and Holly, and cost relating to discontinuing the use of our Ellwood Marine Terminal.

To 9 months, LOE averaged $14.09 per BOE, which is down 5% from the same 9-month period in 2011. So we've been able to keep a tight handle on operating expenses throughout the year. As result, we've reduced our LOE guidance to the range of $14.50 to $15 per BOE for full year 2012.

Now I'd like to spend a few moments discussing operations in a bit more detail. South Ellwood, after completing the pipeline in January, we were finally able to get back to drilling.

We've drilled and completed 3 PUD wells this year. The first was drilled to the west of the platform, had an initial production rate of about 100 barrels a day, and during the third quarter, averaged about 110 barrels of oil per day. The well has been on gas lift, but we believe it is capable of higher production rates once we're able to lift it with an electric submersible pump.

Our second well is drilled east of the platform and was placed on production late in the second quarter. It has produced steadily since it came on with no water production. In the third quarter, it averaged more than 1,900 barrels of oil per day.

Our third well, which bottomed in the general vicinity of the second well but in a separate fault block, was wet, so we are planning on sidetracking that well.

Early in the fourth quarter, we spud a fourth well at South Ellwood that is to a probable location, northeast of the platform. This location has the potential to prove up an entire new fault block as well as to add PUD locations in that fault block. We set intermediate casing on the well and have suspended drilling the well so that we can move back to the third well to begin drilling that sidetrack.

We expect to have a sidetrack drilled and completed by the end of the year. We'll finish drilling and completing the fourth well in 2013.

We have our annual maintenance shutdown on Platform Holly scheduled for November, which we expect to take about a week to complete. At our West Montalvo field, we drilled continuously from the second quarter of 2011 through July of this year. We drilled and completed 9 wells during that period, all of which were productive. The overall program was spot on with our forecasted performance and provide a robust economics.

Our net production in the third quarter from West Montalvo was 1,960 BOE per day, which is an increase of almost 60% since the third quarter of 2011. We still have 2 wells to place on artificial lift once they stop flowing naturally. We expect an increase of 100 to 200 barrels per day per well when placed on artificial lift. We already have drilling permits in hand for our 2013 drilling program, and we're in the process of securing additional drilling permits.

As we discussed in the second quarter call, we completed our 2012 drilling program on our Sockeye Field in the first half of the year. We drilled and completed 2 horizontal wells into the upper M2 portion of Monterey and drilled a dual completion well producing from the M4 Monterey, while injecting into the Upper Topanga waterflood. We saw an uptick in production from Sockeye in the second quarter as a result of that drilling activity.

In the third quarter, we were busy with facilities and process improvements which allowed us to handle the increased fluid volumes more efficiently. Our scheduled annual maintenance shutdown in Sockeye was in the third quarter and it went as planned.

We're in the process of moving our company-owned drilling rig from Platform Grace to Platform Gail, to replace a contractor-owned drilling rig on Platform Gail. That will reduce our drilling and workover costs on Gail going forward.

We continue to not give recompletion program in the Sacramento Basin, performing 33 recompletions in the third quarter, which brings our 9-month total to 173. For full year 2012, we expect to perform over 200 recompletions in the Sacramento basin. So we continue to be active with recompletions through the end of the year.

With gas prices in the basin currently around $3.90 an Mcf, the economics for these very inexpensive recompletions are very good. As we discussed previously, other than the 3 wells we drilled in the first quarter, we have had no other drilling activity in the first 9 months. However, just a couple of weeks ago, we moved the rig back in and spud our fourth and final well of the year in the Sacramento Basin. We're targeting an anomaly identified on 3-D seismic in the Strain Ranch area, where we have drilled some of our most successful wells in the last couple of years.

Our technical staff has made excellent use of the drilling downtime to better characterize and evaluate our fields at to high-grade the hundreds of drilling locations we have in the basin. We're still closely monitory natural gas prices and the team is ready to ramp up activity when prices strengthen. The bulk of our activity from our onshore Monterey shale continued to be the delineation of our Sevier field in the Western San Joaquin Valley.

We have now spud a total of 12 wells in Sevier since 2010 and continue to advance our completion and stimulation techniques. We've been installing artificial lift in wells and building centralized production facilities. We completed our produced water pipeline in October and since placing it in service have reduced water disposal costs from dollars per barrel to cents per barrel. We're nearing completion of our oil and natural gas pipelines and the corresponding sales and marketing agreements for both our crude oil and natural gas.

Our third quarter production from the field was again limited due to activity on the drill pads and air permit limits regarding flare gas volumes, but we expect to have all wells on production by year end.

Gross field production again topped 250 BOE per day on occasion during September, but the overall average for the third quarter was about 155 BOE per day. Other activity on the onshore Monterey for the third quarter was limited to processing the data from the 28-square mile 3-D seismic shoot in the Salinas Valley in the second quarter. Besides the potential the area has in Monterey, we're also using the 3-D data to evaluate the deeper Vaqueros formation, which we tested in our first exploration well in the area several years ago.

Looking at oil pricing, with the majority of our crude oil being sold under contracts based on California Buena Vista postings adjusted for gravity and marketing, we continue to outpace WTI postings. During the third quarter, average Buena Vista postings were $14 per barrel higher than WTI. The only exception to the Buena Vista postings as a basis for our sales contracts is our South Ellwood crude which is tied to Napo, a water-born crude from Ecuador that is routinely imported to California. Napo has been selling in slight premium to WTI for much of 2012.

Our net after transportation at Ellwood is currently about even with WTI, which is an improvement of $15 a barrel over our old contract for barge deliveries. In the third quarter of 2012, the company-wide weighted average premium before hedging were about $4 a barrel above WTI. Our net realized price in the third quarter before hedging was $96.20 a barrel, that compares to $100.38 in the second quarter and $98.66 a barrel in the first quarter of this year.

Our hedges include basis swaps on WTI to Brent that impact our after hedging realizations. In the third quarter, hedges cost us $9.68 a barrel, up slightly from $9.56 a barrel in the second quarter.

With the closing of the Go-Private transaction, we've reduced our 2012 capital spending forecast from $255 million to between $210 million and $220 million. We're also adjusting our production guidance due to the reduced capital spending, as well as the impact of a one-week shutdown of the South Ellwood field.

For the full year 2012, we are forecasting production to be between 17,150 and 17,500 BOE per day. We are reducing guidance for 2 expense categories as well. Lease operating expense is lowered by $0.50 to a range $14.50 to $15 per BOE, and DD&A is lowered by $0.75 to a range $14.25 to $14.75 per BOE.

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

Timothy A. Ficker

Thanks, Ed. I'll cover a few here from the quarter. Our adjusted EBITDA for the quarter was $55 million, which is up about $13 million compared to the comparable 2011 quarter and up about $10 million compared to the second quarter after considering gains of approximately $11 million in realized upon the early settlement of hedges during the second quarter.

Adjusted earnings for the quarter were $11.5 million, which is up about $12 million compared to the comparable 2011 quarter and up about $9 million compared to the second quarter after considering the gains on early settlement of hedges I just mentioned. Those increases are largely due to increases in revenue resulting from increased oil production, and in the case of the 2011 comparison, improvements in LOE and transportation expense.

Oil and gas revenues were $95.4 million for the quarter compared to $80.9 million in the second quarter. The increase results from higher oil production, which was up about 21% compared to the second quarter, resulting from our SoCal drilling that Ed mentioned earlier, and higher realized natural gas prices, which were up about 20% in the second quarter.

Those increases were partially offset by a 6% decline in natural gas production, resulting from reduced activity in the Sacramento Basin and lower realized oil prices which were down about 4% from the second quarter. Lease operating expenses have increased by $2.8 million from the second quarter and this is due in large part to the cost incurred during the quarter for our scheduled maintenance shutdown of Platform Gail and our Sockeye Field.

On a BOE basis, we report LOE of $13.90 for the third quarter and $14.09 for the first 9 months of the year. Our folks have done a great job of keeping an eye on operating expenses, so we've been able to reduce our full year 2012 LOE guidance to between $14.50 and $15 per BOE.

Transportation expenses were fairly minimal in the past 2 quarters, but there is a $1.9 million decrease from this 2011 quarter, resulting from the elimination of barging operations, which we discontinued in the first quarter of 2012 in connection with the completion of our South Ellwood pipeline. Production and property taxes decreased by $3.6 million from the second quarter and that decrease is essentially -- that decrease essentially represents the return to a more normal level of production and property taxes after recording supplemental taxes during the second quarter, which I discussed last quarter's call.

G&A expense increased from $9.9 million in the second quarter to $11.8 million in the current quarter. And excluding stock-based comp and going-private-related costs, G&A increased to $9.2 million in the third quarter from $8 million in the previous quarter as a result of certain nonrecurring salary-related costs and a settlement accrual related to the Beverly Hills lawsuit.

On a BOE basis, G&A expense, excluding stock-based comp and going-private-related charges was $5.59 for the current quarter compared to $5.15 in the second quarter. On a full year 2012 basis, our G&A guidance remains $5.25 to $5.50 per BOE.

Looking at the balance sheet compared to year-end 2011, our biggest changes were PP&E and debt, which are both off as a result of our drilling programs.

Finally, subsequent to the quarter end, the Go-Private transaction was consummated, and in connection with the closing of the transaction, we entered into a fifth amended and restated credit agreement relating to our revolving credit facility and also entered into a $315 million second lien term loan. The terms and details regarding those agreements will be included in the footnotes to our 10-Q, but as it relates to the revolving credit facility, the initial borrowing base is $175 million and the initial commitments are $156 million. So based on our outstanding balance and outstanding letters of credit, we currently have approximately $51 million of liquidity.

Now we recognize that we have a fair amount of leverage so our focus has turned to the goal of deleveraging and that will be a top priority for us. While we've talked about different options to achieve that goal, we're currently studying and analyzing those options and have not made any decisions yet, so we're not in a position to discuss the status or details of the options under consideration. I know that deleveraging topic may be of particular interest to some of you and once we narrow in on a particular path or 2, we will share as much information as we can.

That's a brief financial overview, Ed, so I'll turn it back to you.

Edward O'donnell

Thanks, Tim. With that, let's open it up for questions about our third quarter results.

Question-and-Answer Session


[Operator Instructions] Your first question comes from the line of Sean Sneeden, representing Oppenheimer.

Sean Sneeden

Just, I guess, following up on some of your going-private presentations that you have put out. I think you had contemplated capital spending for '13 in the $100 million range. Can you discuss or how you are thinking about the spend there? I'm assuming the -- I think the presentation was showing that production would be roughly flat to up. I'm assuming most of the spend for '13 is going towards Southern California and the Monterey. Is that the right way to think about it?

Edward O'donnell

Well, first of all, Sean, some of the presentations you saw on the website were put out there for use of potential investors in the take-private transaction, and those are some previously nonpublic information that we put out to help them evaluate the terms of the deal. But we are just now in the process of putting our 2013 capital budget together, so we haven't finalized that yet. So we have not put out any 2013 guidance yet. So as we get through our capital budgeting process here and get it approved by our Board, well, we expect to have guidance out by sometime in December, and then we'll follow that capital budgeting process. So we haven't nailed down what size of that budget is going to be yet for next year, however, I can make some comments about, I guess, going forward. One is that, again, given our leverage situation at the moment, we certainly will expect to keep our budget within operating cash flow. So we expect to be very disciplined going forward, and that will determine the size of our capital budget. And we will focus that -- those investments on our low-risk, high-return oily properties, which is Southern California. So I think you can expect to see activity in Montalvo, where we've been very successful and we're teed up and ready to go again for 2013, and you'll see some -- expect to see some activities in South Ellwood as well and a follow-up with very successful 2,000 barrel a day well we had there earlier this year, and probably some activity at Sockeye. Again, our 3 big oil properties in Southern California, I think that's where you can expect to see the activity. We will continue to be, I think, very disciplined in taking an objective look at our Monterey holdings. As you know, we've previously curtailed drilling there in the Monterey. And right now, we're really focused on pulling together all the information that we have, that we've gathered in the last couple of years there, particularly in Sevier. As you know, we've focused our efforts in the Sevier field, and we're in the process now of getting all those wells on production. And once we have our gas pipeline tied in, then we'll be able to put everything on production without constraints, get little more -- longer duration production testing from each of those wells, and we'll be able to, I think, focus on what is a commercial development there. But we don't see -- we don't plan to have much drilling activity in 2013 in the Monterey, but I think you will just see us getting everything on production and regrouping and seeing where we're at in terms of that development. And in the Sacramento Basin, I think you'll see more of the same there. I think you'll see some additional recompletion work because those recompletions are very inexpensive and have payouts in the 1-to-2 month kind of timeframe, so they -- we get our money back very quickly. You'll continue to see that kind of activity, and I think you'll continue to see very little drilling activity there going forward until prices improves substantially from where they're at.

Sean Sneeden

Okay, that's helpful. So I guess from what I'm hearing then, it's that your -- the core of what you're really going to be spending on is the Southern California legacy oil assets then.

Edward O'donnell


Sean Sneeden

Okay. And then can you just kind of giving the sort of rise in gas price and where the strip is today, where would you feel comfortable reallocating money back to the Sac Basin?

Edward O'donnell

Well, that's -- I guess, there's a couple of parts to that answer, Sean. And I think one thing is that the technical work that our folks have done there, they've done a good job of high-grading our opportunities there. We have a lot of opportunities there, a lot of infield drilling, but it's not all the same. And we have a much better feel, I think, now for the better areas and maybe the lesser attractive areas. And so they have different economics and different oil or different gas prices so we have some projects that are -- that has some good solid economics at $3.75 an Mcf. And as you go, get higher and higher prices, more of those projects come into play in terms of having some robust economics. When you get the range of $4.25, let's say, or so above that $4.25, $4.5, somewhere in that range, mostly everything up there has some good economics. So however, having said that, these projects will still have to compete with oil projects in Southern California, so we're going to still focus on what has the best return and the best use of our capital, our limited capital, going forward. So with that mentioned, I want to stress that we are going to stay within our cash flow and we're going to be very disciplined. We're going to rank projects, and we're going to put the capital where we can get the best return and the best risk reward ratio. And that is probably going to continue to be our legacy oily assets in Southern California. So even if we get some better gas prices, they're still going to have to compete for limited capital, Sean.

Sean Sneeden

Okay, that's pretty helpful. I guess just one follow-up on that. When you said spend within cash flow, is that -- are you saying operating cash flow? Are you including any sort of divestitures within that cash flow number?

Edward O'donnell

No. I'm talking about operating cash flow, Sean. And that's -- on the one hand, we're really focused on deleveraging the balance sheet, as Tim just mentioned, and that is our priority right now. But at the same time, we understand that going forward, you still have to be reinvesting in your business to maintain production levels and maintain operating cash flow, so we'll be aware of that as well. And that's why we will have a capital spending program next year and continue to invest in our best projects and our best properties, but we'll certainly stay within operating cash flow. And deleveraging is a whole different piece of it, so -- in terms of raising capital to improve the balance sheet.

Sean Sneeden

Okay, that makes sense. And then could you just briefly update us on where you guys are on Hastings? I think, previously, you had thought about selling your stake and then I think that might have changed. What are your current thoughts on that asset?

Edward O'donnell

Yes. There's been talk about that in the past, Sean, in terms of monetizing that asset. It isn't a core asset to us, certainly, it's a non-op situation where we have a reversionary interest, as you know, that we back into 22.3% working interest at some point down the road here after Denbury has recovered certain costs associated with developing the CO2 flood there. But the performance of that field so far -- and it's early in the overall process here, it's such a big field and the CO2 flood is being implemented in stages that will actually go on for several years, but the production performance of that field this year now is greatly exceeding the operator's expectation. And -- I think you're going to -- but it's still early. We're still in just the fault block A and now there's actually a lot of stages to go. So we really like that project, we like the performance they're seeing and you're going to see increases in production there going forward now. The production came on, I believe, late January this year. The field has been somewhat facility constrained as they've tried to get additional compression out in the field to handle the recycled CO2. And there will be additional compression installed before year end, and that'll give a big bump-up in production. And then there's additional compression scheduled for the first and second quarters of next year, so you're going to see the oil production continue to ramp up there and what is shaping up to be, I think, a very successful CO2 flood. So the bottom line of all that is, obviously, we, Venoco, don't have any cash flow from Hastings today, but it has tremendous future value to us when we back into that working interest. So the issue has always been can we get what we think is fair market value for that property and it maybe a little early yet in the life of the CO2 flood to achieve that. And of course, Denbury has the first right of refusal on that sale as well. So it is an option available to us. It's one we're looking at, but it's -- we like that project a lot. It has a lot of future value, and this may not be the time to monetize it, but that is an option that's still on the table for us.

Sean Sneeden

Okay, that's helpful. And so I guess, it sounds like you guys wanted to see how the oil ramp really goes probably next year, and then at some point, kind of reevaluate where you are. Is that sort of a fair assessment?

Edward O'donnell

Yes. It's worth more every day to us, the way I see it. Because everyday the performance improves, the production goes up and that is -- the performance is demonstrated by actual performance out there rather than just projections. So every day that goes by adds value for us. So we monitor it all the time and we have our own technical personnel following it. So we'll watch it all the time, and I think 1 year from now, you're going to see that it's worth a great deal, more value even than today.

Sean Sneeden

Okay, that's helpful. And I guess just one last one for me is I know you said you don't have that much detail on the deleveraging plans yet, but perhaps just kind of thinking about it in a very broad sense, can you kind of talk about what you see as sort of the ideal leverage for the company kind of in the long-term basis? I think, during the marketing of the going-private transaction, you kind of thrown out a 2.5x sort of debt-to-EBITDA level. Is that sort of the right way to think about where you ultimately kind of want to go with this balance sheet?

Edward O'donnell

Yes. I think that's a good long-term view, Sean. We want to do some things here in the near term to deleverage. It won't get us perhaps all the way there in the next several months, so that 2.5x EBITDA is probably a longer-term figure to be looking for, but we're looking at some deleveraging options that will get as part of the way there much sooner. So I guess there's just your time horizon, and I think there's some deleveraging options here in the near term, and then they are continuing deleveraging options further out that would get us down to that kind of level. We want to get down to that kind of level so we can be more active in making acquisitions going forward. As you know, that's kind of the legacy of our company, how it's built is through acquisitions and exploitation of good properties that we've been able to acquire. And we want to get back into that arena and be more competitive in that, but we need to establish some free board, if you will, on our balance sheet, I think to be as competitive as we want to be in that sector. So I think that is still a goal that we have, is to get down to that kind of range.


Your next question comes from the line of Gary Stromberg, representing Barclays.

Gary Stromberg - Barclays Capital, Research Division

Can you guys just talk about decline rates in Southern California and Sac Basin? Can you help us understand what CapEx level is needed just to keep production flat?

Edward O'donnell

Well, yes, decline rates in Southern California, in fact, most of California, I guess, as we look at it, I think very shallow compared to most places in the country anyway. We've got properties ranging from maybe 3% to 15% if you look at property by property, but in general, we're probably more of a 7% decline rate kind of region down there, I guess, somewhere in that range. So it's -- they're modest decline rates, and so we look at modest levels of capital spending to keep production relatively flat. So the Sac Basin has had a little higher decline rate. But some of that is -- a matter of fact, we've had so much activity in the last few years, and I think decline rates there are actually softening, if you will, because it's been some time since we've had an active drilling program there. So we've seen a fair amount of decline the last year or 2 there, but now as these wells kind of settle in and get off that initial decline rate, that initial part of that curve, they're selling in at a more like in the 10% kind of range. And again, so that lessens the amount of capital going forward to keep capital spending flat or to keep production flat there, too. So I don't know what the exact number is going forward, but our maintenance capital levels are pretty modest. So we'll be able to certainly budget, I think, considerably more than just maintenance capital, I think, for our properties for next year.

Gary Stromberg - Barclays Capital, Research Division

So in the third quarter, you spent $25 million in Southern California, excluding the Monterey shale. And it sounds like in the fourth quarter, overall, you're going to spend around $35 million. I assume that's pretty minimal spending again on the gas assets and most of that in Southern California oil. And it looks like production declines at that $35 million level. So is it higher than that $35 million a quarter level that you need to spend to just keep production flat overall? Or can you just help walk through that math?

Edward O'donnell

Well, production's actually up quarter-over-quarter and our oil production, as you've seen, has grown substantially throughout the year with the capital spending in oil. So oil has gone up substantially, gas has declined because we haven't been spending there. And overall, we're not quite flat, we're actually up, I get what, 5% quarter-to-quarter, I guess, overall production on that basis. So part of the issue is we've changed our mix a great deal. You're seeing more high-value oil and lesser value gas changing places there. Also, we had our annual maintenance shutdown in our Sockeye Field during the quarter, so that offset some of the increased production we saw as well. And then the -- in the fourth quarter, you're going to see a planned annual maintenance shutdown at South Ellwood as well. So that kind of tempers the production volumes you see there.

Gary Stromberg - Barclays Capital, Research Division

Okay. So if I could just paraphrase. It sounds like over the last 4 quarters, CapEx, let's say, was $220 million in production. From fourth quarter '11 to third quarter '12, it's just about flat. But if you cut back spending on some of the Monterey, do you think that, that number to keep production flat is a lot lower than that $200 million plus number?

Edward O'donnell

Oh, yes, it's less than $100 million, yes. I believe for our assets is, I think, is probably substantially under $100 million [indiscernible].

Gary Stromberg - Barclays Capital, Research Division

Okay. And then just on the debt balances. Can you just review what we should expect for year end? I think it's around $100 million on the revolver, $315 million in term loan, $650 million notes, but I just wanted to make sure that, that was correct.

Edward O'donnell

Yes, let me turn that over to Tim, Gary.

Timothy A. Ficker

Yes, Gary, that's where we are right now, and I don't think you'd see a substantial change in that. I mean, we are focused on deleveraging, and if we have the opportunity to do something between now and year end, we certainly will, but I think that, that would be a pretty aggressive timeframe.

Gary Stromberg - Barclays Capital, Research Division

And how much cash roughly?

Timothy A. Ficker

Well, since we get our revolving credit facility, we generally tend to use that cash to pay down the revolving credit facility so we don't carry much cash on the balance sheet at any particular time.

Gary Stromberg - Barclays Capital, Research Division

And when is the next borrowing base for determination?

Timothy A. Ficker

Actually, we're in the process of that right now. But the credit facility which we put in place in conjunction with the Go-Private transaction October 3 used the midyear reserve report to establish the borrowing base. And typically, in the November borrowing base redetermination, they used that midyear reserve report for that redetermination. So we don't anticipate any change there.


[Operator Instructions] Your next question comes from the line of Eric Busslinger, representing Market Management (sic) [Marret Asset Management].

Eric Busslinger - Marret Asset Management, Inc.

Marret Asset Management. Just regarding the Hastings Field. Could you guys give us rough estimate of when you think Denbury is paid out its cost of capital and then the reversionary interest that's in?

Edward O'donnell

Yes. That's kind of a moving target as you probably know. I mean, obviously, it depends on several factors, the production performance of the field, commodity prices going forward and so forth. But -- so there are a range of estimates, I guess, is the answer to your question. And we're looking at probably 2016 on the earliest probably, late 2015 or early 2016 on the early end, and maybe even 1 year or 2 later than that or so depending on all these various parameters. So it's a few years out yet to back in, but I'd say it's -- whatever your prediction is on those parameters will get you there, I guess.


With no further questions, I'd now like to turn the call back to Mr. Ed O'donnell for closing remarks.

Edward O'donnell

Thank you for your questions, everyone, and thank you to all of you who listened to the webcast this morning. Replay information of this call will be posted on our website on the Investor Relations page. So again, thank you and have a good day.


Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.

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