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Venoco (NYSE:VQ)

Q4 2012 Earnings Call

April 16, 2013 11:00 am ET

Executives

Kevin Hehn

Edward O'donnell - Chief Executive Officer

Timothy A. Ficker - Chief Financial Officer

Douglas J. Griggs - Chief Accounting Officer

Analysts

Sean Sneeden

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

David Zimmerman

Operator

Good day, ladies and gentlemen, and welcome to the Venoco, Inc. Fourth Quarter and Year End 2012 Earnings Call. My name is Sharon, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes.

I will now turn the call over to Kevin Hehn with Venoco. Please proceed, sir.

Kevin Hehn

Hello, everyone, I'm Kevin Hehn with Venoco. We filed our 2012 10-K with the SEC yesterday and we issued a press release on our fourth quarter and year end 2012 results.

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. 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 risks and uncertainties relating 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, 2012.

The earnings release and the relevant non-GAAP reconciliations are available on the Investor Relations page of the Venoco website, which is www.venocoinc.com.

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

Edward O'donnell

Thanks, Kevin. Welcome to all of you who have called in and are listening to the webcast this morning as we discuss our fourth quarter and full year 2012 results.

To start off with, on December 31, we sold all of our producing assets in the Sacramento Basin, along with our acreage in the San Joaquin basin, excluding the Sevier prospect, for $250 million to an unrelated third-party.

On December 31, we received $149 million of the sale proceeds, followed by another $73 million on January 3, which related to leases that had preference rights attached. Remaining $29 million relates to leases that require that we obtain consents from the landowner prior to transferring ownership.

Per the terms of the agreement, we have until June 30 of this year to obtain the necessary consents. To date, we have received all but $8 million of the $250 million in sale proceeds, and we expect to receive the remainder before the June deadline.

Although we believe that we had very valuable assets in the Sacramento Basin, its fresh natural gas price environment relative to oil didn't allow us to allocate the capital necessary to develop the assets to their full potential.

Over the years, our Sacramento Basin team did an outstanding job of unlocking and building value in these assets and we very much appreciate all of their efforts.

The perspective onshore Monterey acreage in the San Joaquin basin that was included in the sale did not include the Sevier field, which is where we are focusing our efforts with respect to the onshore Monterey.

While we believe the acreage sold has potential, the exploration effort necessary to advance those areas would have required a significant amount of capital. Since we are currently focused on developing our legacy Southern California assets, which have significant upside potential, and doing so within operating cash flow, we knew we wouldn't be able to devote any significant resources to this acreage in the near term.

Additionally, we save about $5 million a year in leasehold cost by divesting ourselves of this acreage. The price we received for the combined assets was highly favorable, and we'll use the proceeds from the sale to substantially reduce the additional leverage that we took on in the going-private transaction.

The sale of our Sacramento Basin and onshore Monterey assets allowed us to eliminate a significant portion of the second lien term loan that we took on in the going-private transaction. The elimination of this secured debt freed up additional borrowing base capacity under our revolving credit agreement, which allowed us to enter into an amendment to the revolver, which among other things, expanded the bank group and increased the borrowing base of the facility from $175 million to $270 million.

After closing the amended facility, we used a portion of the additional capacity available to repay the remaining principal outstanding on the second lien term loan.

I'll let Tim Ficker go into further detail regarding the amended facility later in the call. But now I'd like to spend a few minutes discussing operations.

After completing the pipeline in January, we were able to get back to drilling in South Ellwood in 2012. We drilled and completed 3 pud wells during the year. The first well was drilled to the West of the platform and is currently producing about 100 gross 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, the 3242-12, was drilled in the opposite direction of the platform and bottoms at the easterly boundary of our lease. The well was placed on production late in the second quarter and has since produced with no decline and with no water production. During March of this year, the well averaged about 2,100 gross barrels of oil per day.

Our third well, the 3242-4, was completed in late 2012. The initial completion was wet. So we redrilled it as an offset to the 42-12 well. We completed the well in February of this year. And since cleaning up, the well has averaged about 1,500 BOE per day, 97% of which is oil.

Early in the fourth quarter, we spud a fourth well at South Ellwood, the 3242-19, to a probable location northeast of the platform. This location has the potential of prove up a new fault block, as well as to add PUD locations in that fault block. We set casing on the well and then suspended drilling so we could move back to the re-drill of the 3242-4 well I just discussed.

Shortly following completion of the 4 well in February of this year, we then returned to the 19 well to continue drilling. However, the intermediate casing strength parted after running it in the hole, causing a delay in our drilling program. We are currently assessing whether to continue on with the 19 well or to temporarily suspend drilling in order to begin drilling a new location created by the success of both the 12 and the 4 wells. In the event we decide to begin drilling a new location now, we would expect to return to the 19 well later in the year. We expect to make a decision in the next couple of weeks.

The drilling program that we began in 2012 has had a significant impact on our company. By way of illustration, the South Ellwood field produced about 2,100 net BOE per day in 2011, which is prior to any of our drilling activity.

As a result of our drilling program, we have been able to increase our production from the field by more than 140% to a rate of about 5,100 net BOE per day in March of this year.

South Ellwood, with its shallow decline rate and long-lived reserves, has always been a valuable asset to the company. But it became that much more valuable in 2012 once we were able to initiate a drilling program to tap the extensive potential in this field.

At our West Montalvo field, during 2012, we spud 4 wells and completed 6, 2 of which were spud in late 2011. All of the wells were drilled from onshore to offshore bottom-hole locations.

Since the second quarter of 2011, which is when we started our significant drilling efforts in the field, we have drilled and completed 9 wells, all of which have been productive. Results of the overall program have been in line with our forecasted performance and have provided robust economics.

The impact of our drilling program is illustrated by the increase in our production from the field, which in 2012, increased by 44% over 2011 production.

Our drilling program at our Sockeye Field that was completed in the first half of 2012. We drilled and completed 2 horizontal wells into the upper M2 portion of the Monterey and we drilled a dual completion well, producing from the M4 Monterey, while injecting into the Upper Topanga waterflood.

Our limited drilling in the field in 2012 enabled us to keep our year-over-year production flat. In the second half of the year, we focused on facility process improvements, which allowed us to handle the increased fluid volumes more efficiently. We also moved our company-owned drilling rig from Platform Grace to Platform Gail to replace a contractor-owned drilling rig on Gail, thereby reducing our drilling and workover cost going forward.

With respect to our onshore Monterey shale acreage, during 2012, we continued to focus our efforts on the Sevier field in the Western San Joaquin Valley. During the year, we spud 5 wells and completed 6, including 1 spud in 2011. We also installed artificial lift in wells and built centralized production facilities. We completed our produced water pipeline in October and have realized significant savings in water disposal costs as a result. This substantially completed oil and natural gas pipelines to their respective points of sale and we are currently negotiating sales agreements with purchasers.

Now I'd like to talk about capital expenditures and production and expenses for 2012. During the year, our capital expenditures totaled $219 million. Of that total, approximately $154 million was for drilling and rework activities, $25 million for facilities and $40 million for land, seismic and capitalized G&A.

Capital expenditures in our Southern California legacy fields accounted for $117 million or 53% of total 2012 capital spending. As previously mentioned, we completed 6 wells in our West Montalvo field during the year, including 2 that were spud in 2011.

At South Ellwood, we spud 4 wells and completed 3. And at Sockeye, we drilled 3 wells early in the year and performed 1 recompletion. 2012, we spent approximately $76 million, or 35% of our capital expenditures on the onshore Monterey shale play.

During the year, in our Sevier field, we spud 5 wells and completed 6, including 1 spud in 2011. We also completed a 3-D seismic shoot in the Salinas Valley. We limited our capital spending in the Sacramento Basin to $26 million or 12% of the total capital spend in 2012.

During the year, we spud and completed 4 wells and performed approximately 250 recompletions. This year, our capital budget is $91 million, which should allow us to stay well within our operating cash flow for the year. Approximately $78 million, or 86% of the budget, is allocated to our legacy Southern California projects, which includes plans to drill 5 wells in West Montalvo and complete 3 to 4 wells at South Ellwood, 2 of which were spud in 2012. We have limited capital expenditures planned for our other legacy Southern California fields in 2013. The remaining $13 million, or 14% of our budget, is allocated to onshore Monterey activities.

Our daily production volumes in the fourth quarter were 16,939 BOE per day, compared to 17,899 BOE per day in the third quarter. The decrease in production in the fourth quarter is primarily the result of 2 things: First, in November, we had our annual maintenance shutdown at our South Ellwood field, which lasted about 1 week. The shutdown had about a 400 to 450 BOE per day impact on production in the fourth quarter.

Second, we experienced some mechanical problems on several wells in our West Montalvo field, which resulted in lower production from that field in the quarter. These issues have been resolved and the field is currently operating at normal levels.

For the full year of 2012, we averaged 17,336 BOE per day, compared to 17,612 BOE per day in 2011. Pro forma for the sale of our Sacramento Basin assets, our production increased 17% in 2012 as compared to 2011.

Furthermore, liquids production in 2012 increased by 20% compared to 2011, from 6,688 barrels per day to 8,033 barrels per day. As expected, our production mix during 2012 changed substantially from the previous year's result of increased drilling in our oily legacy Southern California properties and reduced drilling in our Sacramento Basin gas properties.

Our fourth quarter 2012 production was 49% liquids, compared to 38% in the fourth quarter of 2011. The increase in oil production in 2012 contributed to a 9% increase in adjusted EBITDA compared to the prior year.

For 2013, we expect our production to average between 10,000 and 10,500 BOE per day, of which about 95% is expected to be liquids. Lease operating expenses increased 13% to $15.69 per BOE in the fourth quarter compared to $13.90 per BOE in the third quarter. The increase in our per barrel operating cost is primarily the result of a scheduled maintenance in our South Ellwood field, which resulted in both higher lease operating expenses and lower production levels during the fourth quarter.

For the year, our lease operating expense averaged $14.48 per BOE, which is actually a bit lower than our 2011 cost of $14.64 per BOE. So we're very pleased that we've been able to keep a tight handle on operating expenses during the year, allowing us to maintain flat operating cost on a year-to-year basis, even though our production mix shifted in favor of oil, which is more costly to produce.

I'll let Tim Ficker discuss G&A and property and production taxes a little later in the call. Pro forma for the sale of the Sacramento Basin assets, our lease operating expense was about $24.70 per BOE for the full year 2012. We expect our lease operating expense per BOE to average between $20.50 and $21.50 for 2013.

Turning now to reserves. We had a good year for reserves, as our year-end 2012 reserves were 52.2 million BOE compared to 2011 year-end reserves of 49.7 million BOE pro forma for the sales of the Sacramento Basin and Santa Clara Avenue property.

If you recall, we sold our small Santa Clara Avenue field in the second quarter of the year. Net of production, we added 5.6 million BOE, which allowed us to replace of 182% of 2012 pro forma production.

Our PV-10 at year-end 2012 was $1.5 billion. Our most significant addition in proved reserves came from our reversionary interest in the Hastings Field, which has responded very favorably to the CO2 flood, that Denbury Resources, the operator, has implemented. The field was returned to production in January of 2012. Since then, production from the field has greatly exceeded third-party engineering forecasts. As result of the positive response, we were able to add nearly 10 million barrels of oil to our proved reserves at year end.

At South Ellwood, we had a bit of a mixed bag with respect to year-end reserves. As we mentioned earlier, the 3242-12 well has been highly successful. And as result, we were able to increase our proved reserves for that well by about 3.3 million BOE when we converted the well from a PUD classification to PDP classification.

However, we lost a combined 7.9 million BOE as result of the other 2 wells. The first well we drilled that's currently producing about 100 BOE per day was below expectations, and the initial completion of the 42-4 well was wet. However, as I mentioned earlier, the 42-4 well was redrilled in early 2013 and produced at an average rate of about 1,500 gross BOE per day in the last 20 days of March. So we expect to record a significant amount of PDP reserves in 2013 related to this well.

Additionally, as a result of our drilling program at South Ellwood, we expect to be able to book additional proved locations in the field in 2013. Our Sockeye and West Montalvo fields remained relatively flat with respect to reserves from year-on-year.

A couple of comments on oil pricing. As we have discussed in previous calls, we entered into a sales contract tied to Napo, a water-born crude from Ecuador, for our South Ellwood field oil production in the first quarter of 2012. We also entered into a sales contract for our Sockeye Field, which is tied to California - Buena Vista postings, and it became effective April 1, 2012.

Production from our other fields is already being sold based on contracts tied to Buena Vista postings. Both Buena Vista and Napo have traded at a premium to West Texas Intermediate since we entered into the contracts early in 2012.

The company-wide weighted average premium, before hedging for the last 9 months of the year, was about $6.86 per barrel, above WTI. For the full year, our realized oil price was $97.28 a barrel, which is about $3 above average WTI.

And finally, we want to give some guidance for the year 2013. Our capital expenditures for the year are expected to be between $90 million and $100 million for the year, which we expect to result in production levels in the 10,000 to 10,500 BOE per day range. We expect our lease operating expense to be between $20.50 to $21.50 per BOE, G&A to be between $11 and $11.50 per BOE, property and production taxes to be between $1.80 and $2.27 per BOE, and DD&A to be between $12.50 and $3.50 per BOE.

Timothy A. Ficker

$13.50.

Edward O'donnell

I'm sorry, $12.50 and $13.50 per BOE. Thank you. With that, I'd like to introduce Tim Ficker, who will go over the financial highlights. Tim?

Timothy A. Ficker

Thanks, Ed. Let's take a few minutes to cover some financial highlights from the quarter and the year. Adjusted EBITDA for the quarter was $40 million -- $40.7 million, which is down about $14.3 million compared to the third quarter and down about $26.4 million compared to the 2011 quarter, which included realized gains on the settlement of gas hedges of about $12 million.

For the year, adjusted EBITDA was $239.3 million, which is up about $20.5 million from 2011, primarily as a result of higher oil revenues in 2012, which I'll discuss along with other components of EBITDA in more detail shortly.

Adjusted earnings for the quarter was a loss of $9.4 million, which is down about $30 million compared to the comparable 2011 quarter, and down about $21 million compared to the third quarter. Those decreases are largely due to increased G&A costs, as well as decreased revenues, both of which I'll discuss a little more -- more a little later.

For the year, adjusted earnings were $53.9 million, up about $10.6 million from 2011. Oil and gas revenues were $90.7 million for the quarter, compared to $95.4 million in the third quarter. The decrease results from lower oil production, which was down about 8% compared to the third quarter, primarily due to the annual maintenance shutdown at the South Ellwood field and well work at our West Montalvo field during the quarter. Additionally, realized oil prices were about 2% lower in the fourth quarter compared to the third quarter.

For the year, oil and gas revenues were $350.4 million compared to $323.4 million in 2011. This increase is primarily a result of a 20% increase in oil production as result of the successful drilling activity during the year, primarily at the South Ellwood and West Montalvo fields. We also realized a 7% increase in oil prices in 2012 compared to 2011. The increase in oil revenue was partially offset by a 15% decline in natural gas production, resulting from reduced activity in the Sacramento Basin, and a 28% decrease in realized gas prices.

Lease operating expenses for the quarter increased by $1.5 million from the third quarter, and this was due in large part to cost incurred during the quarter for the scheduled maintenance shutdown at

our South Ellwood field.

For the year, our LOE was $91.9 million, which is about $2.2 million lower than 2011. On a BOE basis, we reported LOE of $15.69 for the fourth quarter and $14.48 for the year. Given our oil-weighted production mix in 2013 resulting from the sale of our Sacramento Basin assets and our oil focus CapEx programs, our 2013 guidance for LOE is $20.50 to $21.50 per BOE.

Transportation expenses were fairly minimal in the past 2 quarters, which is the result of the elimination of barging operations, which we discontinued in the first quarter of 2012 in connection with the completion of our South Ellwood pipeline. Our transportation expenses for the year were $5.2 million, the majority of which was incurred in the first quarter while the barge was still in operation.

Production and property taxes were $1.1 million in the fourth quarter compared to $1.7 million in the third quarter. For the year, production and property taxes were $9.7 million compared to $6.4 million in 2011. That increase is primarily due to supplemental taxes accrued during the second quarter of 2012 related to the successful drilling at our South Ellwood and West Montalvo fields.

G&A expense increased from $11.8 million in the third quarter to $21.1 million in the fourth quarter. Excluding noncash stock-based comp, going-private-related costs and severance costs related to the sale of our Sacramento Basin assets, G&A increased to $13.2 million in the fourth quarter from $9.2 million in the previous quarter. For the year, G&A expense was $55.2 million compared to $39.2 million in 2011. And excluding the cost I just mentioned, our G&A was $38.9 million for the year compared to $31.9 million in 2011. The most significant driver contributing to the increase for both the quarter and the year was the accounting for the conversion of Venoco's restricted stock and stock option awards into cash settlement awards as a result of the going-private transaction.

On a BOE basis, G&A expense, excluding noncash stock-based comp, going-private-related costs and severance costs related to the sale of our Sacramento Basin assets, was $8.47 for the current quarter compared to $5.59 in the third quarter. For the year, G&A per BOE was $6.13 compared to $4.96 in 2011. Our G&A guidance for 2013 is $11 to $11.50 per BOE.

Looking at the balance sheet. Compared to the year end 2011, the biggest changes were in PP&E and debt. PP&E decreased as a result of the sale of our Sacramento Basin assets and Monterey acreage as the proceeds we recorded against the full cost pool. That decrease was somewhat offset by our capital expenditures during the year.

Our debt increased primarily as a result of the debt we took on in the go-private transaction, partially offset by the use of proceeds from the asset sales at year end. Initially, we used a portion of the sale proceeds to repay the balance outstanding on our revolver at year end, but we subsequently reborrowed funds under the revolver, and along with the remaining sale proceeds, reduced principal outstanding on the second lien term loan by about $200 million. That was in January of 2013.

Earlier in the call, Ed mentioned that we entered into an amendment to our revolving credit facility in March of 2013. And as a result of that amendment, we increased the borrowing base from $175 million to $270 million, with commitments of $268 million. We used proceeds from the increased facility to pay off the remaining principal balance of the higher interest rate second lien term loan. In addition to increasing the borrowing base, the amendment also relaxed the limits on our debt-to-EBITDA ratio to 5.5 -- 5.75 in the first quarter of 2013, stepping down to 4.0 by the third quarter of 2014. One of the significant reasons for the change in the covenants was the delays that we experienced in getting the 3242-4 well online and therefore the related delay in production and cash flows. The amendment also added a secured debt-to-EBITDA covenant and cleaned up some definitions in the agreement.

One other thing I'll mention before I finish is related to hedging. Subsequent to year end, we entered into some additional oil positions and those are laid out in the 10-K that we just filed. In addition, in the last few days we also unwound the $5.10 and $5.80 WTI to Brent swaps, as well as 400 BOE a day of the $6.05 WTI-Brent swaps, all of which we had outstanding at year end. But those transactions are not yet reflected in the 10-K.

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

Edward O'donnell

Thanks, Tim. Now, let's open it up for questions about our fourth quarter and year-end 2012 results.

Question-and-Answer Session

Operator

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

Sean Sneeden

Could you just discuss the inventory that you guys think you have on -- in your legacy assets, perhaps if you look at it on R/P or just a number of locations that you might have?

Edward O'donnell

Yes, Sean. I think we have about 3 dozen locations identified right now in our Southern California legacy assets. At Montalvo, we've -- as we indicated, we're going to drill 5 wells this year. We've probably got something like 15 locations there in round numbers, mostly offshore. We've still got a few onshore, as well. At South Ellwood, we've -- we don't have as many, but we've got obviously very high-impact locations there with 2 wells we just talked about near our Eastern leased line, they're producing a combined 3,600 barrels a day between the two. And we've got additional locations on that leased line as well. And then the 19 well that we've talked about going to a probable location northeast of the Platform, if successful, we'll prove up a number of locations there. So that's yet to be determined, but we expect to complete that well this year and we'll find out. Get a good idea, at least, of the size of that fault block if it is productive out there. And we've got some infill locations at South Ellwood as well that we're working on. At Sockeye, we have additional locations in both the upper M2 Monterey and the M4 Monterey, as well as a couple of locations in the Topanga waterflood. We're not allocating any capital there this year just -- because we just don't have sufficient capital to allocate. We can't cover everything this year. So we've still got a number of locations and a pretty good inventory for a foreseeable future here. But next year, we'll probably have a program at Sockeye and drill some wells there in addition to probably more wells at Montalvo and probably more wells at Ellwood as well.

Sean Sneeden

Okay, that's helpful. And then, I guess, how should I think about any sort of downspacing opportunity? Do you guys have that kind of optionality at all?

Edward O'donnell

Downspacing, well, I think it's the Montalvo is probably where we have the most opportunity for downspacing there as we drill up the offshore portion of that field and -- but that's just going to depend on performance going forward. But I'd say about 3 dozen locations what we've got out there right now. And there's downspacing opportunity at Sockeye as well, I guess, but not a lot, Sean.

Sean Sneeden

Okay. And then you guys did a pretty good job of taking out some of the second lien bonds or second lien term loan with the Sac Basin sale. Can you just talk about how you -- or what your strategy might be in terms of realizing what you think are the true value or some of your legacy assets in Southern California? I know in the past you've kind of thrown out the possibility of an MLP. And we've seen probably kind of an MLP in energy entering the San Joaquin Basin through the Berry acquisition. Could you just kind of discuss what do you think or what you're looking at right now?

Edward O'donnell

Well, of course, we are focused on deleveraging. And that's a very high priority to us, Sean. There's no question about that. And we're -- I think we're happy with where we're at right now in terms of what we've accomplished since the take-private transaction is completed and where we're at this year in getting rid of -- the sale of Sac Basin and getting rid of the second lien term loan. So we're certainly happy with the progress we've made, although it remains a high priority to us and we've still got a ways to go. A couple of things. One, of course, is we are investing less capital next year and staying within cash flow. That's certainly an important point for us. And we're drilling the higher-impact, low-risk wells that we have in our inventory, and that's certainly highlighted by our progress at Ellwood so far. So we're adding to EBITDA, if you will, on that part of the equation by really doing a good job, I think, in selectively allocating our capital next year and staying disciplined in operating within our cash flow. In terms of other deleveraging activities that we might embark on, we have, as you know, we have talked about a master limited partnership and asset sales and joint ventures as other options available to us. And we are looking at some joint ventures, for example, in our onshore Monterey acreage and we have some parties interested in joint venturing with us there. And we are not going to be able to allocate a lot of capital to those properties in the near term. And so we would like to get a joint venture partner in there to carry us, to help advance the Sevier field, in particular. So that's part of our strategy there. And other than that, we've talked about the sale of our midstream assets as a possibility. That's still an option to us available out there and MLP is still an option. And beyond that, I really can't talk about much -- in much more detail, but we'll certainly keep you apprised of as we get down -- further down the path on any of these options, Sean. But that again is a real focus for us, particularly in 2013.

Sean Sneeden

Sure. I guess just kind of 2 follow-up from that. On the sale of the midstream assets, do you have the ability or any additional capacity that third parties could run or would a sale -- what I'm wondering is would the sale of your midstream assets be classified under accounting treatment as a sale-leaseback for a transaction? Have you guys looked to that at all?

Edward O'donnell

Go ahead, Tim.

Timothy A. Ficker

Yes, Sean. That's one of the considerations and our thoughts on monetizing those assets is the accounting treatment for it. We actually do have some third-party production that's run on a portion of the system that we have. But for example, the South Ellwood line is really just our oil and the royalty oil that goes through that pipeline. So that is one of our considerations. Certainly, from a monetization perspective, we think that it's a desirable asset to -- particularly some of the midstream MLPs, but we would need to include in our calculus the accounting treatment and how that's reflected in our debt metrics.

Sean Sneeden

Okay, that's helpful. And then just on the MLP. Can you talk about any tax consequences that might come up from converting to an MLP or how that would work?

Timothy A. Ficker

I don't want to get into too much detail, Sean. But I will say that if you look at our 10-K, you can see that we've got a pretty healthy NOL and we got some substantial tax basis that we think would provide a fair amount of coverage.

Operator

Your next question is from the line of Ravi Kamath with Global Hunter.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

I had a few questions. First, Q1 '13 average production, could you share that?

Timothy A. Ficker

We can't share that yet, Ravi. We've got, I guess, 8-K requirements if we did. Certainly, I'll say that Ed mentioned that we were producing 5,100 net BOE a day at South Ellwood and I think that gives you a good indication of where we're headed. So we feel like we're in pretty good shape for the quarter. But again, we don't want to get too far out over our skis. Having said that, it's April 15 and we'll be filing our quarter in just a few weeks. So you won't have to wait long.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Got it. And in terms of modeling for price -- oil price realizations relative to NYMEX for 2013, any kind of guidance there?

Timothy A. Ficker

Boy, that's been hard just because we've seen Brent squeeze. Just to reiterate, we think that the California postings on which our oil is sold and based is more -- fluctuates more with Brent than with WTI. And so we still give a differential to WTI because we think that's where a lot of folks are still focused. But we think that it fluctuates more closely with Brent. Now that being said, when you talk about a differential to WTI where we've seen that basis between WTI and Brent squeeze and widen and so it's kind of hard to say. But I think if you look more to the Brent strip, that it'd probably give you a better guidance on how to model out our production and sales.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Okay. And is that -- I think you mentioned $6.86 per barrel premium over the last 9 months. Where is that like currently?

Timothy A. Ficker

Again, it's kind of squeeze and grow and we'll get into that in our first quarter call. We just don't want to give out too much information right now. We haven't finalized our accounting for the first quarter. So again, we can't -- we just can't give out too much information on that.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

With regards to the Hastings Field, what's your current estimate as to when you guys would start generating cash flow from that or assuming cash flow from your -- the rest of your interests?

Edward O'donnell

It's still a few years away, I think, Ravi. And as you may know and we've disclosed in the 10-K, we have a dispute with Denbury in terms of the cost of CO2 and the cost of transporting that CO2 to the field. And so we're in arbitration now or we've initiated the arbitration process, I should say, to resolve those issues with Denbury. And that should be resolved this year some time, but we don't really want to comment too much on anything that's involved in litigation or arbitration at this point. But suffice it to say that the field continues to produce and perform very well, certainly exceeding the expectations of Denbury and our third-party reserve auditors. So all is going well from an operational and production standpoint in the field.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Okay. A couple of housekeeping questions on the $91 million CapEx budget. Does that include capitalized G&A or should we add something on top of that?

Edward O'donnell

No, that includes cap G&A, Ravi, yes.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Includes cap G&A, okay. Okay. And where was your restricted payments basket at the year end?

Timothy A. Ficker

It's a different calculation, Ravi. It's about $20 million.

Operator

[Operator Instructions] Your next question is from the line of Dave Zimmerman with Eaton Vance.

David Zimmerman

Can you just tell us what your net PP&E in the midstream or the infrastructure assets is?

Timothy A. Ficker

Our net PP&E, as in the cost basis that we have?

David Zimmerman

Yes, on the balance sheet. What have you got?

Timothy A. Ficker

Dave, I don't know that we have that number. We've incurred -- I don't know. Doug Griggs is sitting here. I don't know if you recall exactly off the top of your head what we incurred for the South Ellwood pipeline, but it was...

Douglas J. Griggs

I think it was about $30 million.

Timothy A. Ficker

Yes, $30 million all-in costs and that would include the costs that we were able to capitalize related to interest and so forth, at least for tariff purposes. But we don't really necessarily follow that separately. We have -- when we acquired the midstream assets, we acquired them primarily aside from the South Ellwood pipeline in conjunction with other acquisitions and so it was a purchase price allocation that was done 15 years ago or so. So we just -- it's actually all included in our full cost pool. So if we sold those assets, they would be reflected as a credit to the full cost pool.

David Zimmerman

Yes, sure. But do you even have a round number in terms of what the asset value as opposed to the oil and gas reserve and acreage asset value would be for those assets on your books?

Timothy A. Ficker

We don't have any reserve value for the midstream assets.

David Zimmerman

I said as opposed to the oil and gas reserve values. So okay, if you don't want to answer, that's fine. The other question is on Hastings. Is there any material expenditures, which reduced the present value as presented by your outside engineer or a major increase in volume, which would impact that present value in the next little -- in the next year or so?

Edward O'donnell

Well, we don't have any expenditures related to that at all, of course. We have a reversionary interest there. And when Denbury recoups certain identified expenditures and we back into our interest -- we back into a working interest at that time, but only at that time then will we begin paying a portion of the expenditures in that field and of course receiving a portion of cash flow accordingly. But in the meantime, we have no expenditures associated with it. And in terms of what Denbury is doing, they have capital expenditures ongoing for a period of another 7, 8, 10 years or something as this flood expands. So their expenditures spread out over a long period of time here as this CO2 flood expands from one fault block to another and throughout the field from West Hastings and even in the East Hastings. So this is a multi-year capital expenditure project associated with them. But that's pretty well all laid out in that plan. But we don't have any responsibility for that until we back into our interest.

David Zimmerman

Okay. But it's a couple of years out before you get any meaningful cash flows from that, so that's all encompassed in the present value calculation, right?

Edward O'donnell

Yes, that's correct. Yes.

David Zimmerman

Okay. The only other question is do you have your -- the fourth quarter oil realizations or the spread versus WTI, do you have that ready at hand or not really? You have the 9-month number, that $6.86 for 9 months.

Timothy A. Ficker

Dave, I don't have it at my fingertips, but we can certainly get it to you.

David Zimmerman

But presumably -- yes, okay. I guess not presumably. There's just one other question, it's what, of course, that realization will look like relative going forward. But...

Timothy A. Ficker

Let me tell you. For the fourth quarter, our realization was $94.50 approximately. Yes, weighted average for the quarter.

Operator

Your next question is from the line of Robert [ph] Murray [ph] with Credit Capital Investments.

Unknown Analyst

Could you just give us a pro forma bank debt balance? You mentioned there was a payment in January and then another -- some more cash would come in recently. So I just wondered if you could just give us a pro forma bank debt balance?

Timothy A. Ficker

Yes, we disclosed in our 10-K what our bank debt balance is.

Unknown Analyst

Okay, sorry. One other question, can you give us any color on the reserves or the PV-10 value associated with the assets that were sold?

Edward O'donnell

No, we didn't actually have year-end reserve numbers for Sac Basin or PV-10 associated with it, Robert, because since we sold it out in effect at year end, we didn't have our third-party auditor make the effort to determine what the year-end reserves would have looked like or the value, so we don't have that number from them available.

Operator

I would now like to turn the call over to Ed O'donnell for closing remarks.

Edward O'donnell

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

Operator

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

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