Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Endeavour International (NYSE:END)

Q4 2012 Earnings Call

March 06, 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

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

Carl D. Grenz - Executive Vice President of International

James J. Emme - Executive Vice President of North American Operations

Analysts

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

Steven Karpel - Crédit Suisse AG, Research Division

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

Philip L. Dodge - Tuohy Brothers Investment Research, Inc.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Hassan Jawed Ahmad - Imperial Capital, LLC, Research Division

Rehan Rashid - FBR Capital Markets & Co., Research Division

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

Amy Stepnowski

Operator

Good day, and welcome to this Endeavour International Corporation's Year End Fourth 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 conference over to Ms. Darcey Matthews, Director of Investor Relations. Please go ahead, ma'am.

K. Darcey Matthews

Thank you, Kyle. Good morning. Good afternoon, everyone, and thank you for joining us today for Endeavour's 2012 Fourth Quarter and Year End Earnings Conference Call. Joining us today, we have our Chief Executive Officer, Bill Transier; our Chief Financial Officer, Cathy Stubbs; 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 everybody know that there is a slide deck supporting today's call that management will be speaking to available on our home page at endeavourcorp.com, and also under the IR section as part of today's webcast details.

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-Ks and 10-Qs, and the annual 10-K expected to be filed in the next couple of weeks.

Now for some opening comments, I'll turn the call over to Bill.

William L. Transier

Thank you. Good morning, everyone. We see that there's a lot of interest this morning, and we certainly expected that, glad to have you with us.

As you can see from the press release that we put out overnight, we've had a lot of progress in the last 3 weeks since we made some news events back then.

But before I talk about recent events, let me do a brief review of some of the 2012 accomplishments as we're here to talk about fourth quarter and year end 2012.

First of all, you can see from the numbers that production more than doubled in 2012, with the run rate at the end of the year 2012, almost triple what it was the year before that.

Proved reserves were up 186% in the U.K.. And overall they were up, even though we had to move a fair amount of our U.S. reserves from proved to contingent resources because of weaker average North American natural gas prices.

During the course of 2012, we turned on 2 development wells at our Bacchus field in the North Sea. This asset has had a continued strong performance, actually better than originally expected. We completed the acquisition of an additional 23.43% interest in our Alba field in the U.K. North Sea. Alba, as many of you know, is currently our largest producing asset. And along the way, we spent a lot of time and made a lot of progress, albeit didn't get the production turned on at Rochelle, but got it very close to that towards the end of the year. And we'll talk more about that as the day rolls on.

Since the end of 2012, our production has stayed basically steady and consistent with what you saw in the fourth quarter. We're very pleased with crude oil prices in Europe, and European natural gas prices have remained strong, so we're anxious to get our Rochelle project turned on and take advantage of that.

Just 3 weeks ago, we announced a new Chief Financial Officer, we also told you about weather-related issues with our East Rochelle production well and further delays to that first production there. And we also announced a strategic review process for the company. We will get into all of these matters as we go throughout the day.

In the last 2 days, we have announced the series of transactions that have added $350 million of near-term liquidity to our company and cushion our ability to finish the development work at Rochelle and complete a thoughtful and disciplined strategic review process.

Let me address each of these matters in a little more detail before I turn it over to the team to give you all the details about the quarter. First, with respect to naming Cathy Stubbs as our Chief Financial Officer. The board concluded their search and determined the best candidate for Endeavor was Cathy. I actually endorsed that strongly. A complement to her that the Board made this selection after going through a detailed search process. Cathy has been with our company since its beginning. I've also worked with Cathy in several situations since she graduated with her master’s degree from the University of Texas over 20 years ago. She is a highly skilled professional with a very strong accounting foundation from her years at KPMG. She is very knowledgeable, frankly, the most knowledgeable person about our capital structure and our capital investors. And she has stepped into this new role and doing a fantastic job. The liquidity that was created here in just the last few days and weeks for the company, in a large part, is due to Cathy's strong efforts after stepping into this role as Chief Financial Officer. You'll get to know her as we go forward. And I think you'll get to appreciate the strength that she brings to our team as we head down this path.

With respect to the strategic review process announced a few weeks ago, the Board will be considering a full range of alternatives, including a sale of specific assets, sale of joint venture of partnership in respect to the company's activities in either the North Sea or in the U.S., a sale or merger of the company or we may, as things unfold, continue to execute on the company's operational plans as they now are in place.

As you saw, we've hired 2 advisors: Tudor, Pickering, Holt and Lambert Energy Advisors out of the U.K. Each of these advisors, in my view, was selected for their experience, their reputation, and importantly, their relationships with parties that we think would be interested in the process that we're about to go through. They are a formidable team for us, and they're doing a fantastic job together to make this process good for our Board of Directors. Our objective of the process is to accelerate the deleveraging of our balance sheet and to unlock what we believe is the underlying value of the company's assets. We cannot really give you any guidance on the timing. Other than for obvious reasons, we expect to move through the various alternatives thoughtfully and expeditiously.

With respect to the increased liquidity of the company through the series of transactions, you will see, and you will hear more from Cathy about the fact that we extended our revolving credit agreement and 2 reimbursement agreements to midyear 2014, providing $220 million of liquidity for 2013.

Our forward sale was for $22.5 million. This is relatively short-term movement. In my view, the purpose was to move cash flows from the second half of the year to the first half of the year and lock in Brent crude oil prices, which we actually did before this recent slide in Brent pricing here just in the last week or so.

We entered into an agreement to sell a monetary production payment in the amount of $108 million. And the purpose of all of this was to add liquidity and to provide cushion to allow us to get Rochelle production turned on and go through this rational strategic review process.

Now I consider all of these actions as important because the U.K. North Sea is now, and most recently, showing an impressive signs of renewal and activity. And interested investors, who know the value of the petroleum basin, are entering into it every single day.

The U.K. government has or is in the process of implementing some very positive tax and regulatory legislation to stimulate investment in the North Sea. These initiatives will improve how decommissioning is handled and provide allowances for smaller fields and fields that are candidate for redevelopment, such as Rochelle and Alba and others that could possibly fall underneath these positive tax allowances going forward.

Our portfolio has the ability to deliver significant free cash flow once Rochelle and Bacchus are fully developed. And we're less than 1 year away from being in a positive cash flow position that would exceed any capital requirement for several years in the future.

I just want to say we're committed to reducing our debt levels, reducing the carried cost on debt and the cost of our capital as indicated in the initiation of our strategic review process. The preservation, in my view, of the value of our assets is our primary goal, and we will do everything possible to capture that value for our shareholders as we go throughout the rest of the year.

With those opening remarks, I'd like to turn it over to Cathy and let her run through the fourth quarter numbers and some things about these financing and other liquidity transactions that we just had. Cathy, welcome to the team.

Catherine L. Stubbs

Well, thanks, Bill, and hello, everyone. Thanks for joining the call today. I've been in my role for 3 weeks, and I'll say it's been very active. I'm excited to roll out our recent financing transactions that we put in place, as current as yesterday, that provide immediate liquidity to the company and address our near-term obligations that we were faced with.

My plan for the call, first, I'd like to take you through the numbers for the quarter and the year. Then I'll give you some details on the financings. And finally, give you an outlook for 2013 capital expenditures.

Turning to the numbers. I'm on Slide 3, there's a slide on volumes. We were up 4,115 barrels of oil a day year-over-year or 133%. This is primarily due to the additional interest we purchased in Alba in May 2012 and the startup of our 2 Bacchus wells, the first in April and the second in late July.

Over the third quarter, we were up about 535 barrels of oil a day. And again, we have a full quarter from the Bacchus production in the fourth quarter. And we also had a listing in bid turns in the fourth quarter where we didn't in the third. This increase was offset somewhat by some various maintenance issues at Alba impacting production capabilities there that Carl will speak to.

And as you know, we record sales volume as listings occur. Our sales volumes exceeded our physical production in the fourth quarter, primarily due to timing of listings in Alba versus the production there. We exited the year at around 10,400 barrels of oil per day.

The composition of our production in the fourth quarter of 2011 was predominantly U.S. gas, around 73%, with 1/4 of that being U.K. oil. We've shifted primarily with the purchase of Alba for 2012 into an 80% U.K. oil mix and 20% U.S. gas.

Pricing, the commodity prices have remained strong during the quarter and the year. In the U.K., our Brent price averaged $110.08 in the fourth quarter versus $109.5 in the third quarter. Brent pricing has remained in the $110 to $115 barrel per day -- I'm sorry, price per barrel range and is currently at $112 a barrel.

NBP, which is our index pricing U.K. gas, is around $10.47 MMBtu in the fourth quarter, increasing from $8.97 in the third quarter. Current NBP is approximately around $10.90 per MMBtu. This will be what our Rochelle asset, which is gas, will be priced on this index.

Henry Hub gas pricing in the U.S. increased to an average of $3.39 in the fourth quarter, up from $2.88 in the third quarter. Henry Hub prices have continued to strengthen since the end of the quarter and are currently around $3.50 range.

We're encouraged by the strong pricing environment, and we look to lock in pricing as we bring on volume. We have hedged our exposure to commodity prices through instruments, including our forward sales, our embeddings and puts and calls or callers into our marketing contracts. And our goal is to remain hedged around 50% of our estimated production, and we'll work to achieve this goal as we bring on production.

Revenues, given this mix of sales volumes and price, were up $159 million year-over-year or 265%. Currently, our revenues again are predominantly oil. This mix will change dramatically to a more balanced mix when Rochelle comes online, which is again, U.K. gas.

Operating expenses. Year-over-year OpEx was up, with increased production primarily. We also had a onetime charge for inventory purchased with the Alba acquisition of $9 million that flowed through. From the third quarter to the fourth quarter, we were flat at around $23.9 million each quarter.

You can see on Slide 5, we've shown you some metrics on a BOE basis. OpEx per BOE year-over-year is up $6 a barrel. Again, this is primarily due to Alba's higher cost per barrel operating cost, and this field being a larger part of 2012 production. However, we believe these average costs are still reasonable to us.

DD&A expense increased from 2011, primarily again related to the increased volumes in 2012. It's also up due to higher decommissioning cost estimates that run through DD&A expense as accretion expense.

Impairment expenses, we had charges during 2012. We are under the full cost accounting rule. And in the U.S., we had a reduction of the 12-month average gas price, which you use to perform this test and had a $6 million charge in the fourth quarter and $53 million for the year 2012.

G&A is up year-over-year, primarily due to some increased compensation, which is partly noncash stock comp and consulting fees, as our U.K. operations grew with the production there. On a barrel -- BOE basis, however, I'll point out that GOE -- G&A is down, primarily half of that of last year.

Interest expense is up in 2012 over 2011 due to our high-yield offering and our revolving credit facilities. This is partially offset by the repayment of our senior term loan and notes payable. Capitalized interest was also greater in 2012 due to working progress associated with our development projects in the U.K. on Rochelle and Bacchus.

And just to remind you, in the fourth quarter, we did add liquidity there through upsizing our high-yield debt by $54 million and increased our revolving credit facility availability from 100 to 115.

Just a note, interest expense includes some noncash items. There's a $14 million charge for amortization of debt issuance costs and the noncash interest on our 11.5% convertible bonds that picks to the principal amount there.

Letter of Credit fees. This, again, represents charges on our 2 Letter of Credit facilities for decommissioning. The largest of which is $120 million on Alba that was necessary to put in place the Alba purchase. My plan is still to handle these LCs with a more traditional bank facility, which would significantly reduce the costs. We're working on such a facility now, and we believe we'll get the best results from this facility as Rochelle comes online.

Income tax expense. Deferred tax charges include an entry for the U.K. tax law change on rates, which decreased our benefit from 62% to 50%. That was recorded last quarter. Current taxes, our current cash taxes are for PRT only were shielded by our net operating losses for the remainder, and that was about $32 million.

Just to point out, we ended the end of the year with a U.K. net operating loss, which shields future U.K. income of $501 million for CT and $379 million for the supplementary charge tax.

All this mix on Slide 6 shows our adjusted EBITDA. Again, we ended 2012 at $130 million, a 426% increase over 2011. And again, it's primarily impacted largely by our increased production and strong prices.

Slide 7 shows our adjusted net loss. Again, while EBITDA is up, these increases were offset, primarily by our higher interest cost in LC fees, bringing us to a net loss of $61 million as compared to $50 million in prior year.

Capital expenditures for the year of 2012 on Slide 8. Our direct oil and gas expenditures during 2012 were around 190, and we're focused on U.K. spending primarily on Bacchus, the 2 wells and Rochelle, with some infill drilling in Alba.

We had acquisitions CapEx, and that was to close the Alba acquisition in May 2012. You'll see we had asset retirement obligations. This is a noncash amount, which has corresponding increases to obligations short-term and long-term on the balance sheet, which are for increased estimate of abandonment retirement obligations due to really our increased working interest in Alba and some adjustment to timing of obligations at other fields.

So that runs us through the numbers. Next, I'd like to take us through the financing transaction. My focus has been the following. First, to provide liquidity. Second, putting a lower cost of capital. And third to delever. I'm committed now to work hard to achieve these goals.

The first of which is liquidity, which we've made significant progress in achieving this. Over the course of the last 2 months, the bulk of which has been in the last few days, we've executed a number of transactions that give us significant financial flexibility. This flexibility allows us to, again, execute on our Rochelle development project, bring on, turn on -- drill the third well at Bacchus and conduct a rational and thoughtful strategic review process.

Here's a summary of what we've done. In January, we announced a new reimbursement agreement arrangement to essentially push out our existing expiring $33 million reimbursement agreement. That Letter of Credit secures obligations at IVR are winning ruby fields in the U.K. This maturity now is in July of 2014, and we've terminated our old reimbursement arrangement. This new arrangement has a slightly lower cost, 9% versus 11.5% of the old.

At the end of February, we announced a forward sale agreement. This gives us $22.5 million, which we've received forward, and we repay this through barrels of crude oil from assets in the North Sea, about -- excess of $200,000 over a 6-month period. This also gives us a hedge against commodity price risks from these barrels as we locked in the price.

Next, we've been working with our existing lenders on the revolver and the reimbursement agreement, both of which were due in 2013. We executed extensions yesterday on both facilities, $100 million of the $115 million due on the revolver has been extended from October 2013 to June 30, 2014. The full $120 million reimbursement agreement obligation, which was due at the end of this year, was extended also to June 30, 2014.

Also yesterday, we entered into a monetary production payment. This was with a group of investors for a purchase price of around $108 million. This will be repaid out of production stream of certain U.K. assets. Targeted payment timing is over a 2-year period and the amortization payment's designed to be light in the near term to give us liquidity and back-end loaded.

Just specifics. In the first 6 quarters of this 2-year period, we target to pay back 20% total of the total purchase price and then the last 2 quarters split the balance. That equals in the near term quarters around $3.6 million per quarter. This transaction is subject to normal regulatory approval, similar to what we just went through with our forward sale and received approval.

The result of these recent transactions brings us over $380 million in increased liquidity. $250 million of that is through deferring our obligations and $130 million through near-term cash.

From my perspective, these transactions remove immediate liquidity concerns and take capital raising activities off the table. This gives us a runway to act on our plans while maximizing shareholder value.

Longer-term plans, as to lowering the cost of capital, we continue plans to put in a lower-cost reserve base lending facility, as I mentioned. And also delever out of cash flow from operations as we increase production and seeing the results from the Bacchus third well and from Rochelle combined with a mix of the potential outcome from our strategic review will provide us the ability to pay down debt.

And that summarizes the recent financing transactions. So to give you a picture of 2013 capital expenditures, we have a Slide 10 that speaks to this. In 2013, we will stay focused on our key developments. In the U.K., we plan to spend $140 million to $150 million. The bulk of that or 60% of that will be for Rochelle and Bacchus. The U.K. also includes cost for Centurion well. This is a commitment from 2012 that was delayed into this year. It is an exploration well that's low cost, and we're excited about that.

Our U.S. capital is targeted around $30 million to $40 million. Our committed capital is in the U.S. is very small, so a large part of this amount is discretionary. We'll weight this towards the second of the year and practically will be spent after Rochelle's online and after the strategic process is complete.

With that, I'll turn it over to Carl for an update on our U.K. operations.

Carl D. Grenz

Yes, thank you, Cathy. And I'm speaking to you today from our London office, so good day to everyone on the call. Well, this last quarter for '12 and the early stage of 2013 has certainly been dominated by events on our Rochelle project drilling program. So I will start by bringing you up to date on the current status of play and describe our forward plans to bringing Rochelle online.

So the East Rochelle well has been safely suspended. We have 2 retrievable packers downhole while assess the end potential for mechanical damage to the well conducted stream caused by a severe storm that came through the region late January this year. This storm caused a crater to appear around the 36-inch conductor pipe, and we suspect the storm caused vibration or harmonic resonance in the riser facility that goes from the seabed to the rig floor, and this is a phenomena called, vortex-induced vibration. That actually fluidized the cement and the soils around the top section of the well. However, that root cause is still under investigation. And we're currently studying and analyzing the effect of the crater may have had on the strength of the conductor pipe to ensure that we can reenter and complete this well. There are multiple options identified going forward on the well, and we're working our way through a decision tree to identify the safest and most optimal way forward. The investigation team that's carrying out this analysis includes significant input from the other Rochelle co-venturers. And we're confident that will bring about a satisfactory solution on this East well.

Now there's a desire to return to the East well immediately after we complete and turn on the West well, and we could have a rig available to complete the East production well. But this will be subject to the satisfactory conclusion of the East well analysis and the completion of the planning work necessary to complete this well.

Now the rig, Transocean Prospect was released from the East well location on February 17. And the rig moved to the West well location and started the well on the 21st of February.

Excellent progress has been made on this well, and we've now cemented in the 12.5-inch casing. And we're drilling ahead expeditiously on the 8.5-inch pile hole section. We anticipate the completion of the well and the start of a production from Rochelle around midyear this year.

Meanwhile, all the seabed infrastructure that we've talked about before has all been installed, apart from the [indiscernible] piece pipe section that connects each well to the subsea [indiscernible]. We obviously can't connect those until the wells have been drilled.

Also, the modification work to the Scott Platform, that's a receiving platform for the Rochelle fluids, is just literally a few days away from being completed. Throughout the status on Rochelle right now, I'd like to move now on to Alba and bring you up to date in what's going on there. A major characteristic of the Alba platform is its ability to efficiently handle a large volume of produced water.

Now production from Alba is being impacted right now from produced water-handling issues. We're seeing daily production being reduced from our expected volumes, whilst the operator deals with some relatively complex issues of emulsions forming in the oil water separators. The matter is being dealt with as expeditiously as possible by the operator and with our input. And we expect to see the asset return to full production potential over the course of this year. Already, some of the mitigation factors has been employed on Alba with successful results.

I'll move now on to the Bacchus development. And as Bill has already explained, the results from Bacchus continue above our expectations. And production from the first 2 wells is averaging about 10,000 barrels a day. You may recall that we decided to evaluate reservoir performance before deciding where and when to drill a third producing well. Well, the subsurface evaluation is now being completed and agreed between partner group. And we expect and anticipate the Rowan Gorilla VII, that's the rig that drilled the first 2 wells, will return to the field later this month to commence drilling that third well. The well is called B-1, Bravo-1. And this well will be drilled in the western panel, all panel of the Bacchus field, with production from -- is expected in the third quarter of this year.

So that's been -- covers the main updates from the U.K. business unit. So I'll now hand over to Jim Emme on North American operations.

James J. Emme

Thank you, Carl. In the U.S., our net production for the fourth quarter averaged 10.6 million cubic feet equivalent per day. And for the full year, averaged 14.3 million a day.

We had no drilling activity during the quarter, but we continue to hold our position in all our critical Haynesville and Marcellus acreage, while we monitor U.S. gas prices.

During this fourth quarter, as we previously announced, we completed a strategic exchange of properties with J-W Operating, in which we acquired all their Pennsylvania Marcellus assets in exchange for our interest in 2 of our Haynesville/Cotton Valley projects in Louisiana and East Texas. We really like the scalability of those Pennsylvanian assets, and we like the superior economics of the Marcellus play, but we're also retaining a 50-50 interest in our 3 remaining Haynesville projects with J-W. And those are all held by production with an estimated 80 or more remaining undrilled locations. Back to the Marcellus, that exchange added about 15,500 net acres. For now a total of 31,000 net acres to our interest, and that includes all the existing wells and pipeline infrastructure.

In our key Cameron County Daniel project area, we now have 100% working interest in several producing wells and 3 horizontal wells, which have been drilled and cased and are waiting on completion due to limited takeaway capacity. To address that issue, we executed a gathering agreement with a third party, which is scheduled to provide us additional takeaway capacity of up to 10 million cubic feet a day by year end 2013. And that project is on track. We've got no new drilling requirements on our key leases in Cameron County until late 2014.

Now moving to the Rockies. In Northwest Colorado, our new project there is targeting stacked, Upper Cretaceous sands and carbonates, including the Niobrara and Frontier formations, which have liquids-rich potential. We've received approval of a 23,000-acre federal unit, which we call the Wylie unit, and we expect to drill an initial test well there later this year. We continue to build our position in this play through leasehold acquisition and drill-to-earn type deals.

In our Heath Shale tight oil play in Central Montana, we're maintaining our strategic acreage position there while we continue to watch oil production from nearby offset wells. We'll factor that information into our next operational steps, whether that might be a horizontal reentry of one of our existing pilot wells or some other operation.

We know that the heat is oil productive so now we need to focus on the economic drivers for the play. So as a whole, we're very pleased with where the U.S. portfolio is going. Not only are we preserving existing opportunities, we're adding exciting new opportunities, and yet, those are back-end loaded this year and will come after the Rochelle development and Bacchus drilling as Cathy mentioned.

So with that, I'll turn it back over to Bill.

William L. Transier

Thanks, folks. Let me just remind you of Endeavour's strategy before we move to and make a few comments before we move to your questions.

Endeavour is a company that remains focused on large development activities in the North Sea. Our operational plan has been to develop Bacchus and Rochelle, add scale to assets through acquisitions like Alba, then to use the significant cash flow margins from these assets to repay debt that was incurred as a result of these development activities and then to proceed to grow from our portfolio, whether that be in the U.K. or the U.S.

In 2012, we talked to all of you about the fact that we felt like we were 1 year away from this goal of significant free cash flow. But a few things happened along the way. First, Bacchus was a. success. It was late in getting to success. But it was a success, but the third well was delayed into 2013.

The Alba acquisition was more costly because of decommissioning security that was required. And performance of the asset, albeit good, is under what our real expectations were. And the Rochelle delays that we announced at year end and then just recently with the difficulty in the East well that caused that to be pushed into 2013.

Sure, these have been challenges to the current business model. But let me remind you of a couple of things. The Rochelle development is just a few months away, and commodity prices are good for us to be turning on substantial gas production in the U.K. and in Europe.

The Alba production has been less than expected. But it is still our largest producing asset, and the cash-on-cash returns on this asset had been very strong. We had a good operator in Chevron, and we're working with them to improve the situation that we have that Carl just talked about. Once we work our way through these technical matters, I am confident that we'll have, not only a better asset with more production, but also an asset producing in a very good oil price environment.

Decommissioning costs have increased and will likely go higher in time. That's just the nature of the business. But the U.K. government has taken several initiatives to implement legislation that will allow smaller companies like Endeavour to post decommissioning security on an aftertax basis. This is a very significant positive event that should reduce cost and incent more activity in the North Sea. We expect this to happen during 2013.

Continued development activities at Rochelle and Bacchus are never easy, but we have an experienced operational team that I believe can make it happen. When done, both of these assets will provide meaningful production increases for our company.

And then finally, the debt levels and cost of debt are too high and unsustainable. You've heard me be honest about that going in the past. But we have a plan, which we've talked about today. We now have sufficient liquidity, and we have a commitment to mitigate the situation as soon as possible.

With those summary comments, let me now ask Kyle to open up the lines for questions and answers. Okay, thank you.

Question-and-Answer Session

Operator

[Operator Instructions] We'll take our first question from Welles Fitzpatrick of Johnson Rice.

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

The $22.5 million forward sale, is that 6 months starting on March 1, or is that second half? I know you said second half, but with the filing, I was a little bit turned around.

Catherine L. Stubbs

This is Cathy. Yes, it is starting in March.

William L. Transier

What I was trying to say, Welles, was we were trying to push cash flow from the second half of the year into the first half of the year, but it does start March 1.

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

Okay, perfect. And one more quick one, how long is the Prospect contract? Is there any risk of not being able to take that back, back East after you drill West Rochelle?

William L. Transier

Well, that's not formalized yet in terms of a novation agreement, which is what you would call it from the Prospect is under contract to Nexen to be clear. They're, obviously, our partner in Rochelle and the operator of Scott. We need to do the analysis work on the East Rochelle well and be in a position to go back there. I think the motivation is to try to move that rig back there immediately. But that hadn't been formalized until we get through the analysis work that Carl and his team are working on over there in the U.K..

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

Okay, perfect. And actually if I could sneak one more. The budget for Bacchus, do you guys -- as a non-op, do you participate in that 3D, that Apache's shooting around the Prospect?

William L. Transier

Carl, you want to?

Carl D. Grenz

No, we're not participating in that. It's not directly relevant to the Bacchus development. So no.

Operator

The next question comes from Steve Karpel with Credit Suisse.

Steven Karpel - Crédit Suisse AG, Research Division

First on the NPP, and maybe it's NPP sales forward in general. So in aggregate of $130 million, can you talk about how you came up with that size, 1 and that's how much you needed? As you look at the delay time for Rochelle and the incremental costs and then maybe the second part of that is how much in practicality combination forward sales/NPP could you do in total or in aggregate if you -- at some -- it may be a, if you want to do more; b, get something now, or b is you want to do more in the future?

William L. Transier

I'll let Cathy address it because she is the creative party that made this all happen, but what we really tried to do was take the forward sale, which is -- with an established purchaser of our, of some of our activity and then layer on that NPP behind that. That's why Cathy talked about the repayment process. And in terms of the size, we are in this business. You always try to capture as big a piece as you can to provide the liquidity and try to give comfort to guys like yourselves that we have all the staying power we need to work through Rochelle and obviously, the strategic review process. So there wasn't any -- I will say this, there wasn't any real math to an exact number. We worked with some of our existing investors, who are obviously, vested in us, preserving the value of these assets and providing a message to the marketplace that we have enough liquidity to get through this. And we just, we came up with this amount. And we, obviously, we're trying to get this done in advance of this call. So the work that Cathy and team have been doing to work through this is, has been put in place. From my perspective, this is a relatively modest amount of our production over the next 2 years that is carved out for these forward sales and NPPs. To answer your question, could we do more? I think the obvious answer is yes. Do we have any intention to do that right now or need to? We don't think we do. So I've said a lot more than I should, because Cathy is sitting here anxious to add to the mix here so.

Catherine L. Stubbs

No. I think that was a good summary.

William L. Transier

That response, Steven?

Steven Karpel - Crédit Suisse AG, Research Division

It did and I guess how much total production. It looks like it's about 1,100 barrels a day if it's exactly 200,000. It was a little bit more for the forward, how much production associated with the NPP?

William L. Transier

Well, because it's dollar denominated, it's not a specific volume.

Steven Karpel - Crédit Suisse AG, Research Division

Maybe I should have asked at current Brent prices is probably I should have asked that?

Catherine L. Stubbs

Yes, and so it is a monetary kind of repay and it will have target repay in dollars. And as I mentioned, so we'll repay the whole amount back over 2 years with a low cost around $3.6 million payback per quarter for the first 6 quarters and the balance over the last 2.

William L. Transier

So if you use $100 oil, Steven, there, you got $3.6 million divided by $100 of oil per day. So you can get the math.

Steven Karpel - Crédit Suisse AG, Research Division

I want to make sure that was about right.

William L. Transier

That's through the first 6 quarters, and then the remainder of it will get paid at those last 2 quarters at the end. We fully expect to be well past that by that time.

Steven Karpel - Crédit Suisse AG, Research Division

And just 3 what I think are quick ones. One, I think I missed the number how much PRT you paid in the quarter, one. Two was just looking at the slide deck, a little more clarity on that ARO number. And then three, what was year-end PV10?

William L. Transier

The PV10 will be disclosed next week, when we file our 10-K, with the reserve numbers that come out then. It's not significantly different than last year, but I hate to quote any numbers because we're still working on those disclosures as we speak. Cathy, can you speak to the other 2?

Catherine L. Stubbs

Yes, the PRT was around $32 million for the year, $32 million.

William L. Transier

The quarter, I guess, would have been about 1/3 of that number because of the Alba production being heavily weighted toward that.

Catherine L. Stubbs

Yes, back-end loaded as we increased our Alba percentage in May. ARO, you asked about the slide on Page 8, and we have about $140 million that was increased to ARO. And again, that was for our increase in the Alba percentage and setting that liability up and the corresponding -- the noncash entry that goes to your PP&E and your obligation, as well as an increase in timing on some of our other assets in the U.K.

Steven Karpel - Crédit Suisse AG, Research Division

All right. I just want to make sure, the full amount is noncash there?

Catherine L. Stubbs

It is.

Operator

Our next question comes from Neal Dingmann with SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Maybe, Bill, first for you, I'm just wondering, the part of issue you had with the cement around that Rochelle East, I'm just wondering now as you're going forward on drilling Rochelle West, anything that you all are doing different or just kind of comments about -- to have a bit more certainty on -- that that does come online around the 120-day mark or so.

William L. Transier

I'm going to let Carl respond to this because he's intimately involved in it, obviously. But we did take some mitigating steps. We have designed the well to handle this -- the beginning in the East Rochelle and then obviously had this happen. But I'll let Carl speak to some of the things we did on West to even provide more insurance to go forward.

Carl D. Grenz

Neal, it's is Carl here. We did take some learnings from the East well and employed them on the West, as Bill has indicated. The series of steps we've taken, some of them are more to do with monitoring, so we can actually see what is happening with the riser assembly as it responds to weather, to wave motion and so on. So we can have a better real-time picture of what's actually going on in terms of the movements of that whole structure. That's one of the significant pieces that we've done on this. We've actually cemented the conductor in now. It's a very substantial piece of metal. Just like in the East, it's a 36-inch conductor with 2-inch wall thickness. We've modified slightly the cementing program to put that in place based on some inputs from learnings elsewhere, and we've modified the riser assembly, so it's non-buoyant. And this is only pretext -- this is a vortex-induced vibration scenario that caused all this. So it slimmed down the riser assembly, so it's not as prone to resonance. We've reduced the height of the whole system by not installing the well head at this point. We don't need to till further on in the program, so the BLP stack is much closer to the seabed, and also [indiscernible]. So those are the main things that we've done differently on this well to stave off any potential. Of course, we're now also in a much better weather window as we're emerging to the spring now in the North Sea. So we shouldn't see the same loading strong storm activity that we're seeing on the East anyway. So all of those things together give us a fairly great confidence that we won't head into the same situation on this West well.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

And Carl, will you be, I guess, in conjunction with that, looking at going back to Rochelle East, or is that something you've kind of -- you've tabled for a while?

Carl D. Grenz

Well, we do intend to go back to Rochelle East and complete this well following the analysis, and as I've said earlier, it's our intention to go back. Since we've completed this well -- this analysis work and we completely understand the mechanism of what's caused this situation and understand fully that there's sufficient strength left in its conductor casing to allow us to reenter the well. So we'll see how that progresses over the following weeks. It does take a while to complete this analysis. We're not going to rush into it. We're going to do it responsibly and safely in conjunction with our joint venture partners.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Very good. And then last one, if I could. Cathy, did you recall -- I know Bill had mentioned you could add a little bit more debt if needed or extend, actually bump that up a little bit, but as you sit today, just remind me what's the current liquidity.

Catherine L. Stubbs

So our current cash position...

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

After this current deal you just did, obviously, pre sort of CapEx remainder this year, I'm just wondering kind of what's total cash -- or I guess total net debt, I guess, is the best way to say it.

William L. Transier

Well, I think that we probably have -- with the facility and current cash, you're probably talking close to $200 million. And then whatever the debt is now, remember that -- the reason I think Cathy was hesitating, the forward sale and the monetary production payment are not really debt, so to speak.

Catherine L. Stubbs

That's right.

William L. Transier

I don't think we were trying to hesitate from your question, but we want to make it clear what these are, and I view the forward sale as locking in the next 6 months of that amount of production. And we did that -- to Cathy's benefit, we did that ahead of this most recent adjustment in Brent crude oil prices, so we got out ahead of that. We can't, for competitive reasons and stuff, we can't talk in too much detail about it, but the monetary production payment is -- it's just a strip out of the income stream going forward. And the way that we manage this is to kind of layer on at the back end of the forward sale and work our way through the end of next year. And we view that as very positive in terms of how to manage our liquidity position between now and getting Rochelle turned on and now and getting through this strategic review process, where we end up on that.

Operator

Our next question comes from Steve Berman of Canaccord.

Stephen F. Berman - Canaccord Genuity, Research Division

A couple of North Sea questions. At East Rochelle, is there any recourse to recover any monies due to the cement job or any kind of insurance you might have? That's first. And also, if it's determined that you have to redrill that well, is that in the budget? Or given the fact that the 2 wells are kind of redundant if you had to redrill it, would you put that off, just bring West on and then decide what you want to do as far as redrilling East?

William L. Transier

Well, I'll get out ahead of Carl on this. First of all, with respect to insurance recoveries and stuff, all I can say at this point is that we are looking into it. As you might expect, insurance companies always start out on one foot and stuff, but we are working on that. That will unfold over a fairly long period of time, I would guess, as we go down the road. But your question about alternatives, I think that Carl would tell you that the analysis gets done, then we figure out what we do in terms of going forward. The budget that we've talked about in the past has been really to get East and West Rochelle turned on. Obviously, there's some added costs if you have to go back and finish the completion on East Rochelle. But it's truly an option for us to turn on West Rochelle, get that production because as we've told you in the past, each of the 2 wells should provide our capacity limits over the Scott Platform. And if we wanted to produce out of West for a while and then come back and put East on, that is an alternative that Carl and the team are looking at. But don't lock us into any of those yet until we kind of figure out everything about that. Right now, we're focused on drilling West Rochelle. It's going along well. As Carl said, it's in a better weather window. We're just going to stay focused on doing that and getting production turned on, and then we'll decide where we go with East Rochelle. But finally, to your question, obviously, if that well -- we had to drill a new well at East, that is not really in our budget numbers at this point in time, and we'd have to come back and update you on that then.

Stephen F. Berman - Canaccord Genuity, Research Division

Let me ask a little differently. Bill, in the past, I think you initially talked about maybe $100 million, $110 million kind of CapEx budget for 2013. Now these numbers are bigger. I'm just wondering how much of that increase at this stage is related to Rochelle, the 2 wells combined.

William L. Transier

I think it's related to 2 things in total. One, Rochelle and two, the second Bacchus well that, when we talked about it before, really, wasn't in this year's budget. So the combination of those, as Cathy talked about, represents 60-plus percent of that capital budget we talked about. The other big piece of the capital budget -- or the other 2 pieces are really Alba, which is about -- based upon the forward plans and in-fill drilling, Alba is probably $30 million, plus or minus. That's kind of consistent with what our thoughts have always been. And then this Centurion well, which is -- our exposure on that is about $10 million to $12 million. That, as we've said before, was a commitment in 2012. It got pushed off into 2013 because of the rigs, the service industry over there and stuff. We have to deal with that this year. We're excited about it, but if it wasn't a commitment well, we'd probably push it off into some other time. So that makes up that capital budget that we're talking about.

Carl D. Grenz

Steve, can I just to turn back to what Bill has -- I just want to build on what Bill said on the Rochelle well there. You asked a question about redrilling the East well. It's, of course, one of the outcomes of this, but we are not done with the current East well by any stretch of the imagination. If the analysis comes out that we have lost mechanical strength on that well, there are certain technologies that we can apply that have been used elsewhere to strengthen up that conductor casing to allow us to reenter that well. So we're a long way from saying that that well is done. The other point I want to make is on turning on the West Rochelle well, as we said in the past, each well from Rochelle has the capacity to deliver the full production nomination, including the high-level reasonable Endeavour's volumes, on a daily basis on this development. So we are looking for the 2 wells, obviously, to give us redundancy in this field going forward. And we will need the second well -- we will need the East well to effectively drain this whole reservoir in the fullness of time. So I just wanted to make that clear that the West can deliver the full nomination of Rochelle, and we're certainly not done yet with this current well on the East.

Stephen F. Berman - Canaccord Genuity, Research Division

At Alba, what are the water handling issue's costing in terms of current production? Bill, I thought I heard you say in your prepared remarks that current production was running about what it was in Q4, so I'm just wondering how -- what kind of impact Alba's having on those numbers.

William L. Transier

I think on a day-to-day basis, Steve, you're talking what we think normal production levels should be, impacting us to the negative of a 1,000 to maybe 1,500 or even more barrels per day. So our view is that the reservoir, on a gross basis, should be producing 25,000 to 29,000 BOEs a day, and we've been in the 20,000 to 25,000 BOEs a day, depending day in, day out. Most of the time, at the lower end of that range.

Philip L. Dodge - Tuohy Brothers Investment Research, Inc.

Moving to Bacchus, what's your expectations for rate on that third well? You might have talked about it in the past, but what are you thinking now?

Carl D. Grenz

Well, we think the third well will be similar to the second well, Steve. We've said before that Alba is approaching high pressure, high temperature. And the second well is certainly constrained on a temperature limitation now. It's capable, from a full-flowing potential, to go way, way higher than it currently is. So it's producing around 7,000 barrels a day, that second well. We have expected the third well to be somewhere in the same sort of order of production.

Stephen F. Berman - Canaccord Genuity, Research Division

That's gross, okay. And last one for me. Serica, I'm not sure how to pronounce, announced a tender process for Columbus today, and you have a piece of that. What are your thoughts on that as far as participating or talking about commencing field development in the second half of this year? Is there any -- are you planning on participating? Is there anything in the budget for that? Can you talk briefly about Columbus for us?

William L. Transier

Steve, this is Bill, and I won't speak for Carl. It is positive news that Serica went out with that announcement that there is basically a preliminary approval of the deck for the Field Development Plan. But you saw their release. It dealt with kind of simultaneous development of a Bridge Linked Platform by BG. We've always talked about it flowing into the Loman field, which is operated by them. I think this is all positive in terms of the underlying value that Columbus represents, but I would see it highly unlikely that we would be spending any capital of any substance on Columbus this year. It just takes too long to get that stuff going, but it sure is going to firm up the valuation for Columbus for us as we go down the road.

Carl D. Grenz

As Bill said there, Steve, we expect it to be sanctioning the Columbus project this year. We've got some monies in the budget for study work, the pre-engineering work, our participation in that. There won't be any significant capital outlay on this project until much later on in 2014.

Operator

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

Cathy, it looks like you're off to a great start in your role. These forward sale agreements definitely look real smart. I'd like to take a little bit of a closer look at liquidity, though. At the end of the year, $59 million of cash, and you just took in $130 million in the last couple of days here through these forward sales. Was just hoping you could map out, really, the cash inflows/outflows between now and when Rochelle's brought online to give us a really good sense of comfort of the level of cushion you have. A couple components that I'm unclear on, really, just the additional fees and payments of the $130 million in the forward sales, you gave some sense to that. And you had $9.46 million in fees, letter of credit fees, in the fourth quarter. Just wondering what that looks like going forward. And then also just the CapEx allocation in the first half of this year, just to go and split that out between quarters will be real helpful.

William L. Transier

Cathy, go ahead. I mean, you've asked a lot of detail here that probably is difficult to give you, but I think the cash position today sits at kind of north of $100 million without this most recent transaction that we talked about yesterday. We've obviously had liftings and cash flow coming in for the first quarter of the year. At this point, I've tried to indicate what that should look like in terms of the production steadiness with the fourth quarter to kind of give you an indication of that. Obviously, the spin for us with both Rochelle, we're obviously drilling the West well, and the Bacchus well will start at the end of this month, according to the most recent plans. So 60-plus percent of that capital budget will probably be spent between now and the first half of the year. If Rochelle stays on track, which we expect it to do, and you get Bacchus, it will spill over between the second and the third quarter. Now you've asked for specifics, but it's hard to do that. The way I looked at what we were doing on the forward sale and this most recent monetary production payment and then pushing out any requirements that would put pressure on us because of the timing of Rochelle and when Cathy would put in a revolver to take out some of these LC facilities in a more cost-efficient manner, all that created liquidity for this year. And I view these most recent transactions as cushion on top of what probably would have been a tight situation for us throughout the course of the year. So we felt like it would have been tight and we would have been managing very close to kind of the limits of our cash without these most recent transactions. So I think these layer on and provide cushion for us, for sure, through the startup of Rochelle. And obviously, we have the strategic review process going on, which, I think, will help to delever the balance sheet going forward. So that wasn't specific. Cathy may talk to it, but I think that that's all we can really talk about at this point without putting detailed forecast in front of the group here.

Catherine L. Stubbs

No. That's a good picture. I agree with that. Where we sit with cash plus the additional liquidity that we just brought in is balanced against our current production, plus we talked to Alba production. Rochelle timing, again, we've said that this West well will bring on at the same volumes that we anticipated. It's just pushed out, and so timing is delayed there. And capital expenditure, you asked about timing. We'll probably be -- we're spinning in the third well -- the West well, sorry, now, and the Bacchus third well will come soon thereafter as well. We've designed these repays of the production payments to be light in this year, so principal payment or payments out to repay will be light this year to balance, again, the inflows coming in from our production and the outflows for CapEx during this year. I hope that gives you a little bit of a framework.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Yes, it seems like you guys have got enough margin for error there. I'll follow up with you on some of the details, don't want to bore everyone on that. If I could just ask on Rochelle real quick, you noted in the press release that the modifications to the Scott Platform are almost complete, and I just want to make sure I'm thinking about the initial production range in Rochelle properly and to be clear on how much production Scott Platform could handle for you initially and then as you go out maybe a quarter or 2.

William L. Transier

Well, the capacity that we have contracted for across the Scott Platform is 100 million a day, but as we've talked about in the past, it depends on uptime rates, and you know what those are in the U.K.. Our expectations are normal uptime rates are in the kind of 85% range, and we expect the West well to be able to push that across the Scott Platform at whatever limits were allowed, up to 100 million a day on a day-in, day-out basis once we get the well turned on. And it won't take very long. I think Carl would tell you it won't take very long to get up to the capacity limits from the well once we get it turned on.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay, so 100 million a day. 85% of that is a good way for us to model this going forward?

William L. Transier

Carl, you want to say that?

Carl D. Grenz

Yes, I think there will be a run for a period initially. It should be fairly short one. But I think the 85% efficiency factor is currently what we're seeing on the Scott facility, so that will be the right level to apply to the production. And as Bill said, we're expecting to see up to 100 million a day capacity once we got through the initial run through period.

Operator

Our next question comes from Hassan Ahmad with Imperial Capital.

Hassan Jawed Ahmad - Imperial Capital, LLC, Research Division

Just going through this -- I was looking at the press release, and basically, it says that the VPP that you just did, the $108 million or so, subject to regulatory approval, what's the timing on that in the U.K.?

William L. Transier

Well, first of all, it's not a VPP. I keep talking over Cathy. Cathy, you go ahead.

Catherine L. Stubbs

Yes, so it's -- we went through this kind of with our forward sale, but it's subject to kind of normal regulatory approval, and we expect this to be short. We can't really speak to the exact timing of that.

Hassan Jawed Ahmad - Imperial Capital, LLC, Research Division

Okay. And then just to be clear on East Rochelle, within your CapEx budget of $140 million to $150 million, does that assume you'd come back and complete the well, or does it assume anything beyond the completion of that well, like perhaps, the inspector comes back with a different conclusion and you have to do a new well? What is factored into that $140 million to $150 million for U.K. spend?

Catherine L. Stubbs

I'll address that. Again, as Bill mentioned, we don't have a full well in there, but we do have kind of a range given to you to go back into the East and look at that and do some additional there, but it's not a full well that's in there. We do have a full well for the West, and we do have the Bacchus well, third well, that's in that budget.

William L. Transier

We'll just have to update you when we find out the results of the work on the East Rochelle well, but right now, it's as Cathy said.

Hassan Jawed Ahmad - Imperial Capital, LLC, Research Division

So presumably, if the inspector comes back with something other than what you think is, let's say, the base case, then the CapEx could theoretically tick upward if you had to do a new well, for instance, in East Rochelle?

William L. Transier

Yes, I think that you're exactly right, not trying to hide from that. Obviously, that's not what we wanted to see, but you've got additional costs over and above what we expected to spend on the East well by some amount. I don't know what that is because we don't know what our reentry game plan will be. If you have to drill another well, you'd probably look in that $70 million -- $60 million to $70 million well gross, and we have our relative percentage of that. And that kind of gives you the bid-ask spread, I think, if you want to think about it. And then the question will be when you would time those expenditures out. So we talked earlier from one of the questions, you get Rochelle turned on, do you go right back to East. That's our intention. If we have to do something different, maybe you time it differently. There's lot of things to consider as we go forward, and I just don't want to lock you into anything particular, but I feel comfortable, which I think you should feel, I feel comfortable that we have the liquidity to move forward to get Rochelle turned on, fully implemented over the course of this year.

Hassan Jawed Ahmad - Imperial Capital, LLC, Research Division

Okay. And then last question on the revolver and the reimbursement facility, good for you guys, extended that out to June of '14, it looks like. But I guess what I'm trying to figure out is on the revolver, is that a -- it looks like it got reduced down to $100 million. Is that -- do you have to pay the $15 million down today, or is that just going to roll off when it matures essentially?

Catherine L. Stubbs

Yes, that $15 million is still due in October of this year.

Hassan Jawed Ahmad - Imperial Capital, LLC, Research Division

Okay. So it's going to go from $115 million to $100 million in October. At that point, you'd have to fund the $15 million paydown in October. Am I correct in thinking that?

Catherine L. Stubbs

Right, our plans are to kind of put in a borrowing base, reserve base lending facility if we get Rochelle turned on, and we believe that's the kind of the most optimal time to do that. And that likely may be wrapped into that facility and pushed out to a later date.

William L. Transier

I think the expectation should be that we'll have Rochelle turned on and Cathy will have the new revolver in place long before September.

Operator

Our next question comes from Rehan Rashid with FBR Capital Markets.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Real quick, could you maybe break down the 2P resource potential from the different assets? And then second question, on NOLs, I mean, the $500 million and $379 million to combine, $800 million and change. Please confirm that. And then should we then expect you to be a cash taxpayer, any portion of this, this year or just going to be until you bleed out all these NOLs?

William L. Transier

I'll let Cathy respond to some of these, but the 2P reserves, the disclosure we made in our press release is the extent to which we'll talk about the 2P reserve. So we generally don't talk about 2P reserves by particular asset. We will make some further disclosures in our 10-K, but the SEC kind of keeps us restricted to talk about 1P reserves. So we've put it there. Obviously, most of the 2P reserves are -- or almost all of our 2P reserves are in the U.K. North Sea, so they'd be relative to the 4 big assets that we've talked about in the past.

Catherine L. Stubbs

The second question, I'll talk to that. The U.K. net operating loss and the $500 million shields us from corporate tax rate. The U.K. tax rate we speak is 62%, but it's really 2-part, a corporate tax rate of 30% and then a supplemental on top of 32%. So those loss figures apply to each of those kind of correspondent. We have $500 million on the corporate tax that's shielded and then the $379 million on the supplemental. The primary difference between those 2 is the interest expense and what is not nondeductible or deductible for U.K. tax purposes.

Rehan Rashid - FBR Capital Markets & Co., Research Division

I got it, okay. But going back to the 2P, I mean, you had reasonable disclosure at the analyst meeting last year outside of Alba. Any reason that will be different today?

William L. Transier

Well, no, I think that the 2P reserves, you see the gross numbers up there. I think the 2P numbers are kind of in that same range. And there wasn't any significant -- I'm sitting here trying to think through those numbers, but let's see what we can do going forward to try to help you with that. I'm not really prepared to kind of say that other than the total right now in the press release that we've got. But all the 2Ps is necessarily going to be with Alba, with Bacchus and Rochelle going forward. I mean, that's where the bulk of it is.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Got it. That's fair. I just wanted to confirm. And then the $30 million on Alba in general is a little bit lower than what I was thinking from an annual standpoint of $40 million to $50 million. Is there something that's going to defer into next year, or is $30 million a year a good run rate for maintenance infill CapEx?

William L. Transier

Well, it's a good run rate for this year because that's kind of the budget, and the expectation is we'll drill 2 to 4 of these infill wells. I think it also depends on whether you drill them off the platform or you try to do a satellite well. Carl's focus had been to try to get this from the platform because they're cheaper wells and they turn on quicker and stuff like that. He's done a great job with Chevron in trying to move forward some of that infill drilling because that adds production for us going down the road. But at least for this year, that's kind of the number we're talking about with Chevron, the operator.

Rehan Rashid - FBR Capital Markets & Co., Research Division

I'm sorry, last one. So Alba, the production at the time of purchase was about net 7,500 barrels a day. After you're done doing the remedial work, is that kind of generally we should expect? Or is your expectation will be to go back to that level, something lower, something higher?

William L. Transier

Well, I'd correct you. When we bought Alba, I think the current production was about 6,000 barrels a day. We immediately drilled an infill well, and that number jumped up to close to 8,000 for a temporary period, and then we started having some of these water handling issues that Carl talked about. Earlier in my comments or in response to one of the questions that came up, we said kind of the normality of Alba, with the wells that we have on, we think that Alba should flow, on a gross basis, between 25,000 and kind of 29,000 or 30,000 BOEs a day. It has been flowing at kind of 20,000 to 25,000 BOEs a day, day in day out and, as I said earlier, kind of at the lower end of that range. So you can take our percentage and kind of do that. I think Carl's hope is that with the good work that Chevron's doing and our team involvement on this, that we will get back to that normality sometime as the course of the year unfolds.

Operator

Our next question comes from Ravi Kamath with Global Hunter Securities.

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

A couple of questions. One, when would you expect to start paying the 62% corporate tax? Has that been pushed back to, like, '16 or just any color on that?

William L. Transier

Well, you can run your own models, but I think from my perspective, we're not going to pay any corporate tax this year. The current tax that you see is the PRT, which has to be paid, obviously. I think that you can run out the models. We're spending more capital, which you get to deduct currently, and stuff. I think it's well into '14, probably into '15 and beyond before you can expect to pay any corporate tax going forward, and we'll do whatever we can in terms of how we handle the tax rate going down the road. That's the one advantage of the U.K. North Sea is that they let you deduct currently everything that you're investing in the North Sea, and obviously, we've been investing heavily over the last couple of years or so.

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

Okay, so sometime in 2015, got it. And then secondly, on the new production payment, is that related to Alba and Bacchus, or is there something related to Rochelle? What fields are those production against?

William L. Transier

It's really to a combination of our oil-producing assets, Alba and Bacchus specifically.

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

Got it. And then is there -- can you provide sort of what percentage of those fields' production you might be selling?

William L. Transier

My only comment earlier was that it's a fairly modest percentage, the way that Cathy designed the repayment. Remember, it's in monetary terms, so obviously, it ties to what commodity prices are going forward. There is some view of that. The first 6 quarters, as she said, of that deal, it's about $3.6 million a quarter, so you can back into the math to some sort of volume based upon whatever your expectations are of commodity prices.

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

Got it. And one final question. On the balance sheet, it looks like accrued expenses and other went up from $23.7 million as of September 30 up to $90.1 million at year end. Just wondering what's in there and how should we be thinking about working capital as a source or use of cash in 2013.

Catherine L. Stubbs

Yes, this is Cathy. I'll speak to that. The bulk of that is PRT, the payments that we'll make for the last half of 2012 and then the noncash entry that I mentioned on asset retirement obligation. So a lot of that piece is noncash.

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

Okay, got it. And then just finally, on PRT, is the expectation for 2013 payment, is that $80 million to $90 million, is that a good sort of range?

Catherine L. Stubbs

That kind of depends on Alba production and then the pricing environment that you have, but I would say we expect it to be about half that, actually.

William L. Transier

Half of that.

Catherine L. Stubbs

Yes.

Operator

We'll take our final question from Amy Stepnowski from the Hartford.

Amy Stepnowski

I'm wondering, in your press release, when you announced that Rochelle was delayed, you also noted that OpEx was higher than you had been expecting. When you look at the fourth quarter, it's actually pretty much in line with the third quarter. I was just wondering from our perspective for modeling, should we think about this as a reasonable run rate, or are there some other issues that we should be thinking about?

Catherine L. Stubbs

This is Cathy. I think that our fourth quarter is sort of a reasonable run rate. It is up over prior year, as I mentioned, and that's because we do have a little bit higher cost on the oil in the U.K., but we do believe that's in line kind of with the practice there. So I think that that's a good kind of rate for your modeling going forward.

Amy Stepnowski

Okay. And just one other quick one. I'm wondering, with regards to lifting and production versus actual sales, not looking for anything too specific, but has there been any significant changes in the first quarter as you look ahead that should make us think that you're going to get these sort of onetime benefits as we have in the fourth quarter, where you had production from the third quarter that leaked into sales for the fourth quarter?

Catherine L. Stubbs

Well, as I mentioned, we record kind of our revenues based upon when the liftings occur. And in the fourth quarter, we had 3 liftings on Alba and we typically have around 2 -- about every 6 weeks or so on Alba. So we'll probably go back to that normal kind of timing.

Amy Stepnowski

Okay. And then just finally, just to make sure there's no confusion, on Bacchus, with the third well, as they're bringing that online, will that require you to limit production from the other 2 wells?

William L. Transier

The answer to that is no.

Carl D. Grenz

We're not expecting to see any backout from the other 2 wells. The whole system's been designed for a 3-well development scenario, and there's certainly capacity on the receiving platform for the full volumes we've talked about.

K. Darcey Matthews

Kyle, thank you. I think we're going to wrap up the call today. Again, to those of you who we didn't get to, please feel free to give us a call. We'll be happy to answer your questions directly. We thank you very much for your interest in Endeavour and look forward to speaking with you all soon.

Operator

And this does conclude today's conference call. Thank you all for your participation.

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

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

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

Source: Endeavour International Management Discusses Q4 2012 Results - Earnings Call Transcript
This Transcript
All Transcripts