Endeavour International's (END) CEO William Transier on Q1 2014 Results - Earnings Call Transcript

May. 7.14 | About: Endeavour International (END)

Endeavour International (NYSE:END)

Q1 2014 Earnings Call

May 07, 2014 10:00 am ET

Executives

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

Derek Neilson - Managing Director of U.K. Operations

James Joseph Emme - Executive Vice President of North America

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

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

Analysts

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

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

Stephen F. Berman - Canaccord Genuity, Research Division

Hassan Jawed Ahmad - Imperial Capital, LLC, Research Division

Josh Gale

Jame Donath

Operator

Good day, and welcome to the Endeavour International Corporation's Q1 Earnings Conference Call and Webcast. Today's conference is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Ms. Darcey Matthews, Director of Investor Relations. Please go ahead, ma'am.

K. Darcey Matthews

Great. Thank you, Kyle. Good morning, good afternoon, everyone, and thank you for joining us today for Endeavour's 2014 First Quarter Earnings Conference Call. Joining us today, we have Bill Transier, our Chief Executive Officer; Cathy Stubbs, our Chief Financial Officer; Derek Neilson, Managing Director for U.K. Operations; and Jim Emme, Executive Vice President for North American Operations.

There is a slide deck supporting this call available on our web page at endeavourcorp.com. Also, let me remind everybody 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 annual 10-K and our upcoming 10-Q.

It was an active quarter for the company as you can see on Slide 3 of our slide deck. Physical production was up slightly to 9,440 barrels of oil per day for the first quarter compared to Q1 of 2013, and sales volumes were up 55% to over 11,000 barrels of oil equivalent per day compared to the same quarter a year ago. We refinanced the revolving credit facility and LC procurement agreements at substantially lower costs of capital, as well as completed a private placement for $30 million.

Operationally, we had first production at the East Rochelle E-2 well, reinstated partial inject -- water injection at the southern part of the Alba field, and started production from the A68 well in that same field. We also successfully finished the hydraulic fracture of 2 Marcellus wells. And then finally in April, the company settled its outstanding litigation with SM Energy. For more details on all of these events, we'll start with an operate -- excuse me, we will start with operational reviews from Derek and Jim, followed by financial updates from Cathy. And then Bill will wrap things up with a few final comments before taking your questions. And now, I'll turn the call over to Derek.

Derek Neilson

Good morning, everybody. I'll summarize what's been going on in our U.K. operations. Bacchus performance continues to be very good, with production from the 2 wells remaining strong. Production efficiency also remains exceptional for the North Sea, with an average of over 95% availability in 2014 to date. In Bacchus, the plan to convert the first development well to water injection to provide precious support to help sustain production rates and increase recovery for the remaining 2 production wells is still planned to be performed in the second quarter of 2014.

Moving on to Rochelle. Production restarted from the East Rochelle E-2 well around the time of the last earnings call in early March and averaged 65 million standard cubic feet per day with 2,800 barrels per day of associated liquids during most of that month. This was less than previously anticipated due to gas compression capacity constraints in the Scott Platform. This restriction resulted from a very successful work-over that was performed in the Telford field, that also produces through the Scott Platform, and that consequently led to unexpectedly high gas production rates from the Telford field.

The short-term production forecast from the Scott operator now shows that gas compression capacity available to Rochelle is expected to increase later this year. And regardless of that, we are addressing the engineering commercial options for increasing gas compression capacity available for Rochelle, with a view to achieving higher production rates as quickly as possible.

On Rochelle, towards the end of March, an incident in the Scott Platform resulted in production from the Scott and Telford fields, as well as Rochelle, being shut-in. Mechanical failure in Scott resulted in an emergency shutdown of the platform, and following full investigation of the incident and completion of the remedial action by the Scott operator, production from Rochelle resumed on April 26. Looking forward, in the short term, we expect Rochelle production will be provided from the East Rochelle E-2 well. Good reservoir management practice to maximize reserve really dictates that the 2 Rochelle wells should be produced in proportion to their ultimate recovery. And thus, the East Rochelle well requires to catch up with the 2 months of production from the W-1 well last year. It should be noted that while W-1's completely shut-in, it is immediately available for production should it be required.

Progress has been made in Alba, with partial water injection to the south of the field being reinstated in late April through a subsea service line. This provides pressure support and allowed the C-13 [ph] well that has been completed late last year to be returned to production. This is expected to be today. The full impact of water injection production will become apparent, but it's likely to be modest compared to the -- that when we get the permanent repair of the water injection line that's targeted towards the end of this year.

Furthermore, now that the first well in the 2014 development drilling program, well A68, was put in production in March and the drilling program is continuing with well A69. That well is expected to start up production at the end of June. The addition of these wells, along with the impact from the partial subsea water injection, is expected to boost overall field production rates.

Looking further ahead in 2014, the third quarter is typically the period for maintenance shutdowns in the North Sea. This year's shutdowns are actually of shorter duration than last year for our assets. There is a 16-day shutdown at the Forties Pipeline System that is planned in August, and that will impact production from both Rochelle and Bacchus. Alba, however, will be unaffected by this as the oil was exported through shuttle tanker. A short Alba shutdown is planned in July for the annual testing of the emergency shutdown valve and other essential maintenance.

Finally, moving on to exploration. We are continuing our efforts to secure a partner to farm out our Rossini prospect on Block 15/26a, north of the Rochelle field. Preliminary well planning is also underway, with a view to drilling Rossini in 2015. The main exploration activity in the first quarter has been in the 28th U.K. offshore licensing round. We have made several applications for additional acreage, which will be complementary to our current portfolio. The deadline for applications was the April 25th, and our successful applications will be known towards the end of this year.

I'll now hand it over to Jim for an update of our U.S. activities.

James Joseph Emme

Thank you, Derek, and good morning. In the U.S., we've got significant completion activities to report on our Pennsylvania Marcellus play, and we're also making preparations to drill later this year in our Niobrara liquids-rich play in Northwest Colorado. Starting with the Marcellus, we operate our 50-50 joint venture there with Samson Exploration in Cameron County, Pennsylvania. In March, we successfully completed hydraulic fracture stimulations for our C-14 and C-20 horizontal wells. This operation benefited from positive learnings in the area and included more than double the number of frac stages on the longest laterals to date relative to our previous wells. This operation was a textbook stimulation effort. It went smoothly and according to plan. So over the past 7 to 8 weeks, we've shut the wells in and allowed the stimulations to soak, which should improve flowback performance. And now we're on the verge of testing these wells back in the coming weeks and look forward to those results. We've also scheduled the third C-13 well stimulation for mid-June using the same completion design. In the meantime, we expect final permit approval soon for our new infield pipeline and will commence construction immediately with an in-service target by Q3 2014.

Moving to our Niobrara liquids-rich play in Northwest Colorado, the company's got 2 projects with leasehold and drilling options totaling about 40,000 gross acres and 27,000 net acres. We have 2 federal units, namely the Wiley unit to the North and the Oreo unit to the South and are proceeding with plans to drill initial horizontal tests in our Niobrara target zone in the late summer to early fall. Endeavour's and other third-party activities in both the Piceance and San Juan basins have generated a lot of industry interest in this emerging play, which is situated in a well-established and robust petroleum system. As such, we're actively considering partnering opportunities prior to commencing horizontal drilling in Colorado.

That's it for the U.S. And with that, I'll turn it over to Cathy.

Catherine L. Stubbs

Thanks, Jim. Hi, everyone, and thanks for joining the call today. I'll discuss with you our results for the first quarter, and then I'll give you an update on our recent financings and our liquidity situation. And then finally, I'll update you on the CapEx outlook for the year and production guidance for the second quarter.

We had a tough quarter. We've dealt with some unplanned incidents and reacted with obtaining additional liquidity from the market, and we also began work on our balance sheet.

Turning to the quarter results. Revenues for the quarter were $94 million, which were up $36 million or 63% over last year's first quarter due to increased volumes, offset somewhat by lower pricing. Slide 4 shows you sales volumes were 11,134 barrels of oil equivalent per day for the quarter, up 55% over the first quarter 2013 sales volumes of 7,186. This is primarily due to a larger lifting at Alba this quarter and Rochelle production, which came online in October of 2013. Despite this increase over prior year, our first quarter was depressed due to Rochelle being down for most of the quarter. It was offline in the months of January and February for our valve issue and an additional 6 days in March due to the issues at the Scott Platform. As a reminder, we record sales volumes as liftings occur for our oil, which mostly impacts Alba. Due to the timing of lifting versus production, our physical production volumes were 9,440 barrels of oil equivalent per day for the quarter, below our sales, but within our guidance of 9,000 to 10,000 BOE per day.

Our realized commodity prices were down slightly from prior year quarter, but remained strong in the U.K. and continue to strengthen for U.S. gas. Our average realized U.K. oil condensate pricing for the quarter was $104 a barrel versus $108 last year. Brent averages $108 per barrel for the quarter and it's currently holding around that level. Rochelle gas production again is sold based on the NBP index. This NBP averaged about $10 in McF in the first quarter. The NBP is seasonal, with peaks in the winter months and lower pricing in the summer months. But the current strip for the NBP for the remainder of this year remains strong and averages around $9 in McF. In the U.S., our realized gas price for the quarter was $4.50 in McF, up over $3 in the same quarter last year. Henry Hub continues to strengthen and is currently in the range of $4.80 in McF. We took advantage of the U.K. pricing environment, and during the quarter we added hedges -- which our hedged position is shown on Slide 5 -- through adding embedded collars to our oil marketing contracts, locking in pricing on 4,000 barrels of oil a day for the second half of 2014. These have an average floor of $102.50 per barrel and a ceiling of $108.25 a barrel. Further, we entered into a third forward sale on approximately 200,000 barrels for the second half of '14, providing a hedge for these oil volumes. We'll continue to be prudent and hedge our volumes to the extent we are able to with counter-parties, and currently we're focusing on hedging our U.K. gas production once it's stabilized.

Operating expenses are up this quarter over prior year quarter from $18 million to $27 million. This is primarily due to the increased sales volumes again from Alba and Rochelle. On a BOE basis, our operating expenses remain flat with the last quarter and prior year quarter at $27 a barrel of oil equivalent. We continue to be disappointed with the high costs at Alba, caused by dealing with the several issues there, and we are working with the operator to address ways to improve.

DD&A is $45 million for the quarter, up $23 million in 2013 -- from 2013, primarily due to increased sales volumes that I've mentioned this year over last. On a per BOE basis, DD&A is up this quarter over last year's first quarter due to the increased depletable costs we've added as we've spent capital last year to complete and bring on our U.K. development assets. As a reminder, accretion expense on our asset retirement obligation runs through this DD&A number, and it's roughly $6 million a quarter. We are seeing reductions to G&A in the first quarter. Our gross G&A, before we move portions out to capital and operating expense, is down $2.5 million from the first quarter of last year. On a net basis, G&A that's shown on the income statement is $4.8 million for the quarter, down from last year's quarter of $5.5 million. We're on track to meet the goals we told you about to realize savings in G&A for the office consolidations and the reductions made at year-end 2013. We recorded a loss on early extinguishment of debt at $4 million this quarter. We announced here earlier this year that we refinanced our existing credit and LC reimbursement facilities, bringing our interest cost down from 13% to 8.25%, and the related write-off of deferred issuance costs are reflected in this loss.

Interest expense is higher over 2013, primarily due to comps related to our Monetary Production Payments that we put in place last year, and reduced capitalized interest this quarter as our development projects were complete. This is offset somewhat by our interest savings realized from our new credit facility, which is, and again, an improved 500 basis points annual rate. We know that this is an area that has to be reduced, and we're doing everything possible to make an impact quickly. As a reminder, interest expense includes some noncash interest and debt amortization, which was $9 million for the quarter.

Letter of Credit fees, remember these represent charge on 2 Letters of Credit for decommissioning, the largest of which is on Alba. During the quarter, we implemented the tax relief put in place by the U.K. government with respect to decommissioning. And in February, we reduced our LC amounts outstanding to $90 million, down from $150 million at year end. This reduction in the LC amount, coupled with the refinancing of the LCs to the new facility in January for the lower rate, result in cost savings for our LCs of about $12 million a year.

As we announced in April, we reached a settlement agreement on our litigation with SM Energy. And as a result, we've recorded expense in the quarter of $19 million, which includes $6 million of a forfeited deposit, $5 million cash payment made at closing and a note for $4.5 million in expense for valuation of warrants issued.

Slide 7 shows the summary of all this, adjusted EBITDA. For the quarter, it was $59 million, which is up 31% over prior year quarter. While EBITDA increased over prior year, these increases are offset by higher interest expense, DD&A and a litigation of settlement expense resulting in adjusted net loss for the quarter of $27 million compared to $12 million loss in the prior year shown on Slide 8.

Looking at capital expenditures for the quarter, shown on Slide 9. Our direct oil and gas expenditures during the quarter were $10 million and were focused on the U.K., spending at Rochelle and infill drilling at Alba. We also spent $17 million on decommissioning at IVRR. While we have completion activities at Marcellus, after the carried costs, we have only spent $1 million of capital in the U.S. for the first quarter of 2014.

Now I'll turn to our financing transactions and liquidity. As we've told you, we're focused on working on the balance sheet during 2014. We're monitoring and managing our liquidity position closely. We ended the quarter with $55 million in cash on the balance sheet. Contributing to our cash balance was a portion of PRT refund for 2013 that we were able to accelerate and received $13 million in March for this. While the past year included a number of transactions gaining liquidity to execute on our projects, we have begun taking steps to reduce our costs. We did react this quarter to the unplanned downtime at Rochelle and closed on a private placement for $30 million. We issued $12.5 million in common stock and warrants and $17.5 million in convertible notes. We also -- the issuer has a 90-day option for a further issuance of an additional $25 million, which expires at the end of May, which we believe will be unexercised at our current market prices. This week, as I mentioned, we executed a third forward sale agreement for $22.5 million in return for a volume in excess of around 200,000 barrels from the North Sea production. Closing and funding on this transaction is expected in a week. The 2 forward sales that we executed in 2013 have been repaid.

We've achieved steps to date to reduce our costs of capital and delever. As we've mentioned to you in January, we closed on the $255 million senior secured first term loan. This has an interest rate of 8.25%, and it's a strip facility comprised of a term loan for $125 million and then an LC facility for $130 million. The net proceeds from these new facilities were used to refinance our existing 13%, $115 million credit facility and replace our 2 LC facilities, one at $120 million that was a 13% cost, and one at $33 million that was a 9% cost. Our new facility matures in November of 2017, which allowed us to push out the maturities of our existing facilities coming due in June of this year.

As I mentioned, our LC requirement has dramatically improved. During the quarter we implemented the tax relief put in place by the U.K. government with respect to decommissioning, and in February reduced our LC amount outstanding down to $90 million, down from $150 million at year end. The cost savings from the new facility, just under 500 basis points improved, combined with the reduced LC requirement, results in annual cash saving to us of $17 million. On deleveraging, we have delevered, repaying $13 million in Monetary Production Payments, since the inception of those facilities put in place a year ago.

Our continued cost of capital reductions and deleveraging plan includes the following: we know we have 2 large payments due on our Monetary Production facility, one coming in January of 2015 and April -- and the second in April of 2015, totaling $104 million. We are focused to ensure those payments are addressed. Our $554 million high-yield debt at 12% is our highest cost of capital, which is too high. The first call date is in a year. If there are ways to reduce this ahead of time that makes sense, we'll consider those options. Addressing our next maturities due in 2016 is also on our plate. There's 2 convert facilities that are due in 2016. We'll continue to monitor cash and liquidity, bouncing against deleveraging options. And I assure you, we're focused on many options to reduce our cost of capital and are considering these where they make sense to our shareholders.

Turning to guidance. Slide 11 shows you, as a reminder, direct capital expenditures for the year were estimated to be in the range of $60 million to $80 million, including $45 million in the U.K. and $20 million to $25 million in the U.S. And we also expected a $50 million decommissioning expenditure, primarily at IVRRH. We are not changing this guidance.

Production volume guidance. The second quarter physical production levels are expected to be in the 9,000 to 10,000 barrels of oil equivalent per day range. Again, this reflects downtime at Rochelle for April related to the Scott Platform issues and lower Alba volumes with the continued water injection issue. We will continue to give you guidance while monitoring the consistency of the Rochelle production and the timing of the repairs at the water injection pipeline at Alba. We plan to file our 10-Q at the end of this week, so we'll give you some more details on this discussion and on the numbers.

With that, I'll turn it over to Bill for concluding remarks.

William L. Transier

Hello, everyone. Thanks for joining us. Just a couple of comments and then we'll get to your questions. We've said it a couple of times already that it was a challenging quarter. Despite the challenges that we had, we still showed improvement in production, revenue and EBITDA. We also still believe that our performance should be a lot better than we showed you this quarter. But as we talked about, the challenges continued for us with the 2 unexpected shutdowns at Rochelle, which will have and -- which did have and will have an impact on our first and second quarter production numbers. On an ongoing basis, we still have to achieve better results from our core assets if we expect to reduce our debt and interest costs at the rate that we targeted over the next 2 years. As Cathy has already said, and so has Derek, we are working aggressively with the operators at Rochelle and Alba to capture improvements and to achieve the performance that we really expect from our assets.

Although we had good execution on the first step in our refinancing activity in January, we were forced to raise capital under duress in February to ensure we had sufficient liquidity to manage our way through the Rochelle valve shutdown issue. Raising the capital was the right thing for us to do as a company, but many were unhappy about the perceived dilution. Shareholders have spoken loudly with the reduction in our share price to roughly half of what it was at the beginning of the year. As a significant shareholder myself, I can assure you that this was the best of a very limited number of alternatives to make sure that we maintained our assets and continued to work through the issues so that we can see the performance out of our assets that we expect.

We also resolved the SM litigation. The settlement eliminates the uncertainty and risk to our business presented by litigation, as well as the ongoing expense of associated legal fees and defense. The settlement, in my view, is an important step to end the distraction and diversion of management time that was being spent on trial preparation and trial, which was scheduled actually for the end of last month.

Let me just say it simply, our focus in 2014 is to stabilize the production from our core assets. As I've said before, we have a concentrated set of assets in the North Sea. We don't operate our assets nor do we control the infrastructure we produce through. However, our assets deliver first-tier margins when they are operating, and we know they are capable of much better performance than has been demonstrated to date. We are working aggressively and proactively with the operators at Rochelle and Alba to make sure we achieve better and more consistent performance in the future. We also continue to accelerate the pursuit of our portfolio. As Derek commented on, we had active participation in the U.K. licensing round, probably one of the most involved licensing rounds in recent history in the North Sea. We expect results later this year. With respect to our bids, or early in 2015. With the license round over, we can now refocus on finding the right JV partner for our Rossini. Our goal still is to drill Rossini sometime in 2015. So the focus for the company is fairly simple. We remain focused primarily on achieving consistent performance out of our assets and on debt reduction and the reduction of our cost of capital. We had good success in January with the new term loan and procurement facilities, but that was just the first of a significant number of other steps we will need to make to create the proper capital structure for our company to successfully operate in the future. You can expect to see many things out of us as we work our way through the rest of the year.

Now I'll turn it back over to Kyle, the operator, to take some of your questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll take our first question from Welles Fitzpatrick with Johnson Rice.

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

With the increase in Telford, should we think of the kind of maximum throughput on Scott as below that 100 to 120 that we've kind of looked at historically?

Derek Neilson

Well the -- yes, we've always said that Rochelle production is dependent, one, on the capacity at Scott, and also dependent on the production from the other fields. The total capacity is as we believed it would be. Having said that, that we were very surprised as we were the partners in Telford of the success of the Telford well. It came in way above expectations, which has reduced the capacity available for Rochelle just now. This was unexpected. The Rochelle operator based their 2014 budget, the approved budget, was aligned with our expectations. And so the result from Telford means that we're currently getting less than that. We're far from satisfied with that. We are where we are today, but we are actively addressing these issues, both with the Rochelle operator and the Scott operator. And that can be addressed technically in terms of looking to increase the overall capacity of the Scott Platform, or also looking to increase the Rochelle share of that. Regardless, we expect the production from the Telford well, according to the operator's forecast, to decline towards the end of the year. So we would expect naturally to get more capacity or the capacity to increase as we go through later this year anyway.

William L. Transier

Welles, this is Bill. Let me just add a couple of things. In the 20 years that the Scott Platform has been performing, it hasn't had gas production from any of the other competing fields anywhere close to what we're seeing today. This was a surprise to us. We don't have an ownership interest in Telford. There's 2 other fields that flow through the Scott Platform, the Scott and Telford fields. Remember, when we built the Rochelle development, we added capacity, gas capacity, across the Scott Platform that we believe technically could get to 166 million a day. We are contractually committed and have a fixed capacity of no less than 60 million a day. And we've always thought that based upon the engineering estimates and what we knew from the operator, that we could reach about 100 million a day on an Mcfe basis. And frankly, we were pretty close to that in the -- when we had production starting last year. After the valve shutdown, this Telford well came on that we, once again, don't have an ownership interest. The operator has an 80% ownership interest in that, and that's some of the things that Derek's working on. As I said, I think that we should see better performance of this. We expect it to. I think the thing that everybody on the call should recognize is that we've had 2 fantastic wells come on and both have produced, both have produced at rates of -- constrained rates of 70 million to 80 million a day, and both have produced at 3,000 to 4,000 BOEs a day of liquids that we get very good operating margins on and very good commodity prices. This field will work, and we will get the production going forward. It's frustrating as the dickens for us that we are where we are, and we have not had the consistent production out of Rochelle we expect. But this is going to work, and it's going to work effectively as we promised the marketplace going forward.

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

Perfect. And then on the 2 potential farm-outs or JVs or what-have-you, can you update us on the timeline for the Rossini prospect and the timeline on the potential Colorado partner?

William L. Transier

Well, I'll let Jim and Derek add into this. But our goal is to have both of these in place this year and obviously move forward. Jim commented on we want to get back to pursuing the proof-of-concept in Colorado. So he's actively moving on that to move down the road and get that in place as soon as possible. I think what I tried to say in my comments on Rossini is that the peer group of companies in the North Sea is fairly limited. And the activity, albeit high in the licensing round, distracted folks from what we had quite a bit of momentum with respect to Rossini. There was also, as you might expect, a little bit of maneuvering in the licensing round in and around what we would do to protect what we consider to be a play in that Rochelle, Rossini area. And we were building partners and things like that. So the point is, is that now people are past that thrust, which all the bids had to be in on April the 25th, and we're back in action to try to get somebody in place in Rossini. I can promise you that we have active, ongoing and pretty intense conversations about Rossini and putting that in place. Our goal is to still get that JV put in place, to have somebody share a significant portion of our costs and to get this drilled and tested in the proper weather window in 2015.

Operator

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

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

So Bill, I'm just trying to figure out what type of, if any, recourse you do have with some of these? I understand how, again, that the wells have been certainly impressive. But to me, regardless of how impressive they are, if you can't -- if you have some downtime either at the well itself or, specifically, at the infrastructure, it's almost pointless to a degree. So I'm trying to figure out what kind of recourse, if any, you all have on -- at this moment?

William L. Transier

Well, Neal, just to be honest about it, it's part of what we deal with in the North Sea. I mean, we don't control the infrastructure, and when the operator has an incident on the Scott Platform, there's not a lot we can do other than monitor the situation and try to assist the operator in trying to get it fixed as soon as we can. I don't think there's any doubt in our minds that the valve situation was human error someplace, and we're pursuing recourse in those areas. That just takes a long period of time. I think for all of us, the best thing we can do is to try to observe the situation -- which I'm not happy with -- but observe the situation that we had a significant capital expenditure. We did a lot of work on the Scott Platform. As you know, I was really pressing to get production started up last year, but -- before the long shutdown period because there's always things that go wrong and need to be adjusted when you turn on a significant new asset like this. And I'm not trying to give any excuse, but I think some of that is what we're dealing with now. And Derek is -- and his team are all over these guys in trying to get improvement. We need to show you, Neal. You and I have talked about this at length. We need to show you better performance for you to have confidence in where we go. We -- I still believe these are good assets, but I haven't shown you the results on the scoreboard yet, and that's what we've got to do.

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

Definitely. I believe the assets are as well. I'm just wondering, I guess for the next quarter or so, how much certainty do you all have, I guess, how in-depth conversation do you have with that we know that the maintenance time is coming ahead another quarter or so down the line? And I guess the fear is, obviously, if maintenance -- if you've already guided to where you are now in the second quarter and maintenance ends up being more material for whatever reason, and we'll see even Bacchus is affected, I guess what sort of things do you have in place? Actually, I think Cathy talked about addressing the payments, obviously, early next year. So I guess, obviously, in a nutshell here, if maintenance ends up being more severe than expected, coupled with potential -- some weather. Again, what type of confidence we have to come up and pay those notes coming due early next year?

William L. Transier

Well, we're going to make it happen, Neal. Whether it's monetization of assets or doing something with the debt itself, we will get that done. We've never disappointed you on that end, and we're not going to start on that end right now. The -- when you look at the numbers, it still shows us having a fair amount of improvement in EBITDA for this year over last year. And if we manage our costs and we can end the year, the second half of the year, with strong performance, then we ought to be able to handle the things that are out there. If not, we'll deal with it in whatever ways we need to, to get there, and try to allow the shareholders in this company to get the benefit of the hard work that we've done over the years and move forward. So we're trying to show you that we had a lot of activity in the first quarter to try to get along that way. We had 2 new surprises in terms of the way the assets operate. But the shutdown periods that you speak about, Neal, in the third quarter this year, are much less than what they were the year before. And they actually don't deal with our facilities. They're really in the Forties Pipeline, which is downstream of our assets. So the one good thing about the Forties Pipeline is that that's Apache and they have the same motivations we do to get stuff done.

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

So it would be hard to perceive [ph] too much material on the maintenance, do you think, Bill, in the third quarter?

William L. Transier

Yes. I -- we have -- even last year when we told you about the long extended shutdown periods, we pretty much stayed on schedule with those shutdown timeframes and got the assets back on. So we didn't stretch too much out of that. The Rochelle was 55 days and we were pretty much right on track with that. And this time, the 16-day period that Derek talks about is related to the Forties Pipeline, once again, which is downstream from Rochelle. While it's shut down, we'll do some other work on the Scott Platform, but it's not really related to Scott in the first tense.

Operator

We'll take our next question from Steve Berman with Canaccord.

Stephen F. Berman - Canaccord Genuity, Research Division

Bill, assuming nothing else goes wrong at Rochelle or Alba and building in the downtime you know about in the third quarter, what could third quarter production look like? I mean, obviously, we've got to do a lot better than 9,000 to 10,000 a day. I'm not telling you something you don't already know. But what's kind of a range that we could be hopeful for if things get back to some level of normalcy in -- for Q3?

William L. Transier

Well, it should be an improvement over the second quarter. I hesitate to say right now, but we've always felt like that Rochelle, if it was producing at the budgeted levels that was 6,000 to 7,000 BOEs a day on a BOE basis, we will see the improvement that comes forward from the 2 new wells at Alba that are on production, as well as the partial water injection as they try to fix the water line, which is expected not, really, until the end of the year, and we'll see where that goes. But Alba should be producing on a net basis to us, 5,000, 6,000, 7,000 BOEs a day. And it's hard for me to predict right now because we haven't seen how these things have performed. But that -- and then Bacchus continues to kind of stay in a good range for us. And as Derek said, they're turning that first well into water injection and stuff. I'm not trying to be evasive, but I'm not going to try to put some number out there that we disappoint again. And I would tell you that as we see this unfold during the course of the second quarter, we'll update you on it. But we should see improvement and a fairly significant improvement over the second quarter subject to the shutdown periods and stuff that goes on. And then the fourth quarter should be a very strong quarter and getting back to the levels that we all expect this company to be producing at, at the beginning of this year.

Stephen F. Berman - Canaccord Genuity, Research Division

And what's the Bacchus number net to Endeavour?

William L. Transier

It's just under -- it's -- right now, it's just under 2,000 BOEs a day.

Stephen F. Berman - Canaccord Genuity, Research Division

Okay. And then a couple for Cathy. Pro forma for the SM settlement and the forward sale you just did. What's the company's current cash position? Or -- and anything else that's happened since March 31?

Catherine L. Stubbs

We ended with $55 million. We have made some payments subsequently on the SM, but we try to keep it in the range of $30 million, $35 million, and that's probably right around where we are today.

Stephen F. Berman - Canaccord Genuity, Research Division

All right. And what's the current share count, both basic and diluted, taking these same -- some of the events that have happened post-quarter into account?

Catherine L. Stubbs

Yes. One quick correction. We have not closed the forward sale and received funding yet. We're going to set the price and receive that in a week. So that number I gave you is without that forward sale. So we will draw in another $22.5 million once that's closed.

Stephen F. Berman - Canaccord Genuity, Research Division

Okay. And the current share count basic and diluted, just taking everything into account from all the financings, et cetera?

Catherine L. Stubbs

Yes. We're around 50 million at the basic and then the dilution from our converts and existing warrants are around another 25 million, 29 million.

Operator

We'll take our next question from Hassan Ahmad with Imperial Capital.

Hassan Jawed Ahmad - Imperial Capital, LLC, Research Division

So I'm just trying to figure out exactly what is your current production at each asset in the North Sea? If you don't want to give guidance, that's fine. But just, what's the current production? And then the second question is what's the rationale on the CapEx in the U.S.? I mean, obviously, liquidity is at a premium right now, so if you're spending $20 million to $25 million in the U.S., wouldn't it be better served if you stay that cash on the balance sheet? Or what are your thoughts on that?

William L. Transier

First of all, we're not spending $20 million to $25 million in the U.S., we spent $1 million. So that's what we just said. And so we're not spending that, and we've used that guidance as to what needs to be spent in the U.S. subject to joint ventures. And we did the same thing last year. We gave the guidance of $10 million to $30 million last year. We spent $7 million. I think our goal is to have a good partner with a common interest in these things to try to move these assets to proof-of-concept. If you move them to proof-of-concept, it gives you a lot more collateral in terms of what you might do with those assets going forward and how we might move down the road. So to say that we're spending money in the U.S. to the distraction of debt reduction and stuff is not really true. And in fact, we didn't spend much in the U.K. this time, other than the decommissioning cost that we had to spend. So we're managing capital pretty tight.

Hassan Jawed Ahmad - Imperial Capital, LLC, Research Division

Okay. And your current production at your assets?

William L. Transier

I think we just went through that. The Rochelle is producing today at 65 million plus about 3,000 BOEs a day. So that's roughly just short of kind of 6,000 BOEs a day, I think, net to our interest, when you get to that. The Alba is producing just short of around 5,000 BOEs day, but we think it's improving. And Bacchus is producing at about just short of 2,000 BOEs a day. And as we said, we're putting water injection on that. So...

Hassan Jawed Ahmad - Imperial Capital, LLC, Research Division

And what do you think the water injection will allow you to get to?

William L. Transier

I can't say until we see it work. But we've put that first well that was put on production in May of 2012 on production. I mean, into -- it's supposed to be turned to water injection this quarter, as Derek said. And then we'll see how that performs. By the time we get to you next quarter, we may be able to give you some indication of how the stimulation works. But we know, as we've always said about Bacchus, you've got 3 panels there, they're pressure-connected. The middle panel and the west panel have been the best producers for us. This well had always been intended to be a water injection well. It overproduced our best expectations, and we're a year plus later in turning it to water injection than we were before. I think once we turn this on and we see how it's stimulated, will tell us much more about the overall recovery rates from the reservoir in total. So we're excited to see what it is, but I can't tell you until we see how it performs.

Operator

We'll take our next question from Joshua Gale with GMP Securities.

Josh Gale

I had some questions about the first -- second quarter guidance relative for -- to the first quarter, but it looks like you answered most of those. So just a question about liquidity. If you come in line for second quarter and do the best you can with the seasonal challenges in the third quarter, do you think you will need to raise incremental capital in advance of the September coupon payments on the bonds? Secondly, the MPP maturities, do you believe that you can refinance and extend those? And at this point, do you think that is the most likely course of action?

Catherine L. Stubbs

Yes. I think that as we've talked about these assets, they will perform and they can perform, and with those cash flows, we're on track to meet our obligations on our interest payments. We're monitoring it closely. The MPP payments, we'll have excess cash flows as the time builds up, and we will use excess cash flows or consider any kind of other options that we need to make those payments or extend those out in the first half of 2015.

Operator

We'll take our next question from Jame Donath with Magnolia Road Capital.

Jame Donath

Given the various production outages that we've been hearing about on these calls for some time, that's obviously put a major dent in the company's cash flow picture. Just building on the response to Josh at GMP and the earlier comments to Neal Dingmann at SunTrust, can you walk through, for this group, with some greater specificity what the strategic or financing options are? Because, clearly, the company is going to be coming up on some significant obligations over the next 12 to 24 months, and it just doesn't seem, given these ongoing outages, that the company is going to be generating the cash flow to meet them.

Catherine L. Stubbs

Sure. Well I guess just as a reminder, we -- of kind of some things that we've done to draw on liquidity. We've been, since a year ago, when we were hit by a storm at Rochelle project there, we've been drawing liquidity. We raised $175 million throughout the end year on MPPs with a reasonable kind of embedded cost. We raised 2 forward sales for a total of $45 million, bringing in capital. We've reduced our LC obligations and made some savings as we refinanced our credit facility. We also have some G&A savings that we're realizing that we've told you. We have some upside potentials that we don't count on. We are pursuing Rochelle insurance claims and things like that. But we will obtain the liquidity we need to run this business. I guess production is the driver of our cash flows. So we're monitoring that very closely. And you saw on the first quarter, we reacted when we did have some production issues and went out to get some additional capital from the market. Evaluating all the alternatives out there, there were few alternatives, as Bill mentioned, and expensive alternatives, but we executed and did receive additional liquidity. We'll get some liquidity from the forward sale I mentioned. So we're continuing to provide that while monitoring the production from these assets which drive...

Jame Donath

I -- Cathy, I understand all that. I guess I'm not talking about ongoing liquidity to fund day-to-day operations. I'm talking about how the company's going to address some of its big obligations coming up, whether they be MPP payments or bond maturities.

Catherine L. Stubbs

So right. So leading into that, these savings kind of help with building the cash to meet those obligations. We are considering, as I mentioned on the MPPs, looking at how we'll meet those obligations with the excess cash flows or refinancing options. Bill mentioned that we may do dispositions or asset sales where we need to do. I mentioned that the highest cost in our structure is our high yield. We have the first kind of call date at first quarter of next year, so we're looking at options there. If we can do something sooner to bring savings to the shareholders, we will do that as well. Our 2016 obligations need to be addressed, and we've already started working on that. We have 2 convert issues that are coming due in 2016. We haven't executed or closed anything, so I'm not at liberty to say. But I just -- assured that we are addressing things. There's a lot of interested people in helping us reduce our cost of capital and delever, and we're considering all these options.

William L. Transier

Yes. Listen, everybody on the call, and we're about out of time, but we understand the best thing we can do for the shareholders is reduce the debt load on the company and reduce the cost of capital. We're focused on that singularly. But obviously, we got to make sure that these assets perform at the level that we expect them to. And we're as frustrated as you guys are on the phone, but we still think that these assets perform at a high level, and they do spin off good margins when they're operating. The capital structure is something that we will work through and it will benefit the shareholders as we move down the road.

K. Darcey Matthews

Kyle, thank you.

Operator

Okay. This does conclude today's conference call. Thank you, all, for your participation. You may now disconnect.

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