Endeavour International Management Discusses Q3 2012 Results - Earnings Call Transcript

Nov. 1.12 | About: Endeavour International (END)

Endeavour International (NYSE:END)

Q3 2012 Earnings Call

November 01, 2012 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

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

Analysts

Irene O. Haas - Wunderlich Securities Inc., Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

Amy Stepnowski

Steven Karpel - Crédit Suisse AG, Research Division

Operator

Good day, and welcome to this Endeavour International Corporation's Third Quarter 2012 Earnings Conference Call and Webcast. Today's conference is being recorded. At this time, for opening remarks and introductions, I would now like to turn the call over to Ms. Darcey Matthews, Director of Investor Relations. Please go ahead, ma'am.

K. Darcey Matthews

Great, thank you, Jennifer. Good morning, good afternoon, everyone, and thank you for joining us today for Endeavour's 2012 Third Quarter Earnings Conference Call. Joining us on the call, we have Bill Transier, our Chief Executive Officer; Carl Grenz, our Executive Vice President for International Operations; and Jim Emme, our Executive Vice President for North American Operations.

Before we begin, let me remind everyone that our comments today reflect 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 10-K and our more recent 10-Q. The third quarter 10-Q will be filed sometime early next week.

And now for some opening comments, I'd like to turn the call over to Bill.

William L. Transier

Good morning, everyone. I appreciate you joining us. Let me kind of give you an outline of what we'd like to talk with you about today before your questions and our responses to that. Well, I'll go through, first of all, a quick highlight of what we have been doing this quarter, a financial review that I will cover. And with the help of the financial pack that came out to you overnight, that should help you understand our comments better from where we've been in the past. Then I'll let Carl give you an operational update on the U.K., and Jim will follow with an operations comments on the U.S. Then I will come back at the conclusion of that and give you an update on the status of the MacCulloch and Nicol acquisitions, and I will address the resignation of our Chief Financial Officer before I close with a few comments and then allow your questions and comments.

Just regarding the highlights for the quarter. The biggest thing for us this quarter was the significant increase in production. You'll see in the slide pack that production was just above 11,000 BOEs per day.

We were also awarded through the competitive licensing round over in the U.K., 7 licenses on 10 offshore blocks. The licenses are traditional licenses, which mean that we have 4 years to complete the work programs, and we basically bid work programs that allows us to have a fairly nominal amount of capital that's involved for the next couple of years until we decide that there's other things that we want to do on the block. The blocks are important to us because they protect our core areas in the Central North Sea.

Our focus has and continues to be the Rochelle development, and you'll hear from Carl about several important milestones that we achieved along the way, including the installation of subsea pipelines and umbilicals, which are complete; the drilling to kind of the final casing point on our first development well; and the decision we made in a very tight service sector to adjust our development operations to preserve the option for first production at Rochelle early in 2013.

We made a transaction in the U.S. through an exchange, that you'll hear more about from Jim Emme, with our partner J-W Operating to give us expanded working interest, operator status and control of the upstream and midstream business there, an area that we're excited about going forward.

And then, as I said, our acquisition with ConocoPhillips for MacCulloch and Nicol is progressing. Like I said, I will give you some more details on that kind of after as we get through the formal part of this presentation.

Let me first go to the financial review. And like I said, Darcey, for the first time, put out a slide pack that should help you with this. So if you go to Page 3 on the slide pack, you can see that our sales volume for the quarter were up 370% comparatively and 215% for the 9 months. This is directly attributable to bringing on Bacchus in the first part of the year, the 2 development wells that we had there, and the acquisition of our additional interest in the Alba Field. Frankly, the increase in production was muted by no sales from Bittern and Enoch because both those fields were shut in during the period and various maintenance issues at Alba that affected the production capability there.

This is just something we have to deal with in the North Sea. And I just remind all of you that the U.K. North Sea is a very mature area. The infrastructure requires shut-ins and maintenance along the way. These matters, many times, are out of our control and maybe not known to us until they are upon us. Our job is to advise you about these matters as best we can in the future so that you have a good view of where we're going as a company.

But importantly, as you look at that slide on Page 3, we moved from a fairly low level of production in the second quarter 2011 of approximately 3,000 BOEs per day, of which 81% of that was U.S. natural gas, to 11,000 BOEs a day this quarter, of which 80% of that today is now U.K. oil. This is a big change for our company and, frankly, it's a big change for any company.

Commodity prices during the quarter remained strong. Brent crude oil prices averaged just below $110 of BOE, slightly higher than the second quarter where it was $108 of BOE. Everybody knows about Henry Hub gas prices, which averaged $2.88 in Mcf for the quarter, up from $2.29 in Mcf for the second quarter. I think importantly for us and the reason again for our focus on Rochelle. NGP pricing, natural gas pricing in Europe, today, is running at about $10.80 an MMBtu. We've seen prices move up over the last couple of months from the mid-$9 in MMBtu to their current levels. We're encouraged about the strength in natural gas prices in Europe, and we're anxious to get the Rochelle production on so that we can lock some of this in for ourselves going forward.

When you take the production and the commodity prices and the change in the mix of our production to liquids, you'll see on Page 7 that our revenues grew from $83 million for the quarter versus only $10 million for the quarter in the same quarter last year. So for the 9 months, our revenues are $121 million compared to $44 million last year.

I'll direct you to Page 8. We put on that page the metrics on a BOE basis. You can see that the metrics are obviously improving because of increasing production. I'll talk about a couple of items on here. In operating expenses, they're obviously up due to increased production, but there was a onetime nonrecurring adjustment, including operating expenses, of about $9.7 million. This represented the allocation of purchase price to crude oil inventory that we bought in the acquisition of the additional interest in Alba. And that had to flow through cost of sales or actually operating expense. If you take the impact of that onetime adjustment, you would reduce our cost per BOE on operating cost by about $7 of BOE, so just put that in perspective as you look forward for us going down the road.

DD&A expense is obviously up because of increased volumes in the U.K. It's also increasing somewhat by the increasing expense for our asset retirement obligation due to a higher decommissioning cost, and that really relates to the acquisition that we picked up with Alba.

Interest expense is higher than the third quarter 2011 due to the high yield debt offering and the signed revolving credit agreement. That's obviously partially offset by the repayment of the signed credit facility and higher capitalized interest. I'll just say this. We talked about it many times with all of you. This is where our focus will be in 2013. Once we get all of our production on, we will focus on reducing debt and cost of capital going forward.

Our G&A expenses, we've done a good job of kind of maintaining flat G&A expenses quarter-to-quarter comparisons. If you look at the 9 months comparison, the increase there is really related to noncash long-term incentive pay. We have, over the last couple of years, reallocated the way that we do compensate it more to long-term incentive pay. That's driven by the relative value of our equity. The accounting calculations are hard to explain, but I think it's important for everybody on the call to know that the management is focused on the performance of our equity going down the road.

We'll now move you to Page 9. You'll see that obviously EBITDA moved dramatically to almost $52 million for the quarter compared to almost nothing for the comparable quarter in 2011. That obviously impacts the 9 months numbers to $65 million for 9 months compared to $14 million last year in the comparative period.

There were some special items in here that you should stay focused on. We had an $11.4 million impairment on our U.S. full cost pool related to the continued reduction in the average pricing and U.S. natural gas prices the way that the SEC calculation requires us to do the ceiling test. That should end the turnaround. Obviously, there's been some improvement in natural gas prices, but you have to work through the averages to get there overtime.

Also included in the income tax line is a special item of $8.4 million, which is a charge to deferred taxes. That relates to a decrease in the income tax benefit associated with decommissioning costs from 62% to 50%, which went into effect this quarter. We all knew that was coming. We've talked about it with you. It just had to be reflected in this quarter's numbers going forward. So that's an $8.4 million special item in income tax.

You'll see Letter of Credit fees on here. I just point that out because they're high, but they were necessary for us to get the Alba transaction done. It also represents, as I said a minute ago, an opportunity in 2013 to make substantial reductions in that cost for ourselves and let the benefits of that flow through to our equity holders going forward.

In regard to subsequent events, we -- after the end of the quarter, we completed 2 small financings. We expanded our revolver that was related to the calculation of the ability of our assets to command that revolver, and we drew $15 million against that. We still have $10 million undrawn. That revolver has the potential to expand again once you close on the MacCulloch transaction, but we'll talk about that when the time comes.

We also took advantage of what everybody knows is a very robust, high yield debt market by doing a tack on to our 12% senior notes. We sold those notes through Credit Suisse at 109% and used part of those proceeds to repay our 12% senior subordinated note. We did that on purpose because the market was robust. Frankly, if we could have done more and taken out some of our other higher cost debt, we would have. But we have to take some baby steps to put ourselves in a position to be able to put our new asset-based lending facility in place next year to replace the revolving credit facility that you see later on in our slide pack. The increasing cash is what I consider to be good prudence for ourself until we get the Rochelle production on, as we'll talk about more going through this.

Hopefully, the slide pack will help you. I'm going to turn it over to now to Carl and Jim to give you a little bit of update on operations. Then I'll come back and talk about the things I promised to talk about when they get done. Carl?

Carl D. Grenz

Well, thanks, Bill, and good day to everyone on the call. Well, this quarter for the international business unit has seen us make progress on all phases of our business. I'll now give you some detail on the couple of our key assets, starting with the Rochelle development.

Now the success and timing of installation of all the subsea equipment is clearly one of the key aspects of the Rochelle development. It was hugely important that we hit the most favorable weather window to execute the program or pipeline and control umbilical bundling installation both efficiently and safely, and we have achieved just that. We now have both the East and West Rochelle pipeline and umbilical systems installed all the way back to the Scott Platform.

On the final stages of the infrastructure installation, namely the 2 -- well, manifold systems are being installed as we speak. Now good progress is also being made on the required modifications to the Scott Platform that receives the Rochelle fluids, and we reported last quarter that all the major equipments have been installed there. And we've since had a successful annual maintenance shutdown on Scott in August when we saw the completion of a substantial piece of that modification work.

The drilling rig Ocean Nomad has now departed the field, having drilled the vertical and angled sections of the East Rochelle well, with the final casing section, that's the 9 5/8 section, has been segmented into the reservoir interval. And the wellhead and Christmas tree have also been installed. So that now just leaves the drilling of the horizontal section of the well and the installation of the liner and the completion assembly before production can begin.

Now this drilling took longer than we anticipated as we encountered some geologic issues that had to be overcome. The delays incurred whilst drilling that final casing section. And our drilling team successfully now navigated through the issues to save this whole section. And as I said, we now have that section completed.

Now at the same time as this drilling work's going on, of course, we were continuing on with installation of the pipelines, and that was happening quite a bit ahead of schedule. So we made a management decision to suspend the well, call the rig and allow Technip, the installation contracted with pipelines, who incidentally have done a tremendous job for us, to complete their work scope.

If the pipeline installation vessels had not been utilized within this contracted window, we might have lost these vessels probably until 2014. Such is the nature of this tight vessel market at this time here in the North Sea. There is literally no spare capacity in the market for such vessels.

Now we also took this decision on moving the rig knowing we had a second rig available, called the Transocean Prospect, that's due to arrive to us early in December. So this rig will drill the horizontal section of East Rochelle well, install the liner and the completion string, and then we'll be ready for production start up. So if the remaining work now goes to schedule, we're anticipating production from Rochelle to begin at the end of January 2013.

So now I'll move on to Alba. Production on Alba continues to be enhanced by the ongoing infill drilling program, development drilling program. The first and second wells of a 3-well program this year are on production, and the third is planned to come online in December. Now the third quarter characteristically sees many platforms in the North Sea have maintenance shift out windows and Alba has seen production affected by such planned maintenance activity. We've seen the extensive work carried out on the produced water handling system, and this work went on longer than anticipated. But it's now being substantially completed, with production back up to volumes that we know Alba is capable of.

So I'll now refer finally to the 27th Round, and you can refer to Slide 4 in your slide pack, which, I think, will give additional context to my words here. So the 27th Licensing round was announced recently by the U.K. government. You may have seen the government announced that Endeavour were awarded 7 new licenses, and we think that was an excellent result for us.

These licenses covering 10 exploration blocks in the central area of the North Sea are all operated by Endeavour. As Bill said, they're traditional licenses. Meaning we have 4 years to complete the work scope associated with each license. They're all located close to our existing assets and acreage and provide significant growth opportunities for the company in the future. There are no firm well obligations of these blocks, so we have minimal capital commitments associated with this expanded component of the portfolio in 2013. More specifically, we have less than $1 million of firm commitment on these blocks covering these licenses to 2013.

So the blocks captured by Endeavour build on our existing focus areas around Rochelle and the R block and also our emerging focus areas around Alba, MacCulloch and in the southern area close to the Centurion South prospects that we intend to drill in the second quarter next year. Endeavour applied for 15 blocks in total. We've been awarded 10, as we said, with the results of 3 additional blocks yet to be announced by the government. These unannounced blocks are subject to environmental assessments, and the deck must carry out these assessments prior to any licensing decisions being taken probably later this year.

So in conclusion, we've had a very busy quarter, and we're making progress on all fronts. And as I said, production started from Rochelle occurring in January, pretty close to our targeted date.

So with that, I'll pass over to Jim for the U.S. operational update.

James J. Emme

Thank you, Carl. In the U.S., our net production for the quarter averaged 12.9 million cubic feet equivalent per day, and for the 9-month period averaged 15.5 million a day. And that's great considering we had no drilling activity during the quarter and just one Haynesville completion from a well that we had previously drilled and cased in the first quarter.

We're pretty encouraged by the continued strengthening of U.S. gas prices but expect still to defer discretionary gas drilling until prices improve a little bit further. As Bill alluded to, our big news is the strategic exchange of properties with J-W Operating. We've closed on a trade effective October 1 in which we exchanged our interest in the Willow Springs Cotton Valley project of Texas and the Bull Bayou Haynesville project in Louisiana for all of J-W's upstream and midstream assets in the Pennsylvania and Marcellus trend.

In the Cotton Valley, Haynesville projects, we're trading out of about 2,100 net acres and 3.2 million cubic feet of gas per day net production, but we still retain a 50-50 interest in our 3 remaining Haynesville projects, which are all held by production and have more than 80 remaining undrilled locations.

If you refer to Slide 5 in the slide pack, it gives you a picture of what we got in the Marcellus. In the Marcellus, we're picking up 15,500 net acres, for now a total of 31,000 net acres to Endeavour. That includes all the existing wells and pipeline gathering infrastructure.

In our key Cameron County, Daniel project area, there are several producing wells which are -- have been constrained due to markets to the town of Emporium, and we have 3 horizontal wells waiting on completion, all of this due to limited takeaway capacity up to this point.

In response to that and in parallel with the close on the exchange, we've just signed a gathering agreement with a third-party gatherer, which will deliver additional takeaway capacity of up to 10 million cubic feet of gas per day by the end of 2013. We've also completed lease agreements on some of our key leases, which effectively extend the drilling requirements on those in Cameron County until 2014 or beyond.

So for Endeavour, this trade delivers 100% operated position in the Marcellus where we can control the pace of development in the near term and retain significant growth potential in the long term. We think of it as a low-cost option on future gas prices.

Moving on to the Rockies and our Heath Shale tight oil play in Central Montana, our working interest group decided that rather than drill a more expensive one-off horizontal reentry in our vertical pilot well, we'd defer that activity until 2013. We're taking a disciplined approach because that will give us time to watch production from recent nearby offset wells and also consider a program with more operational efficiencies, and that means potentially sharing rigs and services with other operators in the area. We're confident that we've got the same Heath B [ph] carbonate zone, which is producing in those offset wells, but we also have other targeted zones of interest we're looking at. And we'd prefer to evaluate all those in one continuous operation next year.

Finally, in our stealth play, which happens to be in Northwest Colorado, by the way, we're targeting stacked Upper Cretaceous zones with liquids-rich content similar to the DJ Basin and Powder River Basin plays. We've recently formed a 23,000-acre federal unit where we expect to drill an initial test by midyear 2013. We really like the multi-pay potential and the liquids-rich component of this play, and we'll continue to build our leasehold position there.

That's what I've got on the U.S. for you today. Thank you. And with that, I'll pass back to Bill.

William L. Transier

Okay, everyone, I wanted to give you an update on MacCulloch and Nicol acquisitions. Let me say upfront, it continues to move forward. But to put it in context for everybody, I thought I would go back in history and kind of bring you down to date in terms of what has been accomplished and where we have had to come to get to the spot where we're at.

If you go back in history, we actually started an initiative to buy the additional interest in Alba from ConocoPhillips back in January of 2011. It was through a discussion, frankly, that Carl and I had with the executive team at ConocoPhillips that we tried to pursue buying that asset, which you now know is a significant part of our portfolio and a very important part our portfolio. Conoco at the time said that they would entertain that, but they wanted to package it up because they were exiting the North Sea and wanted to package it up with some other assets, which happened to include MacCulloch and Nicol. They then put that in a competitive process that we went through, and we ended up winning that proposal to buy Alba, MacCulloch and Nicol when we signed a purchase and sale agreement back in December 2011.

For Endeavour, MacCulloch was a mature asset that had been undermanaged. And frankly, it was too small for ConocoPhillips to kind of really deal with. That represented, once we looked at it technically, some potential for operating efficiencies without a significant amount of capital and a fair amount of production that came along with it, and the returns looked good for us based upon current commodity prices. There is more potential. And one of the reasons that we pursued this in the Licensing Round that we just went through, there's more potential in upside in the area if we invest in infill drilling in the future going down the road.

Nicol was really just an add-on. It's immaterial to the portfolio and to our discussion here today. But let me remind you, importantly for us, we were after Alba, and we picked up MacCulloch and Nicol along the way. MacCulloch and Nicol -- MacCulloch, in and of itself, to have another operated asset is truly important to us, but we've got Alba behind us. So let me talk about what all has been accomplished in this process of getting this deal done.

First of all, we have decks approval for Endeavour to replace Conoco as an operator. That's not a small task, but it speaks to who we are as a company and also our credibility with both the partners and the regulators to be able to get that done. Our old pollution response plan, which had to be redone from what Conoco had in place, has been approved now by the HS&E regulators. We have agreed with both Conoco and ENI on the decommissioning security. That's important. The form of that security, we are satisfied with. And I'll tell you now, we'll give you more details later. But for competitive reasons, I'd like to keep it ourself. It does not require a significant amount of capital as was needed to complete the Alba transaction. So this is a very significant result for us and puts us in good stead going forward.

What I believe now is that Endeavour is in a position and has done everything that is required to do under the purchase and sale agreement, and we're frankly ready to close. We feel like that if -- we could actually close on this transaction within days. But I want to remind you that in the U.K., it requires basically everybody unanimous approval on all matters before you can close a transaction. That sounds different than we're used to in the U.S., but it is the way things are done over there.

What that basically does is it makes -- it substantially makes all parties that are involved in the asset privy to our contract that we signed with ConocoPhillips. The seller, in this case, I think Conoco has incentive to close. Because of the approval of Endeavour as operator, we take that as a sign of support by both the regulators and the co-venturers. However, it is just administratively burdensome, and I understate that, to get these deals closed.

Yesterday, most of you know that the contract was intended to terminate, but we signed an extension with ConocoPhillips to allow time for us to get through the rest of the administrative details and get this transaction closed. When we close, I think all of you should be confident that we've captured an asset under the terms we are comfortable with for the future growth of the company. I'm sure you'll have some questions on that, but we are moving that along. And we feel good about the potential of getting that closed in the near term.

Let me just mention one other thing that has been on peoples’ minds the last few days, and that's the resignation of our Chief Financial Officer, Mike Kirksey. We announced on Monday that Mike resigned from the company. I'll say this, Mike is an incredible human being with great core values. We had 5 very good years with him, and he did a lot with us and for us in the capital markets and in our relationships with investors. It is a very tough job that wears on anyone, and it wore on Mike. It was my decision to announce this before we got to this quarter because I didn't want to go through a quarter with this kind of information sitting out there that investors didn't know about. This is a transition point for the company. You heard Mike say that many times in all of our conversations over the years and in the many meetings we've had with you. And we look at his leaving as an opportunity to add strength to the organization as we transition into a much deeper and bigger company. I'll say this, we wish Mike well, and I respect his decision to resign from the company.

Let me make a few comments, and then we'll turn over to your Q&A. Let me just remind you of what we have accomplished in 2012 to date. Production is up over 300%, and a transition to Brent crude oil pricing exposure has been significant. We turned on our first 2 wells at Bacchus. Those 2 wells have performed at what we thought we would need 3 wells to accomplish, a very good asset for Endeavour because of the drilling results today and the reservoir that we found in drilling the West panel well that we've talked about to you in the past.

We closed on the Alba transaction. You know how difficult that was. It was purely on the basis of perseverance of our team, support from existing investors who believed in us and ingenuity of our combined team that we were able to get that transaction done, a very significant asset for us. It has performed well. It has upside in the way that it has performed to this point.

We have done a number of capital markets transactions to structure the capital of the company that gives us running room through 2016 and beyond.

I point you to Page 11 on the debt maturity schedule. We understand the challenge we have ahead of us in 2013. But it is a very transparent solution for us to replace that revolver next year, and we're focused on that right now. Some of the transactions we did subsequent to the end of the quarter to help us put us in a position to get that done. The cost of capital and debt levels are above our comfort level, but we have a real opportunity to improve that situation in the near term for ourselves next year.

No question what our team in the U.K. has done with respect to Rochelle. It's moving towards first production with the drilling progress and the completion of the subsea infrastructure implementation. The actions we took as a management team to work around what everyone recognizes in the North Sea as a very inflexible service sector with absolutely no availability to rely on helped us keep this project on track, and the work that we did was no less, in my view, monumental and probably saved us substantial time and delays in being able to get that project turned on.

The proof is, however, when we actually get the production turned on, and we're focused on, as Carl told you, getting that done as early as we can in 2013. We continue, as Jim talked about, to develop a U.S. portfolio even though we have restricted them from having almost any capital at all. The ability to do the noncash exchange Jim talked about and give us control of an area that we still have some confidence in, and we'll have control over our development going forward, speaks to the team that we have there.

I think, also, what he did not talk about was the acreage that we put together in Colorado, had no upfront cost for us. We'll be able to drill our way into it as we go forward, and we have control of that situation for ourselves. There are now reserves and production in Marcellus that are waiting on completion into an outtake solution that our team was able to put together that we were waiting on for several years for J-W to get done. Jim and his team were able to get that accomplished for us.

This is a much different company today than it was just 10 months ago. We will be even a different company in just the next few months as we complete acquisitions and turn on development projects and move into the next phase, which is to manage the company as we promised investors we would do.

So with that, I thank you for listening to us and we'll open it up now, Jennifer, for questions from the audience.

Question-and-Answer Session

Operator

[Operator Instructions] We'll go to Neal Dingmann with SunTrust.

Unknown Analyst

This is actually Mario [ph] subbing in for Neal this morning. A quick question. If you can remind us again what peak production numbers look like for early 2013 with or without MacCulloch being closed?

William L. Transier

Well, I think we've always talked about that when you say peak production, that the assets should have the capability of producing somewhere north of 20,000 BOEs per day. That depends on a lot of things. And first, it depends on getting MacCulloch onstream and getting operations status there and managing that asset. It also means putting Rochelle onstream. And then you have to look at uptime capabilities for these assets. But when we talk about those slides, that's always been, as you said, the peak performance that can be there for our assets going forward. So that's the best guidance we can give. And what we had committed to do is once we get Rochelle on production, we will begin to give guidance to the marketplace in more detail. What we've done to date is show you what the assets are capable of, and we're trying to get that accomplished in terms of turning on new development and getting these acquisitions complete.

Unknown Analyst

That's helpful. And then my second question is, could you give us an update on what material wells could come online next year? Maybe, which should we be keeping an eye out for?

William L. Transier

Well, I think the most material well that we have in front of us for next year is the third development well that is being designed right now for Bacchus. As I said in my comments, Carl can speak to this, but when we drilled the second of the 2 development wells that went down through the Central panel into the West panel, and we were pleasantly surprised by the upside in the reservoir we found in that work. That -- just common sense and good technical thought process said we needed to rethink where we were going to place the third development well, which was actually originally designed to be in the East panel and turn the first development well into water injection. So we're watching the performance. Apache is watching the performance as we are, and they're working on a design that I think will end up with a well intended to go and extract the reservoir in the West panel. We don't have kind of final results of that. Carl, you can speak to that if you'd like. But we're anxious to get that well drilled next year. But I think, importantly, you should understand, as my comments spoke to a minute ago, that the 2 wells are kind of performing at the level within the range that we expected all 3 wells to perform at, which is indicative of the quality of what Bacchus represents to us going forward. Carl, did you...

Carl D. Grenz

Well, just to build on Bill's comments, we are doing some reservoir modeling and optimization study work right now. It's going to take us a little while to complete that work, so we're watching very closely the performance of these 2 wells. They're outperforming our expectation, as Bill said. The first well, that's going to be a water injector. It's declining slower than predicted. And second well, the West well, has been on since July. It's still on plateau. It's declining less than we expected. So all those features of the reservoir, particularly this West panel, is very much in our radar to model. And once we've completed the modeling and watched the time value of this work a little more, it will tell us where to drill the next well and what type of well to drill. We'll probably get to somewhere in the first quarter before we actually get some clarity around that, and we'll time the drilling of that third well.

Operator

We'll go next to Irene Haas with Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

This is a question on Rochelle. I just want to ask, when you did you first find out that you have encountered geologic issue and how much extra time you actually spent solving that? And then secondarily, assuming that you do have the last leg of Rochelle drilled, can you walk us through what steps you will have to go through physically to get production on? Do you still need to send divers down into the water? And thirdly, how has the weather condition been in the North Sea?

William L. Transier

Irene, this is Bill, and then I'll let Carl speak to it. But we moved the rig off basically last week and to, as we said, preserve the option of having Technip there to finish the installation. I think you can say that as we were drilling that final section down through the final casing point, that happened over the last couple of weeks, we probably spent 10 days to 2 weeks kind of working on some mud issues and some other things that just slowed us down drilling-wise. You never really kind of know you're there until you're there, obviously, on these things and stuff. So -- and then what happened, as Carl pointed out, was Technip was ahead of schedule, and then you had this convergence to simultaneous operations that was on top of us. And we had to make a fairly quick decision to suspend the well at that final casing point, which is a good place for us to be. The risk was that if you would try to drill out the final section. I'll let Carl talk about that. And if you didn't get that done and if you had any other delays in terms of getting it done before the time frame or the contract with Technip, then Technip was going to go away. And then you'd have to worry about when you got back on their schedule. So Carl can speak about what's left to be done. I think he mentioned that, but I let him speak to it.

Carl D. Grenz

Yes, Irene. Well, first on the well, as I mentioned, the casing is a TD so -- and it's built angled so that it's poised out to drill out the lateral section of this well. That's about a 500-meter or 1,500-feet section. Once that gets drilled, we have to set the liner, the sand screens and run the completion assembly. All the Christmas tree and wellheads are already installed, so it's a fairly standard straightforward job for the second week to come along, spud on to the well and just run in and drill that section out. Now moving on to the subsea infrastructure, the pipelines and umbilicals are laid, the manifolds are going in this week, so divers will go in the water to make the final hookup of the pipelines to the manifold systems. It's a diving bell operation, so it's not so weather dependent. Obviously, you need to have weather to get the divers in the bell in the water in the first place. But once they're down, it's not such a big deal. Fairly routine activity, this, so we don't see any issues, particularly around all of that. So once the manifolds are all hooked up, this will all happen before the second rig comes back to complete that well, so they won't be getting in each other's way. So the operations will become discrete, and we'll get this done all by the end of January opening the well.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Carl, just a follow-up. I didn't hear very well. So you still have to send divers in the very tail end, but you don't think it's a big risk with weather?

Carl D. Grenz

The divers will go in to assist the vessels connecting the pipelines to the manifold systems. But because it's the type of diving operation that we're talking about, it's not so weather dependent once they're actually in the water working.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Okay. And then how the weather is conditions right now in the North Sea? And any feel for the next few months are going to unfold?

Carl D. Grenz

Yes, the weather is seasonably very good right now. So we've been blessed with some good weather over the last couple of months actually in the North Sea. Predictions are that, that will continue on as far as we can see ahead.

William L. Transier

But Irene, I'll just warn you, we're not weather predictors so...

Irene O. Haas - Wunderlich Securities Inc., Research Division

No, understood, but at least you're not getting hammered already. So you've got -- at least, you've got that much done at this point. That's what I'm really trying to get at.

William L. Transier

I think the important part is that Carl and his team were able to put most, if not all, this infrastructure in place. The diving, as you know, if you're doing it out of a bell situation, it allows us to get down and do the work there as long as you can get to the site and get the divers in the water there. So it's -- he talks about it being routine. Nothing is routine in the offshore arena. But as these things go in the offshore, this is standard operating procedure.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Got you. And one more question, when does your contract, your window close with Technip? Can you tell me?

William L. Transier

Carl, do you want to -- the question was the contact with Technip.

Carl D. Grenz

Yes. Irene, if we hadn't got done by the kind of the middle of November time frame, we would have had to make a decision to release those vessels to the next contract.

Operator

And we'll go next to Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

I've got a few quick ones on Rochelle here that I'll just rattle off and let you respond to. Carl, I just want to make sure that I understand clearly what the geological issue was that you guys encountered, that's #1. And then 2, you did mention -- you've mentioned that market for vessels in the North Sea is extremely tight. And if you do get snagged on something between now and the end of January, whether it's weather or operational -- an operational issue, what are the chances that you'll lose those vessels for a prolonged period of time? I think you mentioned that Technip, you might not have been on their schedule till 2014, if it didn't get worked on prior. And then, third, do you still expect that once Rochelle comes online, is that 100 million a day gross figure still the right number to look at? And how long does it take to ramp to that number once you hit first production?

Carl D. Grenz

Okay, Mike. Well, just to talk about the vessels, first of all, we won't be getting the work completed all but one small piece, which I'll come back to, by the end of November. So that's when we will be releasing all the vessels in the Technip work scope. The final vessels that are in position now are really to install these manifolds, these 2 big well manifolds one on each of the well locations. And then the vessels will be used to do the final hookup into conjunction with the divers, and then they'll go. So we're not looking at these vessels being around us through beyond the end of November, just to be clear about that. So when production comes online, you asked about 100 million, our expectation is that we have a minimum contractual value but we expect capacity up to around 1 million standard cubic feet per day still. We will be bringing the well on. It will ramp -- the gas well, it will be ramped fairly quickly within the constraints of the commissioning of the pipeline systems and the facilities on the platform. The key -- once the pipeline is full of gas, it's a very straightforward and easy ramp up to full production. What we have to do on the Scott Platform is prove up the additional capacity on Scott by using the gas compression more. So that's the key area there. And once we get into that phase of the operation, we'll then be looking at ramping up to this capacity limit that we arbitrarily set ourselves of 100 million cubic feet per day. So what was your first question? Could you remind me of that, please?

Michael Kelly - Global Hunter Securities, LLC, Research Division

Yes, it was about the geological issue. But maybe I'll just stop you before you talk about that and just ask for some more clarity on that production rate. For us guys that are trying to model this, and maybe Bill could jump in here or Darcey, what's the best way to think about that 100 million a day? Are we talking capacity here? Or is this -- I'm more concerned about what the actual production will come in at and how it's going to flow through the income statement?

William L. Transier

Mike, this is Bill. I think the better part of good judgment is to say, "Let's get the well on and tell you." We have capacity limits. The well should perform at that level. I'd like to get this well on and then talk to you about uptime utilization and those kinds of things that are there. The part of the question you asked, too, was around service equipment, and I'll come back to that, too, with this. But our expectations have always been that each of the 2 development wells had the ability to produce at our capacity limits going over the Scott Platform. We had been guaranteed a minimum of 60 million a day and agree to that it can go to 100 million a day across the Scott Platform. So once we begin to ramp up and we take on that capacity, then we will have it going forward. But I certainly wouldn't -- and we're not going to give guidance at this point, but I certainly wouldn't just plan on immediately after the well comes on that you got to 100 million a day. I would allow us to turn on the production and then come back to you and guide you properly down the road. But that's -- our goal is to get that 100 million a day up and have utilization as close to that as we possibly can as quick as we can next year. Let me just mention one other thing and then I'll let you come back to your question. But Carl is right about the infrastructure development and getting Technip to commit to finish their work on Rochelle. We -- the reason we made the decision, as Carl said in his comments, was that we have the Transocean Prospect that's under contract to come and drill the second well of the 2 development wells for us at Rochelle. We're going to use that rig to finish out the first development well, as we talked about. We are dependent upon that rig showing up and the timing that we talked about, and it confirmed this morning that we expect it to be with us around the first part -- the first week in December. We will keep you informed as we know stuff, but we are dependent upon that rig to come to us and us to be able to finish out the lateral section that Carl talked about in that well.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay, great. Bill, the other question I have for you is just -- pertains to cash inflows and outflows in the second half of this year. And quite frankly, I was a little surprised to see you guys add $15 million to your credit facility in the past month or so and do a $54 million debt deal, given that you had $95 million of cash in the balance sheet coming into the quarter. And you guys stated you had ample liquidity to execute the CapEx program in the second half of the year. Last quarter, you stated that CapEx for the second half -- on the call, it was stated that CapEx was slated to be between $80 million and $90 million, and it would take $20 million to close MacCulloch and Nicol. I was just wondering if you could give an update on that and then also talk about just the cash inflows, too, and maybe some of the disruptions you've had between your liftings [ph] at Alba and the actual timing of when you received the check on that production.

William L. Transier

Mike, we're doing the best we can. But I think, first of all, if you look at the slide pack we put out, the capital is pretty much in line with what we said. Direct capital expenditures for the first 9 months of the year was $140 million. That's pretty much in line with what we said all year long. We probably incurred some additional costs with the additional drilling time on Rochelle. But Carl assured me the other day that it's not a huge amount of money and stuff. So we feel like we're on track to deliver that project within a fairly tight range of where we already talked about. You talked about cash inflows and stuff and the credit capacity. I view it as just good common sense that I commented on in my own comments to this conference call that to have liquidity and to have cash to be able to make sure we get Rochelle turned on, we've had -- I think production levels are right in line with what we thought we were going to have in the third quarter. But there's a lot of things that are out of our control. So adding $15 million of liquidity, taking advantage of the high yield debt markets and taking off the $25 million of 12% subordinated notes, I just view those as baby steps to make sure that we deliver on the overall game plan for the company. So I'm going to warehouse the cash. And as soon as we can get production in place, we'll use that cash to pay down debt and reduce cost of capital for ourselves going forward.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Got it. Do you have an estimate for what CapEx would be in the fourth quarter here? And is that $20 million still a good figure for what the cost to close MacCulloch could be?

William L. Transier

I think $20 million is a good estimate for the net purchase price on MacCulloch. And what was the second? CapEx? I think we're still on track, Mike, for CapEx, as we said to be right where we are at end of the year. Some of this stuff has -- like the third development well at Bacchus, has been pushed into next year. We're going to have to spill over our costs on Rochelle. That also means that we've got some more CapEx next year than we kind of planned on if we had gotten Rochelle all the way done this year. So you have some mix and the matching of that, but I don't think it's significant. I think we're going to be pretty much on track with what we've said all along this year that we should be. I don't -- your question is really along the line, is there any more surprises coming? I don't foresee any between now and the end of the year.

Operator

We'll go next to Steve Berman with Canaccord Genuity.

Stephen F. Berman - Canaccord Genuity, Research Division

Just one quick clarification. I got distracted for 20 seconds here on -- at Rochelle, the rig coming in to finish. The first development well, is that sticking around to then drill the second development well after the first one is finished? I might have missed that.

William L. Transier

Well, that's a good question, Steve, and that's still being negotiated. So the hope is that it will. If not, we have a rig slot for a exploration well next year that we would probably just push off and try to use that rig to drill the second development well. But let me point out, from our point of view, it should not have an impact on us ramping up production because, as we've said all along, the 2 wells were really redundancy in terms of pursuant to Rochelle development. Obviously, we'd like to have both wells turned on. We'll just have to keep you up-to-date with the rig market the way it is. But Carl and his team are working with our partners that have provided that rig to us. And I'll remind you, Steve, what we forget this year is that we moved away from a rig that was with a company called Awilco early in the year to be able to provide the rig that we were drilling, the CITGO rig to be able to drill the development well that we had going on here. And now -- excuse me, the Diamond rig. And now we've got this Transocean rig lined up in replacement of that Awilco rig to drill the second well. So the movements that the team has made to be able to keep the project on track had been, as I said earlier, pretty strong in terms of being able to continue on track. So we took the position that having the rig to drill the remaining section of the first development well was the most thing so we could get production on. And then we will work on getting the rig to drill the second development well, whether it's this prospect rig or whether it's the rig that we have lined up for next year.

Stephen F. Berman - Canaccord Genuity, Research Division

Okay. A question for Jim so you don't feel left out here. The Heath, Jim, can you elaborate a little bit about the plans going forward? I know, for example, Cirque and Fidelity have been active out there, have announced some wells. I mean, are those a couple of companies you might work with as you go forward in 2013?

James J. Emme

Yes, Steve, I can comment. As you know, we've got our 4 vertical pilot wells that we've drilled, cored and evaluated. And in parallel with that, those other operators you mentioned, have drilled, I think, up till now maybe 7, which I'd call, key wells immediately adjacent to our leasehold in that Greater Sumatra area. A couple of those had announced IPs, and we're watching the production on those a couple of them that are more recent, there's not a lot of data out. So we're expecting to see that soon. And I think long story short, we've got a couple of target zones we were looking at, but we were really only lined up for one horizontal; reentry. And as you may know, in that part of Montana, it's pretty expensive to bring rigs and services in and out for a single operation. And we've been talking to the other operators, and I think we're going to come up with a plan to be much more efficient in terms of costs on sharing rigs and services and may give us an opportunity to test more than one well by waiting till next year. The leases that we've got are long term, so we're not in any rush. We've got some lease extensions that we can execute next year at very low cost. So we just thought it was prudent to show the discipline to watch basically what others are doing to help us de-risk the play and then come up with a more continuous coherent plan for next year.

Stephen F. Berman - Canaccord Genuity, Research Division

Okay, great. And then one more for Bill. On the realized oil price of $99 and change, that was well below kind of average Brent prices for the quarter. Can you just address why that was?

William L. Transier

It's really not, it includes liquids production, and that's why the averages are the way they are.

Stephen F. Berman - Canaccord Genuity, Research Division

So that's got the NGLs in there?

William L. Transier

Yes. That's a combined. It's something that -- thank you for making the suggestion. We'll try to be more direct in our slide pack for you going forward. How's that?

Stephen F. Berman - Canaccord Genuity, Research Division

Fair enough.

Operator

We'll go next to Ashwin Reddy [ph] with Vendor Capital [ph].

Unknown Analyst

I just had a couple of quick questions. The first one was, with respect to kind of now looking forward in the near-term liquidity picture of the company, I mean, do you guys feel pretty confident that you have what you need to bring up Rochelle and to do whatever needs to be done in other pieces of the company as we're looking forward now?

William L. Transier

Ashwin, this is Bill. I think we're as confident as we can be right now, and we've said that all along. I'm always concerned about things that are outside our control. But I think you know that the facts that we're dealing with right now, and I feel good about our production that we have with the assets that we have already. I talked about the opportunity, the option of getting this Marcellus -- excuse me, the MacCulloch transaction completed. We'll do that as quick as we can. And we've done everything we can to keep Rochelle on track to deliver first production on that as quick as we can. With almost $11 pricing in Europe for gas, I'd love to capture that and start recovering our capital as soon as we can. The concern is always anything that's outside our control that would delay this going forward. But frankly, the major part of the capital is really behind us, and we have tried to build as much control as we can into any kind of capital requirements the first half of the year, next year, to allow us to make sure we get Rochelle up and running full speed and have these other things under our control. So the answer is, I feel as confident as we can be right now. And if everything stays in place that way it should be, we're going to be in really good shape.

Unknown Analyst

Okay. And then just on MacCulloch real quick. I know you had mentioned, I guess, in your opening or in your remarks earlier that you thought it could close kind of within days. I mean, what is -- can you go into a little bit more detail as to what is really left to kind of get done? I don't know if I just maybe missed when you're running through it. But if could you talk a little bit about more kind of between now and closure, kind of what are the steps and what are kind of the processes that you guys are all trying to get done? Maybe it would be helpful just so I could kind of maybe understand a little bit better.

William L. Transier

Well, I love the question, and I would -- I'd love to spend the next week trying to explain to you why it's so cumbersome to get things done over in the U.K. North Sea. Frankly, as I said on the call, from our point of view, Endeavour's point of view, it has done everything that it needs to do and from a contractual point of view, conditions precedent to be able to close on the transaction. The difficulty you have over there, as I said earlier, is because you have to have unanimous approval from everybody involved, including the regulatory agencies. And I tried to click those off for you as we went forward, what I consider to be the principal barriers to getting any transaction done, which we have accomplished, you still have a lot of parties involved that I don't have complete control over in terms of their signing off on a transaction. Should they be able to slow things down? No. Do they have any right really to hold back on their approvals? I think not, in my own opinion. Does that mean that we don't have to kind of work around some of these things and get everybody in place to go forward? In my view, this transaction -- we did a transaction back in 2006 that was actually larger than this one. And we bought a package of assets from Talisman. It took us 5 months to get the entire deal done. This transaction was a headline price of $330 million. We paid $219 million to buy Alba, and we'll pay roughly $20 million to get this one done. It's taken us taken us 10 months, and we had to do an extension with Conoco yesterday to get it done. Things are just different and more difficult in the U.K. to get things done than they were pre-2008, 2009. What I can tell you is that we feel good about what we had done and how we've handled this, and it's a huge hurdle to get over. Carl and the operating team have gotten the deck to approve us as operator. That was always something that we pointed to with everybody that are investors in the company. That had to be accomplished. To get the regulatory -- HS&E regulators to approve the oil pollution plan, that was no longer applicable that Conoco had, also speaks to us technically in our ability to get that done. And then finally, getting both Conoco and ENI to sign off on the decommissioning security arrangement that was there even though we spent almost a year negotiating that with Conoco ahead of signing the purchase and sale agreement. Those are all huge hurdles to get over. But with that said, there's a bunch of small parties and other things that have to get done. Like I tried to guide us on the call, to me, this thing could be closed within days. I've been telling you 30 to 60 days for 30 to 60 days, and I was trying to bridge the credibility gap with everybody on the phone as to where we're at. If you can just think about it one way, and the only way I can explain it, the way that transactions get done over there, by making everybody sign off before you can actually close a transaction, you, in essence, make all them a party to your contract between you and the seller, in this case, ConocoPhillips. It's not -- they can't change the contract between us and ConocoPhillips, but they can sure hold up the approval process just to get there. And that's what we've been dealing with. I don't see anything -- I don't see any big hurdles going forward, but I'm not going to sit there and tell you it's going to be closed tomorrow or the next day. We're working hard to get it done as quickly as we can. Carl is anxious to get his operating team on this going forward. I know it's hard to understand and explain but just accept that Endeavour has been pretty good at figuring its way through these things and getting them done. And this one, we're in good shape, I believe, to accomplish that soon.

Unknown Analyst

Perfect. And then the other thing I kind of wanted to ask you about was the -- just the timing on what we're looking at to next year on the bank revolver and how you guys -- or I mean, the potential of new bank revolver, sorry, and how you guys kind of view the steps between now and when that could actually come in play to help refinance out some of the higher cost capital you guys have in the structure here?

William L. Transier

Well, I'm anxious to get up to that higher cost capital. And you can look up and down the balance sheet -- I mean, the debt structure and see what's easy to take out on a current basis. We've talked about that in the past. I think, from a practical point of view, you would like to get MacCulloch done and you'd like to get Rochelle on to have the best kind of response and execution of a revolver. I don't think that you actually have to have MacCulloch done to get the revolver done, but I think it would be helpful to have Rochelle on production because it's such a big part of who we are going forward. So you will see us try to get this done as soon as possible. I think that we tried to get this done immediately after we had the Alba transaction done, and we've had good response. But we're just not there yet in terms of where we need to be. So if I'm being honest and practical about it, you're probably in the first quarter next year before you get this thing in place.

Unknown Analyst

Okay, great. And I guess just one last one, if I may, sorry. But you kind of talked about the rig coming over -- the new Transocean rig to come over and finish out the horizontal section on the -- under Shell in the first well. And I believe you guys said it was the 1st week of December when that's due to arrive to you guys. I mean, can you just talk about the potential for -- or any possibilities why that rig may not be there at the time that you guys are expecting it to be?

William L. Transier

I think it's pretty simple. It's drilling a well for somebody else right now. And if they have any hiccups in doing the drilling on that well, we're going to have a wait in line. It's scheduled to come to us as soon as it gets done. We watch the schedule every day in terms of what's being done, and that's the schedule we've been presented by Transocean. And so it works well right now if it comes to us early in December. Because it gives Carl and the Technip team plenty of time to get all the rest of the infrastructure in place, so that you don't have the simultaneous operations issue again. But we'll watch it. And if we see something that changes materially, we'll let everybody know.

Unknown Analyst

Okay, great. But right now, it seems like whatever they're doing is on schedule for the other well. So that's kind of the expectation, I guess.

William L. Transier

Once again, well, that's what we've been told. It works well with us. We don't have control over it, but we'll keep you informed.

Operator

We'll go next to Amy Stepnowski with Hartford.

Amy Stepnowski

Just a quick question to follow-up on the licenses that were rewarded. You stated that there was minimal CapEx associated with them in the near to medium term. Could you just help me understand on what basis were the licenses awarded? Was it a competitive bid? Or what exactly were the metrics that were used to award it?

William L. Transier

Amy, I'll let Carl -- I don't mean to dominate the questions, but I'll let Carl talk about it. It's something I've lived with now for 8 years, and that's how we got started. The way it works in the U.K. is you bid work programs. They identify the areas that are going to be subject to a bid round. You put together bid groups if you choose to or you put together yourself to go after the bid and you have to submit a work program that is to pursue the blocks that you're after. That goes through a very involved review process with the Department of Energy and Climate Change. That goes through an evaluation, actually, a grading process. And based upon your work program and your technical skill and how you have handled that in the eyes of the deck, they then award you those blocks. In this case, these blocks are traditional licenses, and that's different than promote licenses. Promote licenses only have 2 years to do your work program. Traditional licenses give you 4 to do your work program. The reason that we said it was minimal cost is that, basically, all we are required to do over the next 4 years is kind of technical analysis of these blocks, which may include some buying of some seismic, some reprocessing of seismic. We have one contingent well amongst the blocks, which means that you have to go through a technical evaluation before you would make a decision on whether you would put a well in place or not. But we have 4 years to complete that. So I think Carl would tell you, and we looked at this exposure before we submitted the bids, we're probably realistically less than $1 million to $3 million of cost, and most of that is internal cost that we'll have to spend over the next year and possibly 2 years until we decide that there's more work to be done.

Operator

We'll go next to Steven Karpel with Credit Suisse.

Steven Karpel - Crédit Suisse AG, Research Division

First, I want to go back to, I think, it was first question when we talked about production capacity. And I got a lot of numbers here, so I'll try to go slow. So if I look at what the business was before the Conoco acquisition of Alba, it was somewhere, call it, around 4,000 barrels a day. And primarily, U.S. obviously had the small Alba stake. It looks like there's been a bit of a decline. So it seems to me that, that, what I would call, the base business is somewhere around 3,500. I'm going to add up these numbers and tell me if this works. And then you acquired 7,000 from Alba. The Bacchus well is -- the 2 wells are somewhere around 3,000 to 3,500. MacCulloch, I think you pick up another 3,000. And then Rochelle, when it comes, on will be somewhere in the neighborhood on a BOE basis of 7,000, give or take. So that aggregates, if I'm doing the math right, to somewhere 23,000, 24,000 barrels a day of capacity. So if I look across the North Sea, first off, are those numbers right? And if not, please correct. And then the second part of that is going to be, if I look across maybe the North Sea in general, what's, a, uptime that we should use in essence to say, if we look at capacity as a generalization of its 23, 24, we're supposed to multiply that by 0.8, by 0.7, to understand what the actual production can be and what we'll actually should see?

William L. Transier

Well, Steven, I'll try to do my best. And once again, we're not going to get give guidance at this point, but we will address this formally for you because I think your question is good one. But I think, first of all, your base production was probably high. I think when we started at the beginning of the year, it was closer to 3,000 BOEs a day, which is what I commented on my -- and probably half of that -- a little bit less than half of that was North Sea and the rest of that was really Jim's production in the U.S. But I'm not going to mince words with that. Alba, we pointed, when we were acquiring the asset, that it was around 7,000 BOEs a day. I think when we actually bought the asset. It was less than that. And as Carl has pointed out, there's been water handling issues and other stuff that has probably kept that below that number, at least since we bought the asset, albeit right after we purchased it, we put on an infill well and we were producing above 8,000 BOEs a day. But you shouldn't factor that into your focus going down the road. You mentioned MacCulloch at 3,000 BOEs a day, I think that, that was really a number that was associated with both MacCulloch and Nicol. And that was based upon the assets we were buying at the time. I don't think that it's more than 2500 BOEs a day. It might be slightly less than that because of the lack of attention to the asset that's been there over the period that we've been trying to pick up the -- to finish the acquisition. I think Carl would tell you that he sees quick response in terms of doing some things, gas reinjection, things that we've talked to you in the past that can get that production back and maybe enhance that. But we haven't talked about any sort of enhancement at our numbers going forward. And then you talked about Rochelle, and we've talked about Rochelle today. Your 7,000 BOEs a day is 100% at kind of 100 million a day. And you're right, you probably shouldn't factor that in. So the numbers, as you said and as we've shown in our presentations, 20,000 to 25,000 BOEs a day, that's kind of capacity. I think Carl would tell you that North Sea uptime is probably in the 80% to 85% range across the venue. Carl, help me if I'm wrong about that. And that can vary. What we work very hard on internally, in terms of our own assets, is working with the other side to work on that uptime availability. And some of that just depends upon normal shutdowns, what's been worked on and stuff like that across the board. So our job, I think as you talked about, is once you do get production online, you get the acquisition completed, you get Rochelle on, then our job will be to work with you and tell you exactly where that goes. But we do have the capacity to produce any given day at the high end of that range. I think you got to look over the course of a year and what it really means to you.

Steven Karpel - Crédit Suisse AG, Research Division

Right. As a general organization, that 80%, 85% is, I suppose, where I'll start. And then -- and we just to make sure I'm not missing anything for '13, any of my numbers here as I use kind of the space of 20%, 25% and then the North Sea at 80%, 85%. The Bacchus, the third well, and then Alba infill wells and the Alba infill wells in essence to keep production flat-ish. Is there anything else I should consider?

William L. Transier

Steve, I think that's fair. I think you got a look at the second development well at Rochelle. I mean, as I said before, it's redundancy, but we got to get the first well on and makes sure it's performing as we talked about. I think those are the issues that are in front of us. And that's all good stuff, but I think you asked really good questions.

Steven Karpel - Crédit Suisse AG, Research Division

And then lastly, I know it's been harped on it a million times but give you a chance to summarize. If on Rochelle, if there is a delay or -- with any issues, are we talking just a couple of weeks? Meaning that if January slips to February, we're not talk about something many days incrementally beyond that. Or are we talking that January '13 slips to January '14, which, I think, is what people are pretty concerned about.

William L. Transier

I respect the concern. I would hope that you would respect what we had done to try to keep it on track with where it's going. I think I've said it straightforward, Steven, that the infrastructure is and should be completed, as Carl talked about in as much detail as we can tell you. And we're dependent upon the Transocean prospect coming to us and allowing us to finish out that last section of the first development well to turn on production. And so your question is -- I can't answer it. We think that it should be -- the grade should lead to us in early December, and we should be able to move forward and do exactly what we talked to you about. I...

Carl D. Grenz

Bill, if I could build on your comments a little bit. Steve, this is a risk business, and I think we've demonstrated over these last 2 months on the Rochelle where we've dealt with issues very effectively to keep this project on track. If there are any issues going forward, we have a very skilled team in place who know what they're doing, been around the blocks a few times. And we do -- we tend to deal with issues pretty effectively if they come our way. All being well, all the guidance we've given you today, weather factors look good. The timing that we've given you looks good right now. We don't anticipate too many problems. But if we get them, we'll deal with them to keep this project on as much as track as possible.

William L. Transier

I think just one other thing, Steven. I mean, the well -- exploration well for another party, how long should that take? Most of these wells get drilled in a pretty tight window of time. Even when they have issues, it's not like it's a development well and completion and other things. But our commitment to you and the rest of the folks listening in on the call is if we find out new information that materially affects this timing, we'll let you know as soon as we can.

Steven Karpel - Crédit Suisse AG, Research Division

All right. And just -- I think just one thing I'd just clarify. I think you said it was the Bacchus well. The capacity numbers we were referring to in all the math we did was before the third Bacchus well. Is that right?

William L. Transier

Well, yes and no. I mean, what I said was is that we're now producing at -- within the range that we talked about for the 3 development wells. We've had good performance in the 2 wells that we have. There was always anticipated normal declines, and we were going to turn one of the wells on as a water injection well and to drill the third development well. So the hope is exactly as you talked about, Steven, is that you drill the third development well and you get something better than the range that we talked about. But let's see where we are when we drill the well, and let's see how it performs overall and what we do to pursue the reservoir going forward. I like what we've seen so far, but we got to get down the roads and get this third development well on.

Operator

I'd now like to turn it back over to our speakers for any additional or closing remarks.

K. Darcey Matthews

Jennifer, thank you. Our thanks to everyone on the call for their time today, and we appreciate very much your interest in the company. Have a good day.

Operator

That does conclude today's conference. Thank you for your participation.

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