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Endeavour International (NYSE:END)

Q1 2013 Earnings Call

May 09, 2013 10:00 am ET

Executives

K. Darcey Matthews - Director of Investor Relations and Corporate Communications

William L. Transier - Executive Chairman, Chief Executive Officer and President

Carl D. Grenz - Executive Vice President of International

Catherine L. Stubbs - Chief Financial Officer and Senior Vice President

James J. Emme - Executive Vice President of North America

Analysts

Stephen F. Berman - Canaccord Genuity, Research Division

Chad L. Mabry - KLR Group Holdings, LLC, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Amy Stepnowski

Steven Karpel - Crédit Suisse AG, Research Division

David Epstein - CRT Capital Group LLC, Research Division

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

Randy Laufman - Odeon Capital Group LLC, Research Division

Stephen Puckowitz

Operator

Good day everyone, and welcome to this Endeavour International Corporation's First Quarter Earnings Conference Call and Webcast. Today's conference is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Ms. Darcey Matthews, Director of Investor Relations. Please go ahead, ma'am.

K. Darcey Matthews

Thank you, Lisa. Good morning, good afternoon, everyone, and thank you for joining us today for Endeavour's 2013 First Quarter Earnings Conference Call. On the phone today, we have Bill Transier, our Chief Executive Officer; Cathy Stubbs, our Chief Financial Officer; Carl Grenz, Executive Vice President for international operations; and Jim Emme, Executive Vice President for North American operations.

Before we begin, I'd like to let everyone know that there is a slide deck supporting this call available on our web page at endeavourcorp.com. Also, let me remind everyone that our comments today reflect our current information and understanding. There are a number of factors, however, that can cause actual results to differ materially from what we present here today.

For the risk factors associated with our business, please read our full disclosures in our latest 10-K and 10-Q. Our quarterly 10-Q is expected to be filed tomorrow. And with that, let me turn the call over to Bill for some opening comments.

William L. Transier

Thank you, Darcey. Good morning, everybody. Appreciate you being here with us today.

The last time we got together to talk was in March when we were talking about year-end numbers. Just to bring you up-to-date since we spoke last, as you know, at the time of that call, we had just moved the Transocean Prospect from East Rochelle over to West Rochelle. That has continued to work full speed since we spoke last. We have now completed the drilling of the well and are in the completion stage for our first production well in the Rochelle field.

We've also moved the Rowan Gorilla VII heavy-duty jack-up back to Bacchus and started work on our third production well there. As you know, Bacchus continues to outperform our expectations to date. So we're anxious to get this last well on production and see what we get going forward from that point.

We've also worked really hard as a team and with the operator on issues related to processing matters at Alba that caused our production to actually be below what our expectations were even though, it's our largest producing field in the portfolio right now. I believe, and you'll hear more about it from Carl, that we have come a long ways in resolving the immediate process problems encountered at Alba. I also believe that the work done will yield much better production going forward in the second half of the year and will likely enhance the long-term recoveries from the field as we move throughout its life.

From a financing point of view, we also extended the remaining $15 million of our revolver into next year. So we now have no short-term debt repayments until the middle of 2014. And as you've probably seen in the last week or 2, we've completed the funding of the monetary production payment that we talked about that provides liquidity for us to get through first production at Rochelle and continue with the strategic review process.

In North America, our gas production for the quarter was stable at about 9 million a day, and our key acreage there is held by production. We will continue to expend minimal capital in the U.S. while we watch gas prices. Although as you've seen them, they appear to be firming up in a positive direction for us. We do plan to drill an initial pilot well test in our liquid-rich Niobrara play in Northwest Colorado this summer, where we now have an improved federal unit and drilling permit in hand.

Many of you are interested in the strategic review process. Just a general color on the process itself, and I made these comments the last time we got together, but there is a lot of interest in the U.K. North Sea. It's showing impressive signs of renewal and activity, and interested investors who know the value of the petroleum basin are coming in from all parts of the world. The U.K. government, as you know, has been in the process of making some changes to the tax and regulatory legislation to stimulate investment in the North Sea. All indications are that, that investment criteria in the North Sea will have a dramatic improvement this year. Some of those initiatives will improve how decommissioning is handled and provide allowances for smaller fields and fields that are candidates for redevelopment, all of which are good for our portfolio.

We announced back in February that the board would consider a full range of alternatives, including a sale, joint venture or partnership in respect to the company's activity in the North Sea, a sale of specific assets, a sale or merger of the company in total or continue to execute on the company's operational plans as we now have them. The objective of the process is to accelerate the de-leveraging of our balance sheet and to unlock what we believe is the underlying value of the company's assets.

I can't really give you any more guidance today in terms of the timing. I can tell you this that the process is robust. There is a lot of interest in this. And for obvious reasons, we can't really say any more than that, but we expect to move through these alternatives thoughtfully and expeditiously to try to get this thing to some sort of conclusion as soon as we can.

Our quarter, this quarter was focused on the execution and keeping developments on schedule. Carl will give you some very -- some more specific updates on our U.K. operations. But I will say this, we are positive in achieving the long-stated goal that you've heard us talking about of having a portfolio of assets that can have a run rate of more than 20,000 Boes per day. I'm confident that we will be at that level in the second half of this year with what we've got going on. Obviously, the key drivers for 2013 remaining are getting first production at Rochelle, getting the third development well on at Bacchus and improve production levels from our Alba field.

Finally, before I turn it over to others, with respect to our capital position, we spoke at length about this on our last call, but you've seen some more activity here in the last kind of month or so, a series of transactions that have really added almost 400 million of near-term liquidity to our company and in my view, cushion our ability to finish the development work at Rochelle and Bacchus and complete a thoughtful and disciplined strategic review process as we move throughout the rest of the year.

So with that, as kind of a lead in, I'll turn it over to Carl to talk about our U.K. operational update and that will be followed by Cathy walking you through the numbers for the quarter. Carl?

Carl D. Grenz

Okay. Thank you, Bill, and good day to everyone on the call. Well, today, I'll start off by giving you an update on Rochelle. Just as a reminder, the whole of the subsea pipeline and manifold infrastructure has been completely installed, except to the final tie-in spools connecting each of the 2 wells to the subsea manifolds. Now these 2 spools will be installed and connected on the completion of each of the wells. Now since the last earnings call, these top-size modifications to the Scott Platform have been completed, so all that is left to do on Scott is the final commissioning there on the introduction of hydrocarbons.

Well, going forward on Rochelle, we have 3 key objectives. The first one is obviously the startup of the development by bringing the west well online. The second objective is to have 2 producing nodes available as soon as possible, and so ensuring we have the redundancy wells ahead of the winter nominations and pricing. And the third clear objective is to complete the work on the original east well that we call E1y. Now I'll talk in some detail on each of these 3 objectives.

So you'll remember from the last call that we moved the rig, as Bill has just said, to start drilling the West Rochelle well in February and that this well is now at a very advance stage. We've successfully drilled the horizontal section through the reservoir to total depth, and we're now in the process of installing the production completion assembly and the tree. We expect production from this well and hence the start of the Rochelle development will occur around the middle of this year. As expected, this west well on its own will be able to fill the available capacity on the Scott Platform ahead of the east well coming on stream later in the year.

Now the Rochelle partners have agreed that on the completion of the west well and after a short exploration well by others, the Transocean Prospect rig will transfer across to the East Rochelle area and drill a new East Rochelle well that we will call E2 and that will start drilling later this summer. This well will target the reservoir in the original fallback location for the eastern area, which is towards the 11 appraisal well that we drilled and P&A-ed in 2009. We expect to bring E2 on production early in the fourth quarter, and this will satisfy our second objective of ensuring we have the redundancy in the wells for the original development plan and sufficient gas available to ensure we can take full advantage of winter nominations and pricing.

Now regarding the original east well, E1y, I can report that the work we've been counting out to study any possible mechanical issues resulting from the storm in January, this work is well advanced. These are highly complex studies and that require some time to complete. But despite the fact that the work is not yet fully complete, we can say that we do still intend to extract as much value as possible from this well, and that we now believe there is a reasonable likelihood of us being able to reenter this well to continue operations.

Now if we are able to reenter this well to complete as a producer, it will be used as a second drainage point in the eastern reservoir, thereby maximizing upside recovery reserves in the east and hence, maximizing value. If the study work concludes that completing the well as a producer is not possible, then we certainly expect to be able to reenter E1 and do a conventional plug and abandon of this well. It's likely though that any reentry on E1 will occur next year, not this year.

So that's Rochelle. I'll turn now to talk to the Bacchus development. And again, I can report that we're seeing production performance from the first 2 wells well above our initial expectations. Production from Bacchus is still averaging above 10,000 barrels a day gross, with exceptional uptime efficiency. The rig Rowan Gorilla VII arrived back in the field in March, and it's well advanced in drilling this third production well, B1, into the western panel of the reservoir, and we expect production from this well to commence in the third quarter.

You recall that the initial development plan was to turn the first well drilled into a water injector after about a year of production. One can report that water injection is not in our plans at this time, and that's due to the continued high levels of production we're seeing from both of the 2 wells on production at this time.

The first well drilled into the eastern and central panels, which we call B3 is seeing a very flat production profile, with little change to bottom hole pressure. And the second well drilled into the central and western panels, B2, that's still choked back and at just 20% open and that's due to the flowing well and temperature constraints. So with the third well on line B1, we expect to see Bacchus delivering gross production in line with the higher end of the range of expectations, which is around 16,000 to 18,000 barrels of oil per day. So Bacchus is going very well.

Moving now on to Alba and some comments there. Production levels, as Bill has said, has been lower than expected so far this year, and that's due to the continuing issues with oil separation and the performance of the produced water-handling systems. These production constraint issues are related to tight emulsions that have formed in the oil separators, causing higher levels of base sediment and water, BS&W, in the oil exports. And together with particulate matter, mainly sand, being carried forward into the water-handling systems, and this in turn acts as a nucleation site for emulsions to form.

Now the operator, along with ourselves, has carried out a lot of work to improve the efficiency of these systems, essentially optimizing chemical injection to improve the water chemistry and to aid separation and to reduce the emulsions. And secondly, using online de-sanders to remove these solids from the system. Indeed, we're already seeing significant improvements with the oil export, BS&W at desired levels, and gross production volumes are starting to improve as a result of this work. And we expect production to be restored back to the maximum potential of this facility during the second half of the year.

The 2013 drilling program on Alba, consisting of 3 new production wells and 3 workovers, is also well underway. We're currently drilling a new low-cost platform base production well, and production will start from this well in the next few weeks. The drilling rig Glomar Arctic III has also recently arrived in the field to drill a subsea completed production well, but it is expected on production midyear.

The third new production well will be a further low-cost platform well that will be drilled and on production by the end of this year. So with the drilling program and the work carried out in the process plant, we can expect to see gross production from Alba to be in the range of 25,000 to 30,000 barrels a day during the fourth quarter of this year.

And finally, just a few words on exploration and regarding our drilling of the Centurion South well. While drilling activity has been completed ahead of schedule with the well P&A and the rig is now off-hire, we did encounter hydrocarbon-bearing reservoir as expected, although it was a thinner section than we anticipated. So we're now considering the commerciality of the field in conjunction with the Centurion discovery to the north.

So that's the update on the U.K. and with that, I'll hand over to Cathy Stubbs.

Catherine L. Stubbs

Thank you, Carl, and hello, everyone. During this section, first, I'd like to take you through the numbers of the quarter; next, give you an update on the capital expenditures for 2013; and then last, I'll comment on liquidity, giving you highlights of our financial transactions that we've achieved since the beginning of this year.

Turning to the quarter, on Slide 3, we show volumes. And just as a reminder to you, we record all revenues on the sales method. So sales volumes shown here are based on the occurrence of tanker lifting. Our physical production represents our entitled share of the production for the period. This will differ from sales volumes based on timing of the lifting. The assets and impact that's different the most is Alba, which is the one that's lifted. Bacchus, our other significant oil-producing asset, flows directly into the 40s pipes, so it doesn't cause such a difference.

Sales volumes for the quarter were roughly 7,200 barrels of oil equivalent per day, up 3,000 per day over the first quarter of 2012 or 72%. This is primarily due to our additional interest purchased in Alba back in May of 2012 and also to the start-up of our Bacchus well, the first in which was April and the second in July of 2012.

Physical production exceeded sales volumes for the first quarter as, again, sales volumes for the quarter only included 1 lifting in Alba. Physical production for the first quarter was down slightly from the fourth quarter. This was really due to reduction in Alba as a result of a 5-day unplanned shutdown that was spurred by mechanical issues. The wells were returned to full production over a 10-day ramp-up period following the shutdown, which resulted in lower production volume for the period. We're currently producing at roughly 10,000 barrels of oil equivalent per day.

Recognize that sales have shifted dramatically to oil from the prior year as our composition of production is primarily made up of oil from our Alba acquisition. We see this shifting to a more balanced oil-gas mix as Rochelle, our U.K. gas asset, comes online.

Commodity prices in the U.K. continued strong during the quarter. We also saw strengthening in U.S. gas price. Brent was at $113 for the quarter, up over $110 from the fourth quarter. We did see some softening in Brent in April, which hit the $100 range but currently, we're back up to $105 a barrel. NBP gas price remains strong, primarily due to cold weather in Europe. The average for the first quarter was up $1 over last -- to $11.50 per Mcf. And NBP is important as this is the index that our Rochelle sales will be based upon.

Henry Hub prices in the U.S. increased about $0.10 from the fourth quarter up to $3.50. We continue to see strengthening since the end of the quarter. We're about in the $4 range now.

We remain encouraged by our strong pricing environment. During the quarter, we locked in on some of this pricing by layering in some collars. For the second half of 2013, we locked in 3,000 barrels a day for oil and a floor of $95 and a ceiling of $105 through our marketing contract.

On Slide 10, kind of layout our hedging position, but these new collars add to our existing collars and forward sale hedge, bringing us to roughly 33% of oil production based upon our current oil levels that are hedged. We'll continue to look to lock in pricing as we bring on volume and again, our goal for hedging is 50% of our estimated production. Given this mix of sales volume and prices, revenues were up $43 million first quarter this year over first quarter last year and again, oil makes up 95% of the revenue for the quarter based on our heavy oil mix.

Turning to operating expenses. The first quarter expense was down from last quarter. It was up over last year's quarter primarily due to our increased production at Alba and Bacchus.

Slide 5 shows the metrics on a BOE basis. You can see that OpEx per BOE is impacted this quarter due to the maintenance at the Alba field to resolve our processing issues that have been mentioned to you before. We also had a well work-over in the United States. We're also up prior year due primarily to higher cost per barrel associated with Alba and this still being a larger part of our 2013 mix over 2012.

DD&A expenses increased from last year, primarily due to increased volumes on Alba and Bacchus again, and also due to higher decommissioning cost estimates that we told you about at the end of the fourth quarter as these run through DD&A as accretion expense. Just as a measure, there was a $6 million in accretion expense running through during our first quarter of 2013, reminding you that this is all a noncash expense. So these higher costs bring our DD&A rate per BOE up to $36 a barrel, which is somewhat offset over the increase in volume year-over-year.

We did have a small charge of $4 million to impairment expense in the quarter. This was due to our U.S. full cost pool. While we see strengthening in the U.S. gas prices, the ceiling calculation requires us to use a 12-month average gas price for the impairment test. So additions to the full cost pool, which were small, were only partially offset by our increase in the 12-month average gas price resulting in this charge. Just as a note, we were at $2.75 for our year-end test and $2.97 at the first quarter.

G&A remains relatively constant. It's down on a per BOE basis from quarter-to-quarter as production volumes were higher. Our interest expense remains flat from the fourth quarter at roughly $21 million. Interest expense is higher this quarter over last year, primarily due to our high-yield offering and revolving credit facility. This was partially offset by repayment of our senior term loan and notes payable last year.

In addition, capitalized interest was greater in 2013 due to our work in progress associated with Rochelle and Bacchus. We also have noncash interest running through interest expense for debt amortization and noncash interest on our 11.5% bonds that was $5 million for the quarter. Letter of Credit fees, again, as a reminder, this is for interest on our decommissioning LC, the largest one on Alba for $120 million that was put in place at the acquisition of Alba last May.

The U.K. government continues to work on initiatives to address decommissioning. It followed through with its plans, and in March of this year, put out its U.K. tax budget that included legislation as anticipated that allows smaller companies like Endeavour to post decommissioning security on an after-tax basis. This legislation is still subject to approval later this year. This is significant to Endeavour and a positive event that will reduce our decommissioning security that we have in place. Again, my goal is to replace these reimbursement agreement with associated traditional revolver that we've talked to you about that will have a much lower cost of capital to handle this LC.

Interest income and other for the quarter includes a noncash gain related to foreign exchange of $11 million. This is due to the dollar to pound exchange rate drop from about 1.6 to 1.5, and the gain is related as we revalue our long-term obligations that are denominated in pound, primarily retirement obligations.

So turning to Slide 6. Our adjusted EBITDA for the quarter is $45 million, significantly up over the $2 million last year. Again, this is driven primarily by our production and revenue increases.

On Slide 7, while EBITDA significantly increased year-over-year, these increases were offset by our higher LC fees and the higher noncash DD&A expense. So adjusted net loss is up only slightly over last year, a loss of $12 million versus a loss of $16 million.

Turning to capital expenditures on Slide 8. For the quarter, we spent $34 million in direct oil and gas expenditures, the bulk of which was on our development expenditures in the U.K. As a reminder, our preliminary budget for the year we told you was $140 million to $150 million in the U.K. About $90 million to $100 million of that was drilling for Rochelle and Bacchus; $35 million was what we call maintenance, which is primarily our infill drilling in Alba; and $15 million for exploratory and seismic, which is primarily the $10 million to $12 million we talked to you about on the Centurion South. We are on track with this spending. The U.S. expenditures are more likely going to be in the $10 million to $30 million range for the year and again, as we've told you before, are weighted towards the second half of the year and are largely discretionary.

Turning to liquidity and financing. Again, our first quarter focus was on providing liquidity. Our next steps are lower your cost of capital and then de-levering. We've worked really hard to achieve this increased liquidity. We walked you through a number of transactions that we put in place on our year-end earnings call. We've executed, as Bill mentioned, 2 more transactions subsequent to that call. These transactions give us sufficient financial flexibility, allows us to complete our projects in the U.K., as well as conduct a rational strategic process -- review process.

Just as a reminder, I'll walk you through these transactions. January, we entered into a new reimbursement agreement arrangement to push out our existing expiring reimbursement agreement for the $33 million LC on the IVRR-Renee/Rubie fields in the U.K. This is now pushed out to July of 2014. This facility has a slightly lower cost of 9% versus the 11.5% that was in place.

February, we entered into a forward sale for $23 million advance payment and again, this is repaid out of barrels of crude oil in the North Sea over a 6-month period beginning in March. This also provided a hedge as we locked in the commodity prices. The details of this are confidential, but you can do the math and calculate a nice price that we achieved over $100 mark.

In March, we worked to push out our existing debts that are coming due under the revolver of $115 million that was due in October. We had pushed out $100 million of that at the time of our call at year end. We've subsequently pushed out the $15 million balance. None of that is due until June 30 of 2014. We also pushed back $120 million of our reimbursement agreement that was coming due at the end of 2013 in December 31. That also is not due until mid-2014.

In March 5, we entered into a production payment for a group -- with a group of investors for $108 million. At execution, we received a $43 million deposit on that. We've subsequently received regulatory approvals necessary and completed that transaction on April 30, receiving the balance of $65 million subsequent to the quarter end.

So Slide 11, shows you pro forma of these adjustments, what our maturity schedules look like, and you can see we have no debt obligations that mature this year. As Bill mentioned, these transactions bring us about $400 million in liquidity. We ended the quarter with $81 million in cash. Subsequent to the quarter end, we received the $65 million on the closing of the monetary production payment, bringing us to pro forma cash of about $146 million. From our perspective, these transactions were designed to and do remove immediate liquidity concerns.

We'll continue and we do continue to monitor our expenditures as we spend capital on development projects. We defer capital where appropriate and where we can. We believe this liquidity positions us to execute on and carry out our capital plan, which as you've heard repetitively is turning on Rochelle and completing our third well at Bacchus.

We do still maintain our other 2 goals to focus on lowering our cost of capital and de-levering. We plan to put in a lower cost borrowing base likely to be put in after Rochelle comes online. The de-levering will occur after cash flows are realized from Rochelle and from the Bacchus third well, combined with a mix of our potential outcome on the strategic review. We'll begin to pay down debt then. We're committed, again, to achieve these goals for you this year.

As Darcey mentioned, we plan to file our 10-Q tomorrow, so you'll have details on our discussion today, as well as more details on the numbers for you. Now I'll turn it over to Bill for concluding remarks.

William L. Transier

Thanks to Carl and Cathy. Just before we turn it over to Q&A, let me remind you of a couple of things.

The underlying value of the Endeavour stock is really centered in our core assets in the U.K., that being Alba, Bacchus and Rochelle. We've talked about all 3 of those assets today. Alba is an asset that is a good asset for us and getting a lot better, and we expect a lot more out of it the second half of this year and in the long term. Bacchus has been an asset that has exceeded our initial expectations, and we're excited about the third well and what that will do for us, both from production and a future reserve growth for the company.

And finally, Rochelle, the long-awaited project first production is imminent for us. And one of the things that we found in drilling the initial well was an upside that we will pursue later in the life of the asset. And then also, a low-cost portfolio in the U.S. that we've not spend a lot of time talking about because we've constrained capital to it, but it's something that we're excited about when we get all this production up and running.

As Cathy said, we agree that the debt levels and the cost of debt are just too high and unsustainable for the company, but we do have a plan. We do have liquidity and a commitment to mitigate this situation over the course of the remainder of this year. We're committed to reducing the debt and interest expense remaining, and that's a priority of mine as we move down the road. As to the strategic review process, as I said earlier, we will keep you up-to-date as we define a course of action once we've had a chance to go through all the alternatives with our board, and that will probably be later in the year.

With that, I'd like to open it up, Lisa, to Q&A, any of you that might have some questions for us.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Steve Berman with Canaccord.

Stephen F. Berman - Canaccord Genuity, Research Division

Carl, can you talk about Centurion South? First, what was the cost of that well? And second, if you do determine it is commercial, would you be able to go back in to this well, which is plugged and abandoned, or would you have to drill a new development well to produce from that field?

Carl D. Grenz

Steve, thanks for the question. The original quest was to find a complementary discovery in the south area of the Centurion field, and recall we had a discovery in the North Centurion area. We wanted this to be complementary to it, so we could have a sizable development that could be easily tied back to infrastructure in the area. What we found was the reservoir was thinner than expected in this area. So it's causing us to pause now to see what we can do commercially in conjunction with the northern area to see if we can make a commercial development out of these areas. The well that we drilled has been P&A-ed. It was never anticipated that we would reuse this well as a producer. So it was just purely and simply an exploration well. So if we conclude finally that there is a commercial development to be added here, we will be drilling a new producer to bring these to our reservoir areas.

Stephen F. Berman - Canaccord Genuity, Research Division

And what was the cost of that well?

Carl D. Grenz

The cost related to Endeavour was $11 million.

Stephen F. Berman - Canaccord Genuity, Research Division

And that's the 8/8s? That's the full cost?

Carl D. Grenz

No, that's the Endeavour share.

Stephen F. Berman - Canaccord Genuity, Research Division

That's your share, okay. Then a question for Bill, what are you budgeting for that Niobrara well, and remind us again where that is in the play?

William L. Transier

Well, it's in the Piceance Basin. Jim's here, so I'll let him speak to that.

James J. Emme

Yes, Steve, this is Jim Emme. We're in the northern Piceance Basin kind of halfway between Rangeley field and the Buck Peak area, which is a pretty active area in the Niobrara right now by the way. The pilot test is a low-cost vertical pilot with cores that will enable us to identify where we want to go horizontal in the future. It's a couple of thousand feet of prospective section both in the Niobrara and the frontier, and we're very excited about the well. It's going to be in the Rio Blanco County, and it's called the Wylie unit, which is an approved unit. As Bill mentioned, we've got the drilling permit in hand, and we expect to be drilling later this summer.

Operator

And we'll take our next question from Neal Dingmann from SunTrust.

Unknown Analyst

This is Will [ph] for Neil. I guess looking at West Rochelle, how much longer do you all think it takes -- or how long does it take to tie it in and complete the well from where you are now?

Carl D. Grenz

Will, this is Carl again. Once we've finished running the completion assembly, it takes just a small number of days to complete the tie-in of the final spool piece from the wellhead to the manifold that's already in place on the same bed.

Unknown Analyst

Okay. And then where you are now? What's the current estimated cost of that well?

Carl D. Grenz

The current estimate cost of the west well is, in gross terms, GBP 43 million. We have 44% of that, $30 million.

Unknown Analyst

Okay. All right. And then you mentioned the possibility going back into Rochelle East, going back into that well. If that didn't work, what's the P&A cost on that?

Carl D. Grenz

The P&A would be, because it's a conventional P&A, would be about GBP 10 million gross to do that.

Operator

We'll take our next question from Chad Mabry with KLR Group.

Chad L. Mabry - KLR Group Holdings, LLC, Research Division

Just another follow up on Rochelle for Carl, I think you had mentioned in your remarks that you're expecting to keep the prospect rig and maybe drill another well before the east well. It was -- I guess first of all, is that accurate? And then it sounds like you do plan to drill that second well this year also?

Carl D. Grenz

Yes, the prospect that's drilling the west well now will leave us for a short period of time to drill an exploration well not to do with Endeavour. Then that same rig will return to the east and drill a new well on the east called E2.

Chad L. Mabry - KLR Group Holdings, LLC, Research Division

And just to clarify, the timing of that?

Carl D. Grenz

Well, the gap following the completion of the west well will be around 40 days. We understand the dry hole time for this exploration well that will be drilled. So it's going to be sort around about the middle of the year before it gets back to us.

Chad L. Mabry - KLR Group Holdings, LLC, Research Division

Okay. That's helpful. And then shifting over to Alba, it sounds like that you're expecting this year's activity to kind of boost production up to 25,000 to 30,000 barrels gross. Just for comparison, what was your gross run rate in Q1?

William L. Transier

It was between 20,000 and 21,000 barrels a day, probably 19,000 to 21,000, dependent on the day.

Chad L. Mabry - KLR Group Holdings, LLC, Research Division

Okay. That's helpful. And then just one last follow-up if I could, you had previously mentioned that you were expecting to incur about $36 million of decommissioning charges this year. Is that still the expectation? And when should we look for those to hit?

William L. Transier

I'll answer for Carl. We've spent probably close to 1/3 third of that already, not quite 1/3. I think Carl and his folks are ahead of budget on that. The original estimates were closer to $40 million. I think when we talk to you last, Carl said $36 million. I think we've been fairly efficient in the way that we've done that work. And the equipment will come back to us kind of in the third -- later in the third quarter and finish up the work. So you'll see that work kind of third and fourth quarter.

Operator

Our next question comes from Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Bill, you stated in your prepared comments that you're confident that the second half of this year you could get to a run rate of 20,000 a day. Just hoping we could examine that a little bit, and if you could just piece that together for us how you get from where you are here at a little over 9,000 a day to that 20,000 rate, and just state if that's a max rate more on the capacity side or if that's really sustainable going forward we could think about in terms of modeling for average rates.

William L. Transier

Yes, Mike, I think it's a fair question. When I speak to that, that's what the portfolio can deliver and obviously, you have utilization rates across the assets that you have to consider. I've talked about this in terms of historical percentages in the North Sea and that varies depending on asset to asset. But the number we've used is 85%, 86%. If we get above that, Carl, as people get above that, we cheer ourselves for doing a better job. And what Carl talked about earlier in terms of Bacchus, the operator there has done a fantastic job because the uptime utilization rate of Bacchus has been almost 100%, not quite, but almost 100% and that's just never seen in the offshore arena. In answer to your question, Mike, when I look at this, you look at, first of all, Bacchus, which right now is achieving a little over 3,000 Boes a day, and Carl expects his third well to come on and he talked about a range of 16,000 to 18,000 Boes a day gross. So that means our piece of that at 30% is a little over 5,000 Boes a day. We expect Rochelle to come on with the west well, and Carl commented that our expectation is, is that the west well will handle the capacity limits across the Scott Platform, but we also expect to bring the second well on production sometime in the third quarter. So we do expect to get to capacity limits there, and we've talked about that. We have limits at 100,000 -- 100 million a day across the Scott Platform. That relates to about 6,000 Boes a day net to our interest. And then you have the Alba fields and Carl talked about 25,000 to 30,000 Boes a day later in the year once you get through the turnaround period and get these other development activities on and obviously, we have 25% of that. So that's 7,000, 8,000 Boes a day there. You add to that the other pieces of production we have and stuff. That's how I get to kind of the round number of 20,000 Boes a day. That's maximum, and then you got to look at what utilization rates are. But we should be coming out of this period end of the third quarter past the turnaround periods for the assets and having a -- be able to have a run rate at pretty much those capacity limits for a while through the early part of next year if we can make all these things happen.

Michael Kelly - Global Hunter Securities, LLC, Research Division

That's great color. Just to follow up on that, if we could talk about Rochelle -- I'm sorry, the Scott Platform and as it revolves around that capacity on it. And what are really the factors there that could cause some variability in rates from that 100 million a day max rate?

Carl D. Grenz

Well, Mike, the variability will come from just experiencing what we can get through the platform when we turn it on. We have made upgrade improvements to the gas compression system. We think we know what that will deliver. Until you actually start the thing up and fine-tune the control system, et cetera, you can't be absolutely certain what you're going to get. You saw the rates that Bill has talked about is what our expectation is in this first year. And we expect going forward that to increase as there is further decline on the inputs to the Scott Platform currently, if that makes sense.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Yes, it does. One more for me and this is kind of a higher level strategic question for you, Bill. If you look at your core assets in Alba and Rochelle, Bacchus, and I know you're going through this strategic review right now. But if you just look at those assets, and you mentioned that there's been a renewed interest and high interest from potential bidders and acquirers in the North Sea, looking at those assets, the value of those relative to the value of the company in terms of its enterprise value, you have $1 billion in enterprise value right now. And do you have confidence that those 3 assets right there could really be purchased by an interested party at a price over $1 billion?

William L. Transier

Well, Mike, it's a good question but obviously, I can't respond to that. I've looked at the -- we've talked about the value of these assets from our perspective a number of times, and you can look at it several different ways. Obviously, from an NAV perspective, which is the value of 2P reserves and we get to those numbers that you talked about pretty easily there and I think that there are, from my perspective, there's upside in 2P reserves in Alba, in Bacchus and potentially Rochelle with the oil Jurassic piece that we think will be there that we're doing more work on. You can also look at it on a cash flow basis, if it wasn't burdened by the debt that we have. At 20 -- close to 20,000 Boes per day with commodity price environment that we have of gas and oil, that generates, by anybody's math, somewhere between $400 million and $500 million a year in cash flow. Really, the burden on that in terms of maintenance capital, and obviously we have some decommissioning issues going forward, but the free cash flow from that on any kind of multiple gets you to the range that you're talking about in terms of valuation. So for us and for our board, it's a bunch of different simultaneous thought processes, whether it's an individual asset or a piece of our team or subsidiary or operations in the U.K. or even an ultimate kind of sale of the entire unit. And all of those things are under consideration, as well as what we're focused on, what Carl is focused on, is execution because once we get execution and we have this cash flow, the optionality for us gets huge in terms of value creation going forward. And I know that the market is not going to give us any credit until we execute and we spent way too long talking about it as a team, but we are close in terms of being able to deliver this to the marketplace.

Operator

Our next question comes from Welles Fitzpatrick with Johnson Rice.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

On the Centurion South prospect, and I apologize ahead of time if you guys hit on this, but could you talk a little bit about what thickness you and the operator were looking for? I believe the operator had put out an 18 million barrel resource estimate on it, kind of what that was based on versus what you all saw.

Carl D. Grenz

Well, this is still a tight hole consideration actually, so we can't talk in any great detail about the thicknesses that we found or expected at this point in time.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Okay. And then just sort of a housekeeping question on Alba liftings in 1Q, is it fair to assume that you guys will make that up in the second quarter? And am I remembering it right that 1 lifting equates to something around 1,000 barrels a day for the full quarter?

Catherine L. Stubbs

It does, and we see that -- we've changed our lifting a bit and we now lift kind of on a -- we were lifting with a group and we were more frequent -- seeing more liftings more frequently. We're now lifting on our own. So we also changed the contract to receive cash rather than on a lifting basis on a monthly production basis. So cash is now smooth, but you will still see the liftings being lumpy.

William L. Transier

Welles, before you -- I know you're hanging up, but I'd noticed on your notes this morning that you were disappointed in us with regards to our liftings. I think to be clear, and what Cathy talked about, we had 3 liftings in the first quarter and it just happens to be the timing on these things. We can time it where we had liftings, 2 a quarter, that would be perfect for us. Cathy has put in a new marketing agreement for our crude oil, which also allows us to do some of these embedded collars at really no cost to us and hedge our production. It also provides us monthly cash flow. From a cash flow perspective, we have more consistency than we had with the liftings. But from an accounting point of view, which never have agreed with the accounting in terms of liftings versus entitlement accounting, but from a liftings point of view, we're going to have some lumpiness in the revenue numbers but we will continue to show you what physical entitlement production is and that's what we tried to show in the press release today.

Operator

We'll take our next question from Amy Stepnowski with Hartford.

Amy Stepnowski

I was wondering, on the last call, you disclosed an estimate for the PRT for the year. I was wondering if you could give us any breakout on that for the first quarter?

Catherine L. Stubbs

Amy, yes, we paid around $2 million for PRT this quarter and again, our expectations are still about the same as we mentioned last call, around $40 million for the year.

Amy Stepnowski

Okay. Great. And also, I was wondering -- I just want to make sure I understand this correctly. With regards to the east well, obviously you've got this -- the rig is going to leave and come back. But did I understand correctly that if everything went according to plan, you were talking about it being on production in the third quarter? Would that lead us to think that the well on the west is going to come on in the second quarter?

Carl D. Grenz

Amy, the wells will come on around the middle of the year. The west well will come on around the middle of the year, and the east well -- the new east well will come on in the third quarter.

Operator

Our next question comes from Steven Karpel with Crédit Suisse.

Steven Karpel - Crédit Suisse AG, Research Division

Maybe first, just to clarify again on some of the stuff. On current production, I think you said current production was 10,000 a day. Can you give what the exit rate was on Alba and then what your current rate is on Alba?

Carl D. Grenz

The current rate on Alba is about 21,000 gross. When you say exit rates, what are you referring to, the year?

Steven Karpel - Crédit Suisse AG, Research Division

Really what I'm trying to get at is it sounds like the water-handling issues and some of the issues you had on in using chemicals and -- have improved. So I'm trying to understand how much you've improved since maybe the end of the third quarter, so in essence, March 31. I'm just arbitrarily picking that day.

Carl D. Grenz

Okay. Well, we were having some significant problems in the third quarter. So...

William L. Transier

First quarter.

Carl D. Grenz

So my guess is it's something like around 16,000 to 18,000 barrels a day at that point, gross. Yes, I'm getting confirmation that it's around 18,000 barrels a day. So we've been making significant improvements, fits and starts, but now we're seeing consistently the production is over the 21,000 barrels a day mark and climbing. So like I mentioned in my comments, by the time we get well into the second half, we should see us realizing production from Alba towards the maximum potential levels. And then bear in mind, you fold onto that, the new wells that we're drilling, that's why we say we're going to see production levels as high as we've stated towards the end of the year.

Steven Karpel - Crédit Suisse AG, Research Division

Great. And then just one quick one on Bacchus, then a couple of financial ones. There's no capacity limits on takeaway?

Carl D. Grenz

Not within the bounds of possibility that Bacchus could deliver, certainly not.

Steven Karpel - Crédit Suisse AG, Research Division

And then the -- you walk through Rochelle, I was a little confused on what you think you have left to do there because you talked about the manifold. Well, from my, I suppose, layman's perspective, it sounds like these are days to complete. So can you walk through maybe what the checklist is to do and how long some of those items take?

Carl D. Grenz

Okay. Certainly. Well, to turn the Rochelle development on, we need to complete the west well. Bear in mind that, that has been completely drilled out now. So what we're doing is installing the completion assembly. That's the piping and the liner that's in the bottom of the well that connects to the surface. That work is well underway, and we're actually installing the tree as we speak and that will enable us then, once the tree is installed, to do the final spool piece tie-in to the manifold. It's just tens of meters away from the manifolds is where the wellhead is. So that's a relatively small amount of work to do on the well itself and the tie-in of the well, so we will be able to start production up and go to a fairly rapid ramp-up, we feel. Towards the end of June, towards the middle of the year, we'll see that production flowing onto the Scott Platform.

William L. Transier

Steve, to kind of add, I don't want you to get too anxious about this getting done because...

Steven Karpel - Crédit Suisse AG, Research Division

Hey, you see where I'm going, obviously.

William L. Transier

Well, I do, and I don't want you to get ahead of it and several questions have come around. But Carl is right. Right now they're running the subsea tree. We have to run a BOP stack. We have to recover the short-term suspension plugs and clean out all the tubulars. We've got to run the gravel pack. We'll have to do some inflow test and clean up the well, install the tree barriers and then remove the rig and then do the spooling of the well to the manifold. So as much as you and I think, from an onshore perspective, you can do that in no time, it takes some time out there, and we've got equipment arranged to get that done. But we have pointed, as much as we're going to in terms of the questions today, to the middle of the year. The middle of the year means somewhere around the middle of the year, June 30. So that's the hope in getting this done. We have not historically been able to deliver on what we promised. So allow us to get this done. Just know that we're making progress on the west well. Carl and his team were on top of this every single day. If you don't think we're watching it every minute of the day, you're misled. So there is work to be done, but it's not a next-couple-of-days situation, Steve, to get this wrapped up.

Steven Karpel - Crédit Suisse AG, Research Division

Understood and appreciate that. And then maybe jump over to Cathy here. I'm trying to understand, I think you'd indicated a current cash position, but I'm trying to understand that in context of, it looks like the working capital number went up pretty substantially. So what -- how is that going to funnel through as we go through the rest of the year? In essence, the working capital on the liability side, there was the adjustment. So trying to understand what that will mean for cash flow as we move later in the year.

Catherine L. Stubbs

Sure. Our current working capital did go down a bit, and the accrued expenses include our forward sale deferred revenue piece and that's going to turn around over the next 6 months. We did basically move $23 million forward on that, and it also includes our current piece of ARO. So that's about $35 million sitting in that. And again, as we mentioned, some of that spend is deferred out later into the year. So again, pro forma cash is around $146 million once we've received the additional proceeds on the monetary production payments that we mentioned. We've kind of laid out for you the capital expenditures that we plan during the year. The additional well on, if we do anything on the east, will come in, again, after the west is expected to be turned on towards the end of the year and likely, some of the cash payments will be deferred into 2014. So and that, coupled with the kind of expected increases in production that Bill walked you through can give you an idea of cash flows in from where we sit today.

Steven Karpel - Crédit Suisse AG, Research Division

And just 1 follow-up to understand this on the CapEx. To use the cash flow statement number was 58 spot 3. So -- for what you call CapEx. What is that number going to be for the full year then in comparison to the numbers that you gave as we think about what the accrueds are, what the AROs and whatnot?

Catherine L. Stubbs

Yes, well as I mentioned, the direct spend was about $33 million. That number on the cash flow statement includes the working capital changes that run through our accrual. So that shows what we paid this year that was accrued at the end of the is why it's up a bit. So depending on -- expect that current payables will be pretty consistent with where they are today kind of at year end or down some. So you can tack on to that number kind of our estimated spend on what we've told you. We still have left on the assets for the rest of the year.

Steven Karpel - Crédit Suisse AG, Research Division

Right. Not to push this, but you seem to imply $170 million number for CapEx, and you said you spent $130 million something. So are we supposed to just tack on $140 million on to this $58 million and call it, give or take, $200 million is the actual cash flow statement number?

William L. Transier

No...

Catherine L. Stubbs

No, again, so you should -- what you should have there is since the $34 million is what we incurred this year, $58 million is what we've paid out. So the delta of that $25 million really relates to last year's payment coming through this year. So if we plan on what you think, we're going to spend out based on what you think we're going to be spending capital and know that you already have a $25 million delta coming in from the beginning of the year related to last year, that's kind of how you should look out for year end.

William L. Transier

Steve, I think that we've confused this issue. But look at Slide 8, that's why we put that in there. We expect to have a run rate of $140 million to $150 million in the U.K., and we've talked about $10 million to $30 million in the U.S., back-end loaded and discretionary. And I think that's the run rate that's a fair estimate of where we see it right now. If you look at the first quarter, we were less than that run rate on an annual basis, and we have quite a bit of activity going on in the second quarter. That will slow down in the third quarter in terms of capital spend, and then it will speed up towards the end of the third quarter and into the fourth quarter. So -- and hopefully, you'll have Rochelle production on and the third well at Bacchus on to help with the funding of that as we go forward. In terms of working capital, you have some of that classification for accounting purposes of what the monetary production payment is and some deferred revenue, but you got to do pro forma with the cash that came in that Cathy talked about that makes it a positive working capital number on the balance sheet. So we're on track. I would point you to the direct capital expenditures on Slide 8. That's our best guess right now.

Operator

And we'll take our next question from David Epstein with CRT.

David Epstein - CRT Capital Group LLC, Research Division

The new East Rochelle well, putting that into the plans, that didn't change anything as far as CapEx guidance, or just there are some other offsets? Or how should we think of that?

William L. Transier

I think that we didn't finish the east well, and obviously we're going to go drill another E2 well, as Carl talked about. That probably adds some amount of capital to the estimates that we built into that. That's offset by some reductions in both decommissioning as well as in the Centurion well and what we're planning in the U.S. So we won't go back and do any work on the E1y well that we pulled off of until next year, as Carl talked about. So I don't know what all that means net-net-net. But probably, we've got another 15 or 20 built into the numbers this year that otherwise might not have been there as we go forward. So -- but we're looking at all the nets to this, and that's why we still think that $140 million to $150 million is the right number for us.

David Epstein - CRT Capital Group LLC, Research Division

Okay. And you guys gave a little bit of color where I think you said the 2 existing Bacchus are over 3, and the third one will bring on another 2. Can you give us a sense of sort of what sort of decline you expect on the 2 existing Bacchus from now till Q4 when the third one comes?

Carl D. Grenz

I don't think we're, Dave, seeing very much in the way of decline this year on these 2 wells. What surprises to the positive is the performance of the first well. Its production profile is now flat. Whereas, we expected that to continue declining through this year, so we see none of that happening. And the performance of the second well is still on plateau, and we expect that to be on plateau, by the way, through this year. As we mentioned, the well is actually being choked back due to temperature limitations and it's only 20% open. So as it declines, as we've seen it minimally declining, bear in mind, this well has been on for some time now. And the choke opening, when it first came online, was 16%. So it's only been opened by 4% in the whole time it's been flowing since July last year. So that's all positive indications that we'll see the current levels of production exiting this year and except that we will add onto it the performance of the new well. So we'll be looking to have somewhere in the region of 7,000 to 8,000 barrels a day gross from that well.

David Epstein - CRT Capital Group LLC, Research Division

And on the second well, any sense of what that percentage decline is? I understand the first well has been flat, will remain flat. The second well, I mean, is it declining 5%, 10% a year? Or any more color?

Carl D. Grenz

No, it's too early to say. As I say, it’s still on plateau. We're not seeing very much -- it's very single numbers any way, the decline. But we're not seeing very much in the way of decline that's on either of these wells.

David Epstein - CRT Capital Group LLC, Research Division

Is there a way to think of how long that can persist whether it's, again, measured in quarters or many years?

Carl D. Grenz

We're still modeling the surprise, the nice surprise that we're seeing from this reservoir. So it's just too early to say how the whole area will perform unfortunately, Dave.

David Epstein - CRT Capital Group LLC, Research Division

Okay. And finally, can I just ask on Alba, which was only $2 million in the quarter. I don't know how much of that was just because sales volume was low versus you had some sort of shield against it. Can you give us a sense of some of the assumptions that will drive the $40 million in the year? And again, I think it's driven by OpEx and some sort of CapEx per barrel figure. So can you give us those?

William L. Transier

We're all kind of scratching our heads, so would you ask the question again so we can...

David Epstein - CRT Capital Group LLC, Research Division

Yes, sorry, I wasn't clear. One, the PRT tax, which you said was $2 million in the quarter, I assume that was a function of just very low sales in the quarter, liftings, but maybe it was something else, maybe you can inform me a little bit more about that. Second question is, when you come up with the $40 million PRT assessment estimate for the full year, what's baked into that as far as the PRT tax, correct me if I'm wrong, is determined by basically your revenues minus some OpEx and then there's some CapEx attributed in the PRT? So I just want to know what assumptions you're using there to come up with a $40 million figure for the full year?

Catherine L. Stubbs

Dave, yes, so on PRT, it did have an impact at the lower volumes. PRT is basically kind of like a corporate income tax calculation on the revenue minus expenses, minus your core CapEx for the field of Alba. We also can deduct our LC decommissioning expenses there as well. So that's kind of how that tax is -- taxable income is calculated, and the rate there is 50% for PRT.

David Epstein - CRT Capital Group LLC, Research Division

And what is the -- do you have like a CapEx per barrel figure that you can share when you come up with that estimate?

Catherine L. Stubbs

Well, for Alba, we've said that kind of our maintenance plan for the year is around $30 million for capital.

William L. Transier

We probably didn't do a good job answering the question, but the way PRT gets paid over there is kind of on a 6-month lag rolling schedule with the HMRC, but the way we book it for financial statement purposes is on an effective tax rate calculation basis. So the $2 million kind of is probably an abnormal low number when you think about $40 million for the year. But I think the way that Cathy described it based upon estimated production less operating cost less capital less LC fees in terms of coming up with an estimate at 50%, you can kind of come to that $40 million we talked about.

David Epstein - CRT Capital Group LLC, Research Division

Okay. But on that front then, with the $2 million abnormally low, is $40 million sort of a reasonable normalized number? Or it's more something like low 50s if for -- on a run rate where you don't have an abnormally low quarter?

William L. Transier

I think our view is that it's going to be for the year in terms of the way it works. And I don't know whether you're most concerned about the book accounting or the cash outflow, we're most concerned about the cash outflow. We think it's going to be at or below $40 million.

David Epstein - CRT Capital Group LLC, Research Division

I'm more concerned about the cash flow -- the ongoing cash outflow. And you're saying on an ongoing basis, that's a reasonable normalized level as well, a little bit over $40 million?

William L. Transier

I think so, and it obviously depends on the ramp-up of the production at the end -- as we go throughout the year and those kinds of things. So I -- maybe we jumped ahead of ourselves by throwing a number out there. But ask us again in the second quarter, we'll give you a better estimate for the year.

Operator

We'll take our next question from Ravi Kamath with Global Hunter.

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

A couple of questions. One, once you complete the decommissioning of the IVRR fields, would that release the $33 million of LCs that you have, or when would those be released?

William L. Transier

Yes, the answer is that...

Catherine L. Stubbs

Yes, you're right. That LC is able to be released upon completion of our decommissioning program.

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

And would that be in 2014?

William L. Transier

No, I think the work on IVRR is going to carry into through next year and probably even into 2015. It's just a matter of scheduling and the plan that's been laid out by all of us in terms of where that goes. So -- but I don't think it's unreasonable to think that as we did to the final stages of the work that needs to be done that, that LC will be eliminated and stuff. We obviously look at that.

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

Okay. And then any estimate for timing of when you can cut your Alba LC in half?

William L. Transier

I think Cathy's desire is to put a revolver in place before the end of the year and probably in the second half of the year. And most likely, as we've talked about in the past, once you get Rochelle turned on, it makes that a lot simpler avenue to go forward. She's got a group of banks that she's working with right now. Once you put that revolver in place, that will house the LC for us and you will handle it there at a much lower cost of capital. And also as she talked about, as we move throughout the year, we ought to be able to do it on an after-tax basis, which hopefully will bring that number down dramatically from where we're at.

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

Got it. And then just on Alba for Q2 of '13, should we be thinking about sort of the normalized 2 liftings, or any color on Q2?

William L. Transier

We certainly hope so.

Catherine L. Stubbs

Yes, I think it should be around every 6 weeks or so.

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

Okay. And then one last question. I know you guys have provided a 2P pretax PV10 number. I was wondering if you had that on an after-tax basis since the tax rate is so high in the U.K.?

William L. Transier

We haven't provided that number but...

Operator

We'll take our next question from Randy Laufman with Odeon Capital.

Randy Laufman - Odeon Capital Group LLC, Research Division

Question on -- just a clarification on the CapEx and the cash flow timing. Is it typical that you have some delays as far as timing of when you are booking your CapEx and the actual payments? So if you're going to spend the budgeted CapEx this year, some of that gets delayed into next year?

Catherine L. Stubbs

Randy, no, we accrue for our capital as we incur the expenditures. So it's -- and we're current with our payables, so it's more of a lumpiness of spending and timing of pay. But no, we accrue for it as we spend it.

Randy Laufman - Odeon Capital Group LLC, Research Division

Okay. And then just a question on the forward sale agreement and the MPP agreement. Wondering if there's any ability to do additional transactions such as those if the company needs to raise additional liquidity?

Catherine L. Stubbs

Yes, we do have capability to do that, and you may see us doing that. We see it as positive. It allows us to lock in to commodity prices, while at the same time, bring in revenue and liquidity forward. So we do have capacity to do that, and that's an option for us for liquidity.

Randy Laufman - Odeon Capital Group LLC, Research Division

On the MPP as well?

Catherine L. Stubbs

Just kind of forward type thinking instrument in general what I was referring to.

William L. Transier

I think we've done as much of the MPP as we plan to do. There's a -- there -- it provided the liquidity we think we need and we'll do the rest in terms of short-term lumps and forward sales where we can lock in commodity prices on a 6-month kind of rolling basis if we need it.

Operator

We'll take our next question from Steve Puckowitz with Stifel, Nicolaus.

Stephen Puckowitz

Sorry to just missed this. I've been on and off the call. When you talk about the $30 million of maintenance CapEx, that's just for U.K. or is that for the whole business?

Catherine L. Stubbs

We can barely hear you. Can you repeat that?

Stephen Puckowitz

Hold on one second. Okay. Maintenance CapEx, this may have been repeated already, but you talk about $30 million for 2013. Is it just U.K. or is that the whole business?

William L. Transier

I think we've talked about it in the past that $30 million to $35 million is maintenance capital for the U.K. We don't really have much in the way of maintenance capital for our U.S. portfolio, and most of that maintenance capital is really the way we define it associated with Alba. And Carl talked about the development infill drilling process that will be ongoing, we think, for as long as we're involved in Alba probably at that same level, 3 to -- 2 to 4 wells a year and obviously some workovers as we go forward. So our estimates, even when we were acquiring the additional interest in Alba, we always talked about $30 million kind of number. So that maintenance capital is, as Cathy said, was $35 million and that's really the U.K. Nothing more to speak to other than that.

Stephen Puckowitz

Understood. I guess I would follow then the U.S. assets, I understand the valuation of the company being centric to U.K. But would it make sense to have ongoing discussions about maybe monetizing the U.S. assets to plug some of this liquidity, and is that possible?

William L. Transier

I think we said in our press release back in February that we were looking at all alternatives, and that includes the U.S. From our perspective, and I said it earlier in my comments, I don't think the market gives us any credit for the U.S. asset base. It's a low-cost set of assets with 2 pretty exciting areas for us, both in the Piceance Basin as well as in now an operated position in the Marcellus. And we have constrained capital on our U.S. team, and there's not much value there given in the marketplace because we really haven't highlighted it at all. But in answer to your question, as I said earlier, the board and myself are looking at all alternatives, and it's the trying to get the best answer for shareholders as well as trying to delever and reduce our cost of capital in the near term and that's what we'll do.

Operator

And that concludes today's question-and-answer session. I would like to turn the conference back over to Darcey Matthews for any additional or closing remarks.

K. Darcey Matthews

Lisa, thank you, and we thank everybody for joining us today for our first quarterly conference call and look forward to answering any of your questions that we didn't get to cover today on the call. Thank you, again.

Operator

And that concludes today's teleconference. Thank you for your participation.

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