W&T Offshore, Inc. (WTI) Q4 2014 Earnings Report, Transcript and Summary

Welcome to the W&T Offshore, Inc. fourth quarter 2014 earnings conference call. At this time all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host Lisa Elliott.

We appreciate you joining us for W&T Offshore’s conference call to review results for the fourth quarter of 2014. Before I turn the call over to the company I have a few items to point out. If you wish to listen to a replay of today’s call it will be available in a few hours via webcast by going to the investor relations’ section of the company’s website at www.WTOffshore.com, or via recorded replay until March 12th. To use the replay feature call 201-612-7415 and dial the passcode 13599736. Information reported on this call speaks only as of today, March 5, 2015 and therefore time sensitive information may no longer be accurate as of the date of any replay. Please refer to our fourth quarter 2014 earnings release for disclosure on forward-looking statements. At this time I’d like to turn the call over to Mr. Tracy Krohn, W&T’s Chairman and CEO.

Thanks for attending our fourth quarter 2014 earnings conference call. Joining me this morning is Jamie Vazquez, our President; Danny Gibbons, our Chief Financial Officer; Tom Murphy, our Chief Operations Officer; and Steve Schroeder, our Chief Technical Officer. Yesterday afternoon in a detailed news release, we announced our fourth quarter results, our year end 2014 reserves, and our 2015 capital plan and guidance, so as is our custom these days, we’ll ask that you refer to that press release for the numbers and we’ll primarily focus on prepared remarks on key operations and plans for 2015 and that will allow time for your questions. As you saw in the release, we had good operating results in the quarter as production of oil, NGLs, and natural gas all came within our guidance. Operating expenses also came in as expected except for LOE which was a bit lower due to less work over activity than planned and the beginning of reduced cost. You’ll note in our LOE guidance, that we expect cost to continue moving downward. We produced on average 50,000 barrels of oil equivalent per day in the fourth quarter 2014 which was 7% above our third quarter production. For the full year we produced an average of about 48,300 barrels of oil equivalent per day which was similar to last year. We reported year end 2014 proved reserves of approximately 120 million barrels of oil equivalent and we replaced 113% of our 2014 production. The components of our proved reserves were made up of 52% crude oil, 13% NGLs, and 35% natural gas. Much of our proved reserve additions in 2014 came from our drilling activity at our Yellow Rose field in the Permian Basin and from our Dantzler field in the deep water Gulf of Mexico. I’d like to point out that although we booked some reserves for Dantzler in 2014 it was only a portion of what we expect to book once we move this field into production, so our current proved reserves don’t reflect anywhere close to the additional contribution we expect to ultimately receive from Big Bend and Dantzler once we get these fields online in 2015 and ’16 respectively. We also added about six million barrels of oil equivalent from acquisitions which included interests acquired at Neptune, Ewing Banks 910, High Island 129, and Fairway fields. Although our operating results came in as expected, our financial results were affected by lower realized oil and NGL prices which were about 25% lower than last year. Our EBITDA was $100.3 million in the quarter and $573.2 million for the year, and our EBITDA margin was 60% for the year down only slightly from 62% last year. Of course, at current prices our financial results are affected and we’re responding with a much reduced capital plan and an aggressive effort to reduce costs and expenses. Having been through several of these cycles, we know the importance of making quick and decisive adjustments to our strategic plans and we’re taking a conservative approach to our use of capital until economic conditions improve. When commodity prices decline quickly, the cost of goods and services typically decline as well but more slowly. The ability to be patient and demonstrate flexibility is really important under these conditions. We’re the operator of most of our production and the majority of our lease acreage is held by production. We have the ability to minimize our drilling budget, work with our service providers to reduce costs, and wait for commodity prices and margins to improve. When conditions are right, we have the flexibility to reinitiate a more robust drilling program. For now, we’re focused on our highest impact projects and on wells in which most of the investment has already been made. We established a 2015 budget of $200 million of which $169 million is for deep water projects which are primarily already in progress. All of these are high quality projects and we remain very enthusiastic about moving forward with them even in current conditions. Development operations are on schedule to bring our deep water discoveries of Big Bend and Dantzler on production as planned and we’re making good progress to our ongoing projects at Medusa and Ewing Banks 910. The remaining budget is allocated to the Gulf of Mexico Shelf and Permian Basin operations. Those funds are dedicated to completing certain operations that were already underway or reaching a stopping point. We are working with our service providers on a daily basis to bring down costs, but we may choose to delay the completion operations on some of the Permian Wells while we work to reduce completion costs to optimize our total completion economics and obviously, most of the cost of the wells over there has to do with the completions and fracking of [indiscernible]. Our borrowing base is $750 million and the current amount outstanding on the revolver is around $460 million, so liquidity is about $290 million. The spring redetermination is coming up in April and our new borrowing base will be set at the end of that month. Our liquidity is strong and we want to make sure that it remains that way, that’s why we’ve reduced our capital expenditure program and are suspending our dividend. Cost of goods and services need to get much better in line with the current commodity price environment before we deploy additional resources to new projects. We think that’s the right thing to do for all of our shareholders. Cost of goods and services are already moving down pretty quickly, so margins should improve and move more in line with historical levels. Although we’ve reduced our capital plan to the less than a third of our 2014 capital spending, we still expect production to be in line with or even to exceed our 2014 production levels. This is because of contributions from various projects and additions to our portfolio including the Neptune field which will contribute for the entire year, two new wells drilled in 2015 at Medusa which will add significant volumes, and new production from our Ewing Banks 910 expansion project which will begin to add volumes in the second half of 2015. Additionally, material rate contributions from Big Bend in late 2015 will add measurably to our exit rate this year following shortly after by the two Dantzler wells scheduled to come online late in 2015 or early 2016. Let me update you a bit more on projects that we have in our 2015 plan. At Big Bend we are on schedule to tie in to the nearby Thunder Hawk production platform. Both of the Dantzler wells have been completed now and are ready for the installation of new deep water infrastructure which will occur over the coming months. Both of these wells will also be connected to the Thunder Hawk platform. Big Bend and Dantzler will together be referred to as the Rio Grande Loop which in aggregate is expected to contribute 8,000 to 9,000 barrels of oil equivalent per day net to W&T’s interest. At Medusa, we’re drilling two exploratory wells targeting multiple stacked oil sands. As a reminder, it’s a deep water field Mississippi Canyon 538 and 582 in which we acquired a 15% interest in late 2013. It did fit our acquisition criteria perfectly as a quality perfectly as a quality producing field with excellent upside potential. The first well, the [SS6] reached total depth in January of 12,500 feet and encountered over 180 feet of net pay. The second well, the [SS7] is currently drilling. We expect to perform completion operations on both wells in the second quarter and we should be able to commence production in mid-2015. We expect these exploratory wells to move previously unbooked reserves into the proved reserve category. The platform rig is currently on location drilling the A5 sidetrack well at Ewing Bank 910. The first well in the program could initially include one to three wells in 2015. The A5 sidetrack is expected to be completed and put online in the second quarter. The second well the A8 could be put on production in the third quarter. We’re highly enthusiastic about this project based on brand new seismic data and analysis that indicates it has similar characteristics to our Mahogany field. We’ve identified several additional targets beyond the first two wells and believe the resource potential at Ewing Bank 910 could be quite significant. We could opt to propose a third well this year with our joint interest operator, but we’ll keep you posted. We suspended operations on the A18 well at Mahogany and have opted to instead focus on analyzing new data we recently obtained over the field and watch the performance of the T-Sand producing from our A14 well. Since we brought the well on in mid-2014 it’s produce well over what we had initially booked as proved reserves. The steady bottom hold pressure and steady production rates. Current gross production is around 3,000 barrels of oil equivalent per day. While we’re waiting for the cost of goods and services to come down, it’s a good time to focus on field analysis and identify additional upside opportunities. At our Yellow Rose field in the Permian Basin at the end of the year, we had 10 wells awaiting completion, six of which were horizontal wells. Our vertical program supported our strategy to hold a vast majority of our Yellow Rose acreage by production which at year end was 90% HBP. Throughout the year we benefitted from a large amount of data coming from the industry regarding optimum drilling and completion techniques and the productivity of various formations. Our 2014 drilling success in two new horizontal benches allowed the company to move funds from our perspective resources or exploratory volumes into proved reserves as we achieved successful wells in both the Wolfcamp B formation and the lower Sprayberry shale. Our reserve position in these two formations is expected to grow as we’ve only booked a small number of wells based on our initial success. We’re pleased that our well results have continued to improve with our most recently operated horizontal wells averaging peak rates of around 1,000 barrels of oil per day and the rates normalize for a 7,500 effective lateral length. We’ve also partnered with an adjacent operator to drill on our acreage with excellent results. The most recent non-operated horizontal well tested in the lower Sprayberry shale in Andrews County and achieved a peak rate of 1,709 barrels of oil equivalent per day, that’s 91% oil or 224 barrels of oil equivalent per day per 1,000 feet of lateral. While we have a high degree of confidence in the quality of our acreage, we plan to leverage the fact that many of our opportunities in this core area are discretionary creating an opportunity for W&T to optimize the value from the fields. Through quality drilling and completion practices some of our latest wells are performing in the upper tier of well performance within the entire basin and allows us to be selective in the short term and at the same time be positioned to accelerate drilling activity as our operating margins improve. In the short term, we will reserve our capital and continue to closely watch industry activity and wait for margins to improve before reinitiating our program. We’re very excited about the performance in our newest horizontal bench and are equally excited about several other benches we have not been able to test and derisk but have been tested by others. Our objective is to add these new benches into our multiyear plan for the fields as we continue to develop and monetize each new formation and bench. We believe that our deep position in the Midland Basin allows for higher thermal maturity and higher pressures which increases the potential for recovery. To date we’ve proven up three horizontal formations in our acreage position. As we test and add new horizontal formations we will effectively multiply our drilling inventory considerably and we think we’re well positioned to realize substantial value for our shareholders. With that operator, we’re ready to take questions.

[Operator Instructions] Your first question comes from Neil Dingmann – SunTrust Robinson Humphrey.

Three questions, first just to hit on the last part that you followed up on, on Yellow Rose you certainly mentioned a large amount of HPP property and now you certainly have much more well control there so wondering how you think about it? I think in the press release you said maybe around $30 million? Maybe half would go to Yellow Rose and the other half or so – I don’t know if it’s half but of the $30 million some would go to the Gulf Shelf and some would go to Yellow rose, how much do you anticipate potentially spending there and of what you spend there would it mostly be horizontal wells this year or vertical?

I would expect most of it to be horizontal activity and of course, we’re still constantly evaluating our operating margins there. Cost of goods and services is coming down right now, we’re seeing good movement in a southerly direction on those costs, but right now we just want to focus on reducing costs and analyzing where we’re going to drill at next and how we’re going to carry out our longer term program.

Although I would certainly not [indiscernible] strapped for cash in the near term, is there a price these days in the next month, next quarter, where you’d consider selling Yellow Rose or is that just something that’s not in the plans yet?

There’s a price at which I would consider selling every asset in the company. That’s always a possibility. Every day the company shares go up for sale and assets go up for sale if somebody comes with the right number, so that’s never been an issue it’s not a pride of ownership thing. But right now, we’re afforded the luxury of looking at a longer term picture without short term pressure on production. We’re trying to look at this thing as a 30 to 40 year property and we’re going to have swings in prices and everything, but the good news, if you look at it from a half full perspective is that we’ll now be able to source materials in bulk at lower prices which is what we’ve been telling the market we were getting ready to accomplish in a development program. We’re about well 15, what we thought was a 15 to 20 well horizontal program so that we could analyze what we’d need for the future so hopefully that will make sourcing materials cheaper and we can prepare for the long run.

Last one for you, I know you mentioned the [indiscernible] lease just as far as spending, just really going after the development of those projects you’ve already started and I guess my question is looking at either Big Bend I know I think gross or so you guys estimate a peak rate of over 22,000 barrels or Dantzler I think you guys were thinking around 30, is that just the initial wells? I guess when I’m looking at those projects are there step out wells, are there different things that you would consider that would boost – again, it might not change obviously, reserves dramatically initially but could actually add – given those kinds of cash flow rates are there additional sort of step out wells or something like that that you could add around some of these mega projects?

The answer to that is certainly yes and what we decided to do with our operator there is put the wells on production, gather production data. We do have wells on production. We have room in the infrastructure to add a well at each one of these projects, as I recall, so that is the plan. We’ll wait and see what production characteristics are but we’re actually with the productivity of the wells we have, we’re a little bit limited at Thunder Hawk right now.

Is it a takeaway issue on any of those or it is something else?

It could be. Right now I think, as I recall, it’s about 55,000 barrels a day throughput that we can achieve with an issues of production and we may be able to increase that later on, we’ll have to see what everybody else is producing across the platform, where pressures end up, and what the producing characteristics of the wells are. We expect both of these fields to expand.

Your next question comes from Richard Tullis – Capital One Securities.

Looking at the cap ex for 2015, the deep water allocation, what’s a rough split out of that cap ex number by project?

We probably have that number, I don’t recall the number right off the top of my head. Most of it’s going out in the Gulf of Mexico to deep water and a little bit to the Shelf, but most of it is to the deep water. I think I gave those numbers earlier.

Maybe another way to ask it is how much is allocated for Big Bend and Dantzler in 2015 to get those projects on?

It’s about $100 million.

What would be your expectation for facilities and asset retirement obligations cap ex in 2015 and maybe even looking out to 2016 as well?

We’re working on those numbers now. Probably around $30 million to $35 million for 2015. I’m not sure about 2016 at this point.

How quickly do you expect Big Bend and Dantzler to ramp up to that 8,000 to 9,000 barrels a day net number that you had referenced?

I would expect that from start to finish it would be somewhere around 60 to 90 days. I expect Dantzler to come on second, Big Bend will come on first and then we’ll level out the production, but start to finish to get them all online I would probably assume around 60 days. It could be a little longer, it could be a little less, but I would assume around 60 days.

Roughly how much proved reserves has been booked thus far for Big Bend and Dantzler on a combined basis?

We had that around six million for Big Bend and Dantzler. That’s booked proved reserves.

Are you planning to participate in any more lower Sprayberry horizontal wells with your partners in 2015?

I’m not sure. I think probably there may be one or two wells and I just don’t remember.

Then just lastly, what was your working interest in the UL Mason well, the number two?

It’s about a third.

Your next question comes from Noel Parks – Ladenburg Thalmann.

Just a couple of things. Continuing on the UL Mason well, that was your first lower Sprayberry?

No, it wasn’t our first lower Sprayberry. I think we’ve had two other wells in there so far.

Looking at the deep water program with the lead time and everything, I’m not used to thinking much about any changes as far as costs once you get rolling, but as a practical matter do you see, especially in the non-operated stuff, any potential for I don’t know if there could be any compromises on day rates or anything given how tough the oil environment is, any thoughts on that?

I think everybody is focusing on reducing costs. Certainly, our operating partners as well. We see it in the cost of goods and services. The first place you usually see it is not with the drilling rigs or completion rigs because you’ve already made a contract with them. The cost of goods and services lag is about six to nine months before we get back to a normal operating margin. I like to tell people this and I don’t know whether people believe me or not, but our margins at $30 oil were the same as they were at $100 oil. Operating margins for us tend to be around 60% EBITDA margins so once things level out then that’s about what it gets to be. But I would expect our outside operators, like us, to be focusing on the things that they can affect immediately. A lot of that has to do with transportation, boats and helicopters, that’s our second largest cost behind the rig cost.

As we look at this oil environment, if you look into second half of ’15 and into your 2016 planning, how different do things look as far as where you deploy your capital? Say if we’re looking at more of a longer term $50 oil deck six months from now versus say $60? Kind of sort of in that $10 range what projects have the biggest inflection point?

That’s a really good question, but again remember, that’s a function of EBITDA margins so while the nominal dollars may be less, what we want to focus on is getting back towards a normal margin rate so that’s the biggest thing. Even though oil is at $50 a barrel it’s really a question of what your margins are. Then, if oil prices fall then we’ll make adjustments to that and I would expect that what you would see and continue to see is a reduction in the rig count. I think that’s a very important factor. I think you have to pay attention to that particularly as it relates to oil production because it’s so much more valuable. The reality is as the rig rate continues to fall you’ve set yourself up for at least a bottom and a potential for going up quicker. The faster the rig rate falls the more likely that you have stabilization of upward price pressure.

The last one for me, as far as the expenses in the guidance, just looking at LOE looking at the first quarter run rate compared to the full year, does the guidance anticipate or include cost savings as sort of a foregone conclusion or are you sort of conservative for now with the potential for maybe the year total to look a little bit better than the first quarter run rate?

Again, we think that’s a function of oil prices so that’s our best guess that we’ve given you right now. Hopefully it would be less than that but if it went up then we would expect that would be a function of rising crude prices.

Certainly, the middle quarters of the year is kind of a work in progress as we sort of see how things unfold?

I think we’re moving pretty quickly to reduce prices as much as we can and I think the service provides understand that and the way it works is it has to come from our direction first because if you don’t ask you don’t get and that’s a fact. Then, they have the same obligation with their suppliers, so they have to run it down through their suppliers too. We have our entire staff focused on getting this process implemented as soon as possible.

Your next question comes from Patrick Rigamer – Global Hunter Securities.

You talk about the flexibility in the capital spending budget and just curious if we do see a recovery in prices later in the year where would you begin to add capital to the program?

That’s a really good question. We’d have to look at what the margins were in the different fields in different areas of the time. I don’t really know that I can fully answer that question. I would expect to first work on the things that had the quickest payout so that’s going to be a function of what the cost of goods and services are going to be. We’re making good progress in all of these areas Patrick and I think that’s probably indicative of everybody realizing that they have to get back in line.

Then Dantzler, it seems like maybe that’s moving a little bit faster than anticipated if I’m reading that correctly? I think at the last update it was 2016 first production and now it’s potential to start late 2015, I’m just curious what’s driving that and maybe what’s the critical path here that could kind of flex that into 2015 or 2016?

Critical path are long lead items. I think we’re having some pretty good luck with long lead items. The next critical path will be installation of the loop and the umbilicals to manage that. Those are the things that are driving the completions of those wells at this point in time because the wells are already completed. We’re just doing the gathering part of it now.

Then the last one for me is you guys are always active in the A&D marketing, I’d just certainly appreciate your perspective on where the market is now and how W&T fits in with that?

There’s always and A&D market whether prices are up or whether they are down. This is an excellent question by the way, thank you. I know that people think that when prices go down that that’s the best time to go out and buy production or do acquisitions, well the acquisition side of it is a little bit tougher. People dig in and they try to hold onto what they have because they’ve worked hard to get it so there’s a little bit of an emotional response there. Secondly, maybe the acquisitions are more difficult to do but the merger side of it becomes a little bit more active in these lower price environments. Then it becomes a matter of how you can handle debt, what your liquidity is. I do see a lot of money on the sides looking at this and figuring out what they want to do and how they want to perform and I expect you’ll see a lot of activity on land. More activity on land than you would offshore.

Does W&T have a preference as far as land versus offshore in this environment?

No sir, we’re just in business to make money.

Your next question comes from Gail Nicholson – KLR Group.

Looking at the cost savings, do you think you’re going to see more cost savings onshore versus offshore or do you think it will be pretty similar across the two regions?

That’s a really good question. The first thing that we see offshore is a reduction in the transportation costs for boats and helicopters which can be substantial. That’s already begun, we’re having good success with that. The next thing that we think about is of course, insurance and labor costs, and the costs for ancillary equipment that we need to run the operations and then lease operating expenses, which are all coming down pretty quick in the Gulf. I don’t know that I can say that the Gulf is coming down quicker than it is onshore because there’s a lot of rigs being laid down so those costs are coming down pretty quickly as well. One of the things that we notice is of course, rig costs onshore going down very rapidly because they don’t have the kind of longer term contracts that you need for offshore, so the onshore rig costs is coming down very quickly. Transportation costs offshore are coming down quickly as I mentioned, but also we’re seeing some flexibility with the cost of completions, and fracks, and everything else out in West Texas.

With the potential rig rates offshore coming down and you guys have plethora of kind of prospects and opportunities in deep water, is there any thought to potentially locking in a long term rig to do deep water projects in the Gulf of Mexico in this current environment, hoping there is a recovery? What’s your thoughts there?

There is that possibility and certainly when we get into these lower price environments you start to see the likelihood of longer term contracts both for rigs and transportation. In higher price environments nobody is really willing to lock in longer term contracts, but as we get into this lower price environment longer term projects become more intriguing as a hedge.

Looking at the potential for a third well at Ewing Bank, I’m assuming that will be similar cost wise around $20 million, will that be additive to the $200 million budget or would you realign funds if you decide to drill that third well?

I think we’d probably look at that as an addendum.

Then just one quick one. Lastly, the dividend being reinstated is that a combination of improving oil price environment as well as reduced service cost or is it all about kind of margins and where your cash flows are throughout the year?

It’s a kind of all of the above approach. We certainly want to return the dividend. I certainly want to return the dividend, that’s how I get a lot of my income so I’m motivated to do it, but at this point in time it just makes more sense to suspend the dividend until we get back to a normal operating environment, cost of goods of services, and a little bit more predictability.

Your next question comes from Michael Glick – Johnson Rice.

Just curious to get your thoughts on hedging just particularly as start to look at 2016?

2016 is a little bit further out than I think about right now. When you’re trying to avoid the alligators you’ve got to think about whether you want to worry about draining the swamp. But at this point in time I don’t really have any predisposed desire to hedge into 2016. I think the likelihood that it goes up is greater than the likelihood that it goes down as far as pricing is concerned. You may see some temporary bottoming out, further bottoming out, I don’t know. Again, if I knew I would have made different preparations and been in a different business. The reality is we’re in pretty good shape for liquidity, this company is right now. Of course, that could change if prices go down and continue to stay down. I think everybody else is in the same boat. We’re not desperate. We use hedging as a tool to protect the things that we need to protect. Right now we think we have pretty good liquidity. If that changes then we could think about doing something different later on. I don’t know that I necessarily need to go out and hedge anything at this point in time.

Then just on the revolver, any expectations to where that borrowing base goes post spring redetermination?

We’ve certainly tossed it around in our shop. I don’t think we’re ready to talk about that yet. I think we just take a little bit of a wait and see effort right now.

Do they give you much credit for Big Bend or Dantzler?

I think we kind of answered that already in that we have a certain amount of proved reserves and that we have more potential there, but beyond proved reserves banks don’t give you a whole lot of credit for probably and possible reserves or exploratory reserves. They’re more proved reserve oriented in their borrowing basis and that’s how they lend. That’s why their interest rates are so much lower, because they’re always the senior secured lender.

Then I guess I’ll just ask about 2016 one more time. I guess the kind of current strip with Big Bend and Dantzler coming on line you’ll have a pretty significant increase in year-over-year cash flow and your capital commitments will decrease pretty significantly. Just curious what you’re initially thinking in terms of capital allocation?

We’ve already decided what we’re going to allocate for capital in the deep water and it’s $100 million something and about $100 of that goes to Big Bend and Dantzler. I’m sorry ’16. I don’t have a forecast for 2016. Most of that capital allocation that we see right now for 2015, I think as we come on line we’ll make some judgments going forward. I would hope to have the quality problem of having to worry about what we might want to spend in 2016 to expand the program, but I think that at this point in time both us and the other operators and non-operators are thinking that we’ve done the right thing in putting these wells on line as soon as we could and gathering up production data rather than going out and doing a multibillion dollar development program with structures. We chose to [indiscernible] complete these wells over to Thunder Hawk and add to them as we thought it was necessary and so that is just what we’re going to stand by and see what happens with what we’re doing with these wells as well as looking at other opportunities to help us build inventory.

[Operator Instructions] Your next question comes from Richard Tullis – Capital One Securities.

Looking at year end ’14 production, what do you estimate your Gulf of Mexico base production decline to be?

Normally from existing formations we see about a 15% to 20% annual decline. As far as Big Bend and Dantzler we don’t expect that, we expect lower decline rates. We think these are big fields so that’s how we look at it right now.

With Big Bend and Dantzler coming on line by the beginning of 2016, those are most oily projects, what do you think your oil percentage of total production could be by then versus say the 40% in 4Q?

I would think our percentage of production goes up. I don’t have really an accurate handle on that because we’re not sure exactly when we’ll get back to normal EBITDA margins but most of the stuff we’re working on is oily in nature just by the virtual of the fact that it’s just much more valuable.

Last question, you had a number of horizontal Permian wells waiting on completion as of the time of the press release and some of it I guess is going to wait for lower well cost or completion costs. How do you see the timing of that working out over the course of the year? Do you expect to have all those wells on line by year end ’15?

I don’t know if I can say that or not. Again, we think the lag period on the cost of goods and services is around six to nine months to get back to normal EBITDA margins. Internally, I think we’ll get there a little bit quicker but traditionally it takes about six to nine months so I’m a little bit reticent to say it’s going to be two months, or three months, or four months, or anything like that. But I think the way I look at it is, is as soon as we get back to normal EBITDA margins we’ll go back to work.

There are no further questions at this time. I would now like to turn the floor back over to Mr. Krohn for closing remarks.

I’m done. Thank you very much, we’ll talk to you next quarter if not sooner.

Ladies and gentlemen this does conclude our teleconference for today. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.