Connacher Oil and Gas Ltd. (OTCPK:CLLZF) Q2 2014 Earnings Conference Call August 14, 2014 10:00 AM ET

Operator

Good morning. My name Rob and I will be your conference operator today. At this time, I would like to welcome everyone to the Connacher Oil & Gas Limited Second Quarter Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions)

Thank you. Mr. Chris Bloomer, CEO, you may begin your conference.

Chris Bloomer

Thanks very much Rob and good morning everyone, welcome to our call, and we appreciate your time in participating. I have with me Greg Pollard, our Chief Financial Officer; Merle Johnson, our Chief Operating Officer; and Jesse Beaudry, our Vice President, Marketing and Logistics.

The purpose of this morning’s conference call is to discuss Connacher’s second quarter 2014 financial and operating results and to provide an update on our business and operations. At the end of the discussion, we will open the lines up for question-and-answer period.

I will now run through our forward-looking information. We caution all participants that certain information provided during this conference call constitutes forward-looking information, specifically forward-looking statements we made relating to financial results from operations, near-term impact of capital projects on production, future development of SAGD+ process commercial project at Algar and the mini-steam expansion at Pod One, and the funding, timing and anticipated impact thereof, future in-fill well drilling activities and the anticipated timing of production there from, future production in the timing thereof with expectations regarding future operations and the amount of the corporations bitumen to be marketed by rail in 2014 and the anticipated impact thereof on bitumen netbacks and the sustainability of the diluent blend ratio reduction.

Following forward-looking information involve significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include but are not limited to the Term Loan Facility that may not provide adequate funds to fund the company’s growth capital program. Additional risks and uncertainties relating to Connacher and its business and affairs are described in further detail in Connacher’s Annual Information Form for the end of the year, December 31, 2013, which is available at www.sedar.com.

I just have some initial comments. I think it’s fair to say that we have disclosed or we have reported six quarters of continually positive operating results. I think that is something that we’re certainly proud of.

Overall, this quarter we are pleased with our operating performance. During the first half of 2014, production continues to increase as the impact of our 2013 capital plan kicks in at Pod One. We’re also pleased that production at Algar has remained steady. The closing of our $140 million first lien Term Loan Facility in the second quarter will allow us to maintain our growth capital momentum for the remainder of 2014 and 2015.

Drilling, completion and tie-in of nine new infill wells in the first half of 2014 at Pod One were extremely well and demonstrates our ability to deploy capital efficiently and effectively. The project met schedule and was on budget. We expect to see the initial production impact of these wells in the second half of 2014.

Operating costs were higher in the first half of 2014 due to higher – or primarily to higher natural gas prices, the impact of higher fluid handling costs from the new wells and several unplanned events. We expect these costs to be moderated in the second half of 2014.

For non-energy costs, we are implementing initiatives to manage and to reduce these costs where we can. Our near-term gross capital initiatives, in addition to the nine new infill wells include the implementation of SAGD+ at Algar and the mini-steam expansion at Pod One. These two projects will have an impact on the near-term production and operating capability as well as our future development plans. These are key strategic projects for the future development of the Company.

Our Marketing and Logistics results continue to ensure that we move our production efficiently and to high value markets.

I would like to turn the call over to Greg Pollard, who will discuss Q2 financial results.

Greg Pollard

Thank you, Chris. Good morning, everyone, and thank you for participating in this call. I would like to highlight the following with respect to Q2 2014. As previously announced, the company closed its Term Loan Facility for the aggregate principal amount of CAD$128 million or CAD$140 million. A portion of the proceeds were used to repay outstanding amounts under the credit facility and the remaining proceeds will be used to fund the Company’s capital program and for general corporate purposes. Concurrent with the closing of the Term Loan Facility, the Credit Facility was reduced to $30 million.

Revenue, net of royalties, was $116 million for Q2 2014, an increase of 5% over Q2 2013, primarily due to higher sales volumes. Adjusted EBITDA in the quarter decreased 5% to $23 million from Q2 2013 due to higher risk management contract losses, partially offset by higher bitumen netbacks.

In Q2 2014, the Company reduced its net loss to $10 million due to increased revenue, lower diluent usage which reduced blending costs, and unrealized foreign exchange gains, partially offset by realized and unrealized risk management contract losses of $11 million in the second quarter.

Connacher closed Q2 2014 with a cash balance of $134 million. At June 30, Connacher had credit facilities of $2 million, which represents our $30 million credit facility less $28 million or outstanding letters of credit at June 30.

Q2 2014 capital expenditures totaled nearly $26 million. Q2 expenditures were focused primarily on the nine new infill wells, mini-steam expansion at Pod One and the SAGD+ implementation at Algar.

To conclude, with the issuance of the first lien term loan facility we have sufficient liquidity to continue with the Company’s 2014 capital plan.

I look forward to answering any questions later in the call. And we’ll now turn it over to Merle Johnson for an operations update.

Merle Johnson

Thanks, Greg. Good morning, everyone. Q2 2014 production increased 18% to 13,689 barrels a day and year-to-date 2014 production has increased 13% to 13,562 barrels a day over the first half of 2013. Production increases are attributable to production from the Company’s four new well pairs at Pad 104 and the four producing infills that were drilled in 2013 at Pod One. As Chris mentioned earlier, production at Algar has been relatively flat this year.

Q2 2014 operating costs increased over the same quarter and 2013 by 35%, primarily due to the following items. AECO 5A natural gas index quarterly average price increased compared to prior periods, resulting in a 32% increase over Q2 2013 to $4.43 of gigajoule compared to $3.36. Wind damage repair to buildings from the first quarter storm and normal course construction cap repairs were down in the second quarter. And finally, fluid handling and disposal costs increased due to higher water and off spec volumes associated with drilling the new infill wells and unexpected downtime at third-party disposal facilities.

As reported earlier, Connacher drilled nine new infill wells at Pod-One in Q1 2014. Steaming began on two of the infills in early July and these wells are now on production. Steaming on the next two wells will begin in August. The remaining focus of the company’s growth capital plan will be the implementation of SAGD+ commercial project at Algar and the mini-steam expansion at Pod-One.

We expect these projects to be on stream in the second half of 2015. In Q2 2014, the company achieved a DBR of 14.4%, this is the lowest DBR in the history of Great Divide and we will continue to manage our diluent use to minimize cost. In conclusion, we’re glad to report that production has continued to increase and we are starting to see results from the latest round of infill wells.

I will now turn it over to Jesse Beaudry to review marketing.

Jesse Beaudry

Thank you, Merle and good morning. In Q2 2014, Connacher’s diverse marketing portfolio resulted in a net realized bitumen price of $58.92 a barrel, compared to $56.38 a barrel in Q2 2013. Connacher continues to demonstrate that our diversified marketing portfolio and solid logistics execution adds value to our barrels. In Q2 2014, the volume of bitumen moved to customers outside of Alberta, averaged approximately 37% of total bitumen sales, compared to approximately 80% of total bitumen sales in Q2 2013. The company directed more volume into the inter-Alberta marketplace in response to stronger local pricing.

The intra-Alberta market prices are diverse in Connacher’s rail program provides the company with the ability to move to the highest paying customers across North America. Ultimately, our marketing flexibility and optionality allow us to increase or decrease our volumes by rail, based on where the strongest pricing present itself. In conclusion, market conditions remains positive in Q2 2014 and Connacher will continue to concentrate on finding new customers in North America and the world, while working to ensure we have the ability to efficiently move our bitumen to these customers.

I will now turn it over to Chris Bloomer and look forward to your questions.

Chris Bloomer

Thanks very much, just a quick recap just to emphasize on what we are focused on in the near-term. Obviously, we are focused on the execution of our current capital plan and making sure that is on budget and that timing has been met and so far very happy to report if that is case. We’re also very keenly aware of plant reliability and ensuring our operations are operating at very high efficiencies.

We want to manage our – the marketing of our barrels very efficiently to high-value customers. The market is very dynamic. We have the ability to move our barrels around the marketplace to meet and what’s turned out to be a very volatile marketplace. We’re also focused on cost control. We believe that we want to be the best of what we do in terms of managing our business and we are focused on that.

So with that I want to again thank everybody for participation and we sincerely look forward to your questions. So Rob, if you want to open up the lines for questions…

Question-and-Answer Session

Operator

(Operator Instructions) And your first question comes from Steven Karpel from Credit Suisse. Your line is open.

Steven Karpel – Credit Suisse

Good morning gentlemen.

Chris Bloomer

Good morning, Steve.

Steven Karpel – Credit Suisse

Maybe you talk about the mini-steam expansion, if you would talk about mini-steam expansion and beyond that talk about putting aside the balance sheet for a second if you had more available capital, what you could do in overall steam expansions and your ability with your view on the reservoir and what you’ve done with the infill wells and your ability to truly take the project up to capacity?

Merle Johnson

It’s Merle Johnson here and I’ll take the first part of the question in regards to the mini-steam expansion. What that project is it’s basically at 10% steam capacity to the Pod One facility. So we have areas within the plants or areas within the plants or areas within any plants where you may have some excess capacity, but unless those bottlenecks are removed all the way through the plant can currently only put out about 27,000 barrels a day of steam. So we’re going to add a bit of water handling in terms of evaporation and a boiler to bring that steam capacity up to 30,000 barrels a day. What that will allow us to do, for the life of the project, is basically support two new well pairs.

Chris Bloomer

To follow-up on your question, Steve, I think it’s fair to say that our current capital plan is designed to fit within our current capital availability. We have within Pod One and within Algar a number of projects that I would characterize as being – like the infill wells, like what we did on 104, we are implementing SAGD+, we could implement SAGD+ at Pod One. So we have an arms length of projects that if we have the capital that we will be executing on and with both developing new production and sustaining production and keep growing production.

We feel that we have the reservoir to continue on with that and I think that that is something that folks should understand that the projects that we’re doing – that’s not the full bucket list of things that we could do and with additional capital, we could do similar things. And then beyond what we could do within kind of the reach of our current facilities, there are number of new pads that we could drill.

We’ve identified with what we feel is very high quality geology that we can tie back to our existing facilities. So we feel that we can sustain and – with capital, we can sustain and grow production both at Pod One and Algar. So I think that’s folks should really understand that that is the case, but we can continue to both do kind of brownfield developments and kind of – not full greenfield but we have places to go that we can develop new pads beyond where we are now. Does that help?

Steven Karpel – Credit Suisse

That helps. I just want to understand and then a follow-up to that is how of that is balance sheet contingent versus what you could do even under your current constrains? Could you talk about the growth prospects? If you look out a couple of years, can you grow – what number these – on projects? Or do you need significantly more capital to really execute the programs that you talked about?

Chris Bloomer

I think it’s fair to…

Steven Karpel – Credit Suisse

And maybe you could give us some magnitude of what you’re talking about.

Chris Bloomer

Well, I won’t give you the magnitude. I would just – suffice to say that we will need new capital to grow into new developments beyond what we’re doing right now.

Steven Karpel – Credit Suisse

And the diluent number, obviously you released it already. It was a little low, very low number, which is obviously great. Maybe comment about generically where you’re sending to, how sustainable that number is and what that will ultimately means for netbacks? And where you’re sending the ultimate dilbit to?

Merle Johnson

I won’t comment on where we are sending to. It’s Merle here. But I will comment on the sustainability. I think we’ve been under 20% now for a year or more. And we’ve shown that we can get as low as the 14.4% that we’ve just done. So somewhere in that range it’s probably where we will operate going forward. We don’t see it going much lower than that with the current equipment.

When we canceled the DRU project over a year ago, the idea was that we felt we could do what it was going to do with the equipment we had. And I think we’ve shown that now, that we’ve been able to get very low and really reduced our costs, regardless of where we go diluent just one of the major cost or the biggest cost for the corporation. Jesse?

Jesse Beaudry

Jesse here. What I can tell you is we moved 37% of our barrels by rail in Q2 and the rest of that went into the local market. And quarter-over-quarter that percentage of rail can go up or down, depending on where the pricing presents itself for Connacher. I won’t disclose were our definitions are for competitive reasons. But what I will say is we’ve – historically speaking and going forward, have the ability to move our barrels across North America, due to our strong logistics program and we’ll continue to do that.

Steven Karpel – Credit Suisse

Thank you.

Merle Johnson

I’d also like to comment on the DBR and kind of put in context that DBR both don’t know diluent blend ratio. The 14% and the DBR that we quote is a planned operational spend, that’s what we try to get down to. We want to use as little diluent as we possibly can in the plant. That diluent blend ratio, when we ship on rail, we ship what we produce at the plant in the railcars to the customer. And we get priced against although they are heavy oil barrels that way. In the intra-Alberta market however.

We do assess what the pricing is and that pricing also includes equalization. So if we truck to a pipeline terminal, they will take our barrel and blend it up to move it. Their cost is dealing on to do that as factored into the pricing. So when we look at that pricing and compared against a rail barrel, we make the decision that if that pipe barrel is higher value, we will move it there, if WCS is strong for instance or if we have a market that we can rail and incur the rail cost and so on, we will move it at way. I will say that the rail customers like the lower diluent blend ratio but we have to balance off where we can get the best price. So the DBR is the plant spec and how we deal with the marketing side if that we do the analysis on the pricing that would include the pricing we get is based on the equalization factor, so it’s included.

Steven Karpel – Credit Suisse

Thank you, gentlemen.

Operator

Your next question comes from the line of Joshua Gale from GMP Securities. Your line is open.

Joshua Gale – GMP Securities

Hey, good morning.

Chris Bloomer

Good morning, Josh.

Joshua Gale – GMP Securities

Your initial capital plan of $50 million, I think that was a press release of January was to include up to 9 new infill wells and the upfront engineering work on SAGD+ and the mini-steam expansion. So in yesterday’s press release, says that $50 million was just for the infills and then an additional $63 million for SAGD+ and mini-steam expansion, not just the upfront but presumably almost all of those projects. So I’m just looking for some clarity on the cost of the infills and whether those would come in as project?

Merle Johnson

Yes, it’s Merle here again. The infill project did come in at budget. We’ve said before that the infills constituted about half of the original $50 million and you’re right; there was some upfront spending on SAGD+ and the mini-steam expansion. For the remaining $63 million, there are other projects included in that $63 million. We’re just saying the bulk of that money is associated with SAGD+ commercialization and the mini-steam expansion. So the infills were on budget and we have spending on SAGD+ and mini-steam throughout the year. But now we’ve gone ahead and we’re going to complete those projects rather that upfront work.

Joshua Gale – GMP Securities

Okay great. And so – sorry those $25 million all-in for the nine infills?

Merle Johnson

Give or take, I mean it’s about half of the...

Joshua Gale – GMP Securities

Great. So it seems two are producing now and two will begin steaming this month that was mentioned in the press release in the MD&A in the first quarter that you expect them all to be producing by year-end. Is that still the case?

Chris Bloomer

I think certainly they will all be tied in, completed and ready to go. Any time we bring on a well, it’s because it makes sense at the time, because we’re treating well, because we can get the barrels through without blowing up our op cost. So we’re still hopeful for that, but there are other factors that go in and certainly they’ll be ready to go.

Joshua Gale – GMP Securities

Okay. I just wanted to revisit the non-energy operating costs for a minute. I know that there were some one-time costs in the first quarter, the repair for the natural gas supply disruption at Algar and then some fluid disposal costs associated with Pad 104. And I know you did a good job on the last call explaining the increased chemical costs and fluid handling costs associated with the new production.

I was under the impression that for most of the second quarter it’d be back to normal. Looks like there was an issue to third-party facility and you mentioned the wind damage for building and associated building repairs. So I’d just like to know perhaps going forward. This was a $15 million and $16 million line item historically, now $20 million for the past couple quarters. So what can we expect as you bring on these infills? Will they have the same impact as the Pad 104 wells? And then also, if you can provide an update on the timing for the disposal well that you drilled earlier in the year. I appreciate that as well.

Merle Johnson

Okay. Merle again, and I think I’ll try and talk most of them. There seem like a lot of questions. So…

Joshua Gale – GMP Securities

Yes, there’s five questions.

Merle Johnson

You might have to remind me all of them. But steady with the disposal and third-party facilities, there are a couple of things that we would dispose of. One is clean water and one is evap waste. The disposal well was for clean water and we are continuing to evaluate it and other options and are still working to get something on or available to us sooner rather than later.

The disposal outage, the third-party outage was for evap waste and one of the parties that we would send it to was not available to us for most of the quarter. You can send it to a number of places and it’s like anything. If you have a deal in place you get the best pricing. If you need to scramble and get it send there tomorrow you don’t. So we struggled a little bit with that. We are working on more long-term options for that as well.

In terms of the operating costs, I think right now for Q2 we were in line with a number of other producers, heavy oil and oil sands, but we were higher than we were before. And what we’re seeing in those is that those costs are coming down. So they were $28 give or take in Q1, $24 give or take in Q2. Towards the end of the quarter they were down in the kind of $21 range. So we are seeing those costs trend down. That’s kind of a good number for us. That’s where we like to be.

So if we’re above the $20 a barrel, we continue to work to bring the cost down. But there are things that could make it higher on a continual basis and one of those is the DBR. When you are chasing a change in operating tactics or a long-term win, you might give up something to get it. If we add extra chemical to get a lower DBR that’s by far worth it to the corporation, but the impact of the DBR is typical seen in pricing and the impact of the higher chemical is seen in op cost.

In terms of bringing on new wells, we’re quite comfortable bringing on infills. We’ve done that before, second half of last year with little impact. We’re actually typically, fairly comfortable brining on pairs. I think Pad 104 was something that was a bit different being four pairs at once and having kind of numerous other things, kind of triples up as the quarter went on. So bringing on a pair or two isn’t seen as the big deal, but maybe four pairs is something that we would expect an impact from.

So we’re definitely watching that as we bring on the new volumes and that’s why I said, they’ll be ready to go and we’ll make what I think are wise decisions on when we can handle on in the facilities.

Joshua Gale – GMP Securities

All right, great. You actually got all of them. But I just want to clarify the $20 a barrel, is that including…

Merle Johnson

That’s including energy. And energy costs are obviously up for the year. They’ve mitigated a bit since Q1 for sure, but we don’t see them going back to the last year’s pricing.

Joshua Gale – GMP Securities

Great. Okay. Thank you.

Operator

(Operator Instructions) Your next question comes from the line of Stan Manoukian from Independent Credit Research. Your line is open.

Stan Manoukian – Independent Credit Research LLC

Good morning. Thank you for taking my questions. You guys have done such a great job improving the efficiency of drilling and getting oil bitumen to the ground. I was wondering what are the insurmountable challenges that will not allow at this point to secure longer term contracts with buyers to secure better price? You have not been able to take full advantage of improved DBR ratio obviously. And your percentage of bitumen dilbit shipped to WTI has declined while prices of WTI have increased. I mean is it the consistency of production volumes that sort of hurt you from getting these contracts, what is it?

Chris Bloomer

Let me parse your question out a little bit. This is Chris. The production aspect of it really does not have a lot to do with market. We produce the volumes and we market them. The DBR is an operational metric that we use. And that reduces our dealing with cost to the plant. The markets that we go to change a lot, we don’t price against WTI we have been able to do that in the past, the markets have changed so we have to price against what the customers willing to pay and that’s quite variable.

Moving barrels by rail, big volumes by rails is not necessarily a reflection of getting a better price. Because as we’ve seen WCF has increased in price and we’ve been take advantage of that. So there’s no production issue with respect to that. And you mentioned long-term contracts, our contracts are, we have a variety terms on our contracts and that changes, that can change monthly, quarterly or continually assessing the market. We’re building up a very strong customer base are one of our key strengths are logistics.

So moving the barrels to market and being able to move our barrels from one market to another, on rail or not on rail, is strategic advantage for us. We take what the market will give us, and we try to maximize that value. And we don’t want to get stuck in one market, if we were just shipping everything in Alberta that would not be optimizing our netbacks.

So we have access by rail to other markets and we evaluate all those markets against them continually to see what’s going to give us the best price. So it’s a very dynamic situation.

Stan Manoukian – Independent Credit Research LLC

Great. But in the mean, last year when the prices, combinations of prices between WTI and WCF was comparable, you were shipping 80% to 90% of your bitumen to the U.S.

Chris Bloomer

Yes.

Stan Manoukian – Independent Credit Research LLC

Obviously you’ve been getting much better price. Now with the comparable combination of prices, you’re shipping significant delays and as far as I understand with these improvements in blend ratio you would have benefitted tremendously in terms of cost, our operating cost by shipping into (indiscernible). And so the question is, I mean, I understand that market has changed. But is there anything that you can do sort of to get more predictable pricing through the long terms contracts.

Chris Bloomer

Not really, not really, I mean, the market long term contracts and marketing depends on what you call them three years, five years, we’ll do some one year contracts, and so on. But last year was very unique, we had a contract that was struck at the beginning of the year, it was with a customer that was willing to pay WTI basis. And that was struck when Brent/WTI differentials were very wide. And the customer could take advantage of buying WTI based crude into their market refining and then selling their products on a Brent price. So that was a very unique situation. And we don’t see and our customers are not offering that deal today and it’s not offer that deal in the current circumstance.

So we have to take what the market gives us and that circumstance we took back last year and we think we’re doing in terms of what the market gave us this year very well. Jesse do you have anything?

Jesse Beaudry

It’s Jesse here, I think that is a good question Sam. What we do is within our control, we asses market conditions continuously rail allows us to opportunity to go to high percentage by rail or by low percentage by rail. And really it will depend on what the market offers us at any given time. So it’s really just a method internally of assessing the locations continuously and trying to place our barrels where it could best fit for Connacher and it changes continuously.

Chris Bloomer

Yes I think the...

Jesse Beaudry

Just the time here if we’re selling within Alberta, we’re trucking the barrels. If we’re selling the barrels outside of Alberta, we’re trucking the barrels and railing the barrels. So there’s an incremental transportation cost. So rail market has to be better than what we can do in our markets in Alberta. But we, selling all our barrels in Alberta does not also that’s not optimal, because not all the markets are going to give you a good price.

Stan Manoukian – Independent Credit Research LLC

So as far as I remember you have a fixed cost associated with the lease of this rail cars that relates to about 45% to 50% of your production rate, so haven’t you been using the entire assets of fleet of your rail cars this quarter?

Chris Bloomer

Yes, we’re using our rail cars and that’s a third of our production.

Stan Manoukian – Independent Credit Research LLC

And what kind of visibility do you have today in terms of new low third quarter and fourth quarter transportation and customers. I mean, do you know what you’re going to have in terms of customers for the rest of the year?

Jesse Beaudry

I think, Stan, again – it’s Jesse here. Those are great questions. We don’t want to provide that kind of information on the call like this for competitive reasons. But what I will tell you is, we have absolute visibility and we’re extremely comfortable with what our portfolio looks like going forward.

Stan Manoukian – Independent Credit Research LLC

Okay. Thank you.

Jesse Beaudry

Thanks, Stan.

Operator

Your next question comes from the line of Amy Stepnowski from Hartford. Your line is open.

Amy Stepnowski – Hartford Investment Management

Hi.

Chris Bloomer

Good morning, Amy.

Amy Stepnowski – Hartford Investment Management

Hi, thanks. Good morning, I’m newer to the company and so just a question, first, I don’t know if you’ll provide any updated guidance or not guidance but any updated information with regards to current production, as we are today, where we stand today?

Chris Bloomer

No, we’re reporting on the Q2, but what we have in our disclosure is that we will provide at the end of each quarter and we’re not providing any guidance or update production as of today. But at the end of each quarter we’ll provide an operating update which will be that has upon into production was in that quarter, and then that’s – and we you don’t make a forecast of production outlook for the year.

Amy Stepnowski – Hartford Investment Management

Okay. And then just a follow-up on topic that Steve had brought up in the first question, Merle you talked about the ability to ramp-up production to the 27,000 boe/day with the projects that you have going on, but also in need for additional capital to execute on some of these other projects. I just want if you could speak sort of on a bigger picture strategically as to what potential options are for raising that capital? Obviously you had just completed the term loan. And from a leverage perspective, probably it has to raise additional financing that way. So just wondering if there’s other strategic out news that you’re exploring?

Merle Johnson

We’re evaluating our options not going to comment on what we think those options are going forward. And just to be clear, it’s not 27,000 barrels a day is steam capacity, it’s not production capacity. So we are well aware of where we are and we’re evaluating options. But not prepared to give with any color on that.

Amy Stepnowski – Hartford Investment Management

Okay. Thank you.

Operator

And we have no further questions at this time. I’ll turn the call back to our presenters.

Chris Bloomer

Thanks very much, Rob. Thanks for participating in the call. I appreciate the questions and we look forward to Q3. With that, we’ll sign out.

Operator

Ladies and gentlemen, this concludes today’s conference call and you may now disconnect