Chord Energy Corporation
Q2 2017 Earnings Call Transcript

Published: 5 Aug 2017

[Operator:]

Good morning. My name is Phil and I will be your conference operator today. At this time, I'd like to welcome everyone to the Second Quarter 2017 Earnings Release and Operations Update for Oasis Petroleum. All participants will be in listen only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I will now turn the call over to Mr. Michael Lou, Oasis Petroleum CFO to begin the conference. Thank you. Mr. Lu, you may begin your conference.

[Michael Lou:]

Thank you, Phil. Good morning, everyone, this is Michael Lou. Today we are reporting our second quarter 2017 financial and operational results. We're delighted to have you on the call. I'm joined today by Tommy Nusz and Taylor Reid, as well as other members of the team. Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties, that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During this conference call, we will also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measures can be found in our earnings release and on our website. We plan to file our 10-Q today following this call and we will also reference our current investor presentation which you can find on our website. As we discussed on our last call, we issued a press release in May indicating that we decided to move forward with an MLP IPO for a portion of our midstream assets. And due to securities law restrictions, and the advice of our attorneys, once again, we will be unable to discuss this development, and we know that you can appreciate that. Through our public filings, you are able to see more information with respect to the transaction on the SEC's website. At this time, we cannot provide further comment. With that, I'll turn the call over to Tommy.

[Tommy Nusz:]

Good morning and thank you for joining our call. The Oasis team put together another solid quarter, bringing our total year-to-date completion count to 28 and preparing us for the increased completion activity in the second half of 2017 as we discussed in our May call. We completed 15 wells in the quarter, with 11 of those being completed with 10 million pounds of proppant or higher. Our production volumes were roughly flat with the first quarter, as we continue to focus on cash flow neutrality in our E&P spend. The team did a tremendous job in the quarter, establishing strong momentum going into the second half, where we have seen some firming in oil prices, coupled with operational production averaging over 66,000 BoEs per day during the month of July. We have the execution plan and the services in place to keep moving in the right direction and with that positive momentum to continue as you'll hear from the team today. Setting up to achieve our targeted exit rate for 2017 of 72,000 BoEs per day and we're on pace for a very solid 2018 as well. Back in May, we also announced our intentions to redeploy our second internal frac spread and optimize our completion schedule around the inclusion of that second OWS fleet in addition to our third-party crews. What we've seen in the market since then strengthens our conviction around that decision and supports our strategy of select vertical integration. All this provides us a natural hedge on service cost inflation, we feel it also provides a more balanced risk sharing relationship with our third-party service providers in terms of capital costs and input elements. We look forward to starting operations of the second crew in the next few weeks. We continue to experience encouraging results from increasingly higher intensity completions and are starting to enter a phase of optimization at least in the core with respect to cocktail, mechanics and overall capital efficiency. Wells incorporating our latest generation of high intensity completions in Wild Basin continue to perform well and we are now analyzing early time data from new tests in the Indian Hills. Our current completion activities are expanding this footprint further as we've now moved on to Alger and Red Bank, where we have already seen some encouraging results, like the Teal well at the north end of Alger, just off the South Cottonwood. This is complemented by our other operator activity in areas such as Eastern Red Bank, west of Indian Hills towards the Montana border and even on the western border of our large Cottonwood block on the east side of the basin. Our focus on capital efficiency through the commodity cycle translates into financial returns as well. We've not been trying to grow at any cost, but [indiscernible] instead spend our energy improving the overall capital efficiency across our entire program. We remain focused on drilling wells that generate full cycle value and on acquisitions that create long-term accretion to our shareholders. While we certainly want to grow the company, and are excited about our current trajectory, our view is that growth is an output that is derived from the quality of our asset base, coupled with the focus on our balance sheet and the efficiency with which we manage both. Like everyone else, we're trying to understand what the rebound could look like after a challenging couple of years, and it's important to keep that at the forefront, especially in the choppy macro environment we still see today. The team did a great job when prices fell in late 2014. We made swift decisions to power down in an orderly manner, avoiding all but negligible termination penalties, while transitioning to a cash flow neutral program in 2015 and 2016 that kept production flat in a $45 world. With our gains and capital efficiency, we can now we keep volumes flat or grow nominally within cash flow in a $40 world and deliver attractive growth rates in a $50 world. We will continue to hedge to manage our risk around that just as we did in 2015 and 2016, and you can see that our overall hedge book has grown since May. We now have hedged about 65% of our oil volumes in the second half of 2017 and have about 22,000 barrels of oil a day hedged in 2018. We were basically cash flow neutral in the first half of this year on E&P spend of about $200 million, which excludes infrastructure spend. Additionally, we expect to continue to be cash flow neutral on E&P spend in the second half of the year as we ramp-up activity. Our track record also speaks to our disciplined strategy and our focus on improving well economics across our position through continued innovation, operational excellence and our vertical integration. With that, I'll now turn the call over to Taylor.

[Taylor Reid:]

Thanks, Tommy. We had a strong end of the second quarter, which sets us up well for the second half of the year. We completed 15 gross, 10.8 net wells, with 60% of these completions being done in June. In fact about 40% of the completions for the quarter were done in the last two weeks of the month. During our last call, we signaled that we would come in relatively flat to 1Q for the second quarter. In fact, we came in just a little under the mark. Break-up impact at the pace of completion activity in parts of April and May, and resulted in the backloaded completion cadence just mentioned. In addition, we had more wells offline in normal in Q2, as we came out of winter and break up. We increased workover activity in May and June to work a backlog of wells offline back down. We'd originally expected to be flat quarter-over-quarter and these two factors cost us around a 1,000 BoEs to 1,500 BoEs per day. More recently, volumes were over 66,000 barrels of oil equivalent per day, as benefits from the late completions and workovers kicked in. You will notice that we experienced a slight decrease in our oil cut in the second quarter. This is driven by an increased percentage of our total production coming from Wild Basin. As previously mentioned, Wild Basin has a higher gas to oil ratio than our other properties in the basin and about 65% of our year-to-date completions have been in Wild Basin. As the impact of wells completed in other areas with lower GOR's increases that balance should normalize. Our 78% oil production guidance for the year remains unchanged. On the completions front, we continue to enjoy the benefits of our pressure pumping business. OWS continues to perform at high efficiency levels, which impacts our well costs and our ability to bring wells online in a timely manner while also ensuring quality and availability of service. This has enhanced as the frac services market tightens and confirms our decision to redeploy our second OWS fleet. We will bring that spread back online in a few weeks and look forward to bringing the majority of our completion work in-house. In the well cost front, we continue to see a tightening of the market during the second quarter. The cost of a 4 million pound of 50-stage completion is now $6.5 million. The cost of a 10 million pound 50 stage completion currently runs $7.3 million. We think inflation will continue to rise in the second half of the year, but the pace maybe slowing as shown by the availability of more service options than what we saw in April and May. Our year-to-date CapEx is in line with our guidance, and we expect the remainder of 2017 E&P and other capital to be as well. It continues to be an exciting time in the evolution of the Williston Basin, as completion technology advances and well performance improves. As Tommy mentioned, we continue to test bigger jobs, as well as stages per job, per clusters and per spacing, diverters and other techniques to optimize our fracs. We now have a good sample of bigger jobs in Indian Hills, including two 20 million pound test and are excited about the early time results. We continue to have the upper bounds of profit loading and in the last few days, we completed our first 30 million pound well in Wild Basin. Also we now have much more production data on our previous test in Wild Basin and have updated the charts on Page 5 of our current presentation. What you're consistently seeing in our latest generation of high intensity wells is that the bigger jobs flow for longer periods of time than the smaller jobs. Both wells exhibit flat production profiles early in their life while they are choked back and rate restricted. The bigger frac simply maintain this profile for longer. This is all a result of the wells being facilities constrained by the local central tank batteries until they begin to decline. Remember, we designed our facilities to cost effectively capture early production, not just for the peak. Our Johnsrud 3BX well in Wild Basin, 20 million pound test is a great example of this performance. It was choked back early in its life awaiting gas infrastructure and it's producing today at rates there for 14 months or similar to its early time production. As you can see, this well has been and is a great example of the benefits of the larger frac jobs. Again, it's still early innings, as we continue to gather and analyze more data with longer tenure. We are also excited for results from several of our peers who are testing these larger completions in and around our Extended Core and Fairway acreage. We also have several large completions in our Red Bank area scheduled for the coming months and are currently planning to [Indiscernible] other Extended Core and Fairway areas for 2018. As we move into the second half, we are excited about the program ahead. We are confident in our ability to execute on the program as we have the resources and the team in place to do the job. With that, I will now turn the call over to Michael.

[Michael Lou:]

Thanks, Taylor. As you probably know, the Dakota Access Pipeline or DAPL is now online and its contribution to basin takeaway capacity is making a significant impact on basin wide differentials. The line started moving oil in June and now in August, we are seeing the full impact of the additional capacity and demand in our differentials. While differentials tightened from $5 per barrel in the first quarter to $3.50 in the second quarter, we saw only a partial impact in our second quarter differentials and we expect to see a more substantial impact to third quarter and beyond. Differentials in June were down to about $3 per barrel, and recently we've had some sales well below that. On average, we expect differentials of $3 or better for the remainder of the year, keeping us well within our $3 to $4 annual guidance range. We've delivered basin leading differentials over the past couple of years by getting crude onto large gathering systems and maintaining maximum optionality amongst delivery points. While we certainly have direct access to DAPL through both third party and proprietary systems, the overall increase to basin takeaway has put significant pressure on basin wide differentials, and specifically for producers who have not committed production under long term contracts. As a reminder, Oasis has 85% of its barrels that are not under long term contracts. [Indiscernible] increased slightly this quarter, but was still within our guidance range on the year, much of that increase is related to newly available long-haul pipeline charges, as we access better markets and is offset by the improved differential yields. Lease operating expenses per BoE also increased slightly, it was a function of our lower production this quarter coupled with higher work over rates that Taylor mentioned previously. We expect to work LOE back down within our guidance range, as we materially grow production in the back half of 2017. The team had done a great job maintaining the stellar efficiencies that we achieved over the last two years and positions us to increase activity in the second half of the year, at extremely strong full cycle returns for our investors, which will also continue to improve the balance sheet. We're off to a great start in the third quarter and we are on pace to efficiently achieve our plans. We had many discussions over the past several months during periods of lower oil prices on how we would react in those lower oil prices. If the commodity head south for a prolonged period, we maintain the optionality to reduce activity in very short order and as Tommy mentioned earlier, we can still grow modestly within cash flow in a $40 world. I want to close by echoing Tommy's comments on the importance of financial discipline. Regardless of where oil prices trade, we will continue to focus on shareholder returns and optimizing capital efficiency. We made material improvements to our balance sheet throughout the downturn, and we see it continuing to improve organically as we continue to -- as we execute our plan over the coming years. With that, I'll turn the call back over to Phil for questions.

[Operator:]

Thank you. We'll now begin the question-and-answer session. [Operator Instructions] The first question comes from Neal Dingmann with SunTrust. Please go ahead.

[Neal Dingmann:]

For you Taylor, could you just remind me what the cadence, I know you guys have some larger cadence as it pertains to some of these 20 million pound and 30 million pound jobs, I know, I think more on the 20's side, what are sort of the plans for the rest of the year and kind of how you perceive even the 30 pound jobs at this time?

[Tommy Nusz:]

Yes, on just straight cadence, so, now we've got 28 for the first half of the year, it's kind of consistent with what we said in May. So, you get 48 for the second half of the year and kind of split it between the two quarters, so, 24 roughly in each of the last two quarters and Taylor can give you some color around prop intensity on those. So, as we said, we'd get 130 million pound job and so far and as tested, number of the 20 million for the rest of the year Tommy said we're going to do more wells and about roughly 60% of the whole program will be actually a little bit more, and around [indiscernible] over the 4 million pound job that's still shooting have a 10 million pound average and we're just going to have a mix of different jobs to test a full range as the year goes on. The 30 million pound job in terms of performance, it has just now come online and as a talk about with all these big wells their rate restricted early so, it just looks like the other wells until it gets further out in time.

[Neal Dingmann:]

Could you talk about again that second spread, I forget that you did talk about the timing of that coming, but just talk about the size of that and given what you're seeing now on these jobs, any thoughts about adding horsepower to the original ones, again I forget what the size each were [indiscernible] about the size of each and if you would add more horse power to the first?

[Tommy Nusz:]

Yes, it will come on here within the next two weeks or so, and I think spreads will be the same size, we did the second spread, we laid it down last year in February and to bring it back, we actually added some horsepower to the spread. And so, as we talk about the commissioning getting back up and running in at the same capacity and size as the first spread will cost us roughly $15 million. But all that will be really be in place when we bring it on here in a couple of weeks.

[Operator:]

The next question comes from Brad Heffern with RBC. Please go ahead.

[Brad Heffern:]

On the workovers for the quarter or for last quarter, was there any reason that you're seeing more need for that than expected and was there anywhere that that work was particularly concentrated?

[Michael Lou:]

So, the workovers really are a function of just winter and break up, and we tend to have -- you can have more wells down in the winter period, just because of operating conditions. And then combining that with cycle times really being longer, you end up with more wells going down with the cycle times are just winter days are shorter, harder to get as much work done at a day. So, it takes more equipment to get all those wells back on, so we ended up getting a bit of a backlog that we really worked down in April and May -- in May and June. Once we got kind of past breakups, got more rigs out there and worked that backlog down. And in fact, as you look in July you really see the workover count start to come down. So, it's not a reflection of any particular areas, it's kind of spread across the whole position. And as we mentioned, we did a big slug of those, got the benefits of getting those wells back online and I should see it kind of moderate for the rest of the year.

[Brad Heffern:]

And then secondly, can you talk at all about the cadence for OMS spending, it was kind of heavy this quarter.

[Tommy Nusz:]

You're talking about which part of the spending, you talking about capital?

[Brad Heffern:]

Yes.

[Tommy Nusz:]

The OMS spend is in line with expectations, obviously you're going to deal a little bit more through the good months here over the summer time. And Taylor mentioned it, I think in his prepared remarks, the capital overall is in line with expectations year-to-date and we think for the full year as well.

[Operator:]

The next question comes from Jason Gilbert with Goldman Sachs. Please go ahead.

[Jason Gilbert:]

Question on Wild Basin, the higher GOR there, was that expected and how we think about? I'd like to ask maybe just going forward?

[Tommy Nusz:]

Yes, in Wild Basin, we've kind of always said that that area has a higher GOR, so it's about a 70% oil cut, about a 30% gas cut. The rest of the basin is closer to 85% oil and 15% gas. And so, as activity is a little bit more focused for the last couple years in that Wild Basin area, the gas mix is going to increase. However, what we've said kind of through this year is that as our activity starts to get more balanced between Wild Basin and other areas, you're going to start to see that that oil and gas mix kind of moderate in that 78% for the full year. So, not surprising that that it's a little bit more gassy in the second quarter because 65% of the wells in the first half were in that Wild Basin area throughout the rest of the year, so it's going to be a little bit more balanced.

[Jason Gilbert:]

So, the older vintage wells across the play are performing in terms of oil cut exactly or as you expected, is that safe to say?

[Tommy Nusz:]

Yes. They're pretty much performing as we would expect.

[Jason Gilbert:]

And second one, can you talk about the M&A environment in the Williston right, I mean, [Indiscernible] surprise most of us to the upside on the front they got, and I just want -- are you more of a buyer or a seller of assets on this market?

[Tommy Nusz:]

Yes, I would say that it's consistent with what we've always done, the SM transaction at the end of last year is a great example, is that where we have opportunities to bolt on, in and around our core blocks, then we'll do that. And so, we continue to look for a little -- we've got little things that are a million or two million here or there, occasionally something big, like [Indiscernible] will pop up and but we're always looking to bolt on.

[Jason Gilbert:]

And one last one if I may. You mentioned, if the commodity head south, you could reduce activity, what's -- could you get more granular on the price on which [Indiscernible] 4 rigs to 3 or on the upside four rigs to five maybe?

[Tommy Nusz:]

Yes, I think -- I mean it's consistent with what Michael said, I mean we've been saying for some time, as we're kind of managing this thing within a $45 to $55 band, and as it starts to head to $40, we can track to the same old scenario where we live within cash flow, kind of tread water on volumes, maybe at this point at $40, we think we can probably grow volumes just nominally in that world and then the activities and output of it. So this year we had 76 completions in that world, we'd probably have somewhere in the range of $45 or $50 and we'll see where that goes. But up also keep in mind too, we're continuing to build our hedge book, we're -- what was it, Michael, 65% for the second half of this year and continuing to build the book, we're only at 22,000 for 18 right now, but continuing to build that book next year to insulate us against that price. So, but that's kind of how we are managing it, but that's consistent with what we've been doing.

[Operator:]

The next question comes from David Deckelbaum with KeyBanc. Please go ahead.

[David Deckelbaum:]

Taylor, I was hoping -- looking at the parts that you put up on Wild Basin, it looks like you're having more success with 50 stages versus 36 and the 4 million pound jobs, is that sort of the base case now for that 4 million pound job? It's getting the tighter frac stage spacing there?

[Tommy Nusz:]

We've actually gone to 50-stages on all the jobs, so both the 4 million pounds and the bigger jobs, we just -- we're seeing better well performance with the increased stages, we think better distribution of the frac.

[David Deckelbaum:]

And then in your comments, I think I mean John said earlier about that well being choked back early and how it's producing at a similar rate now. Based on the date you've collected, do you think if there's an argument to chuck these wells back further intentionally going forward?

[Tommy Nusz:]

We may be getting a -- we're looking at the data and trying to analyze and see if there is a EUR, longer-term well performance benefited choking the wells back, it's driven really a lot by facilities. At this point, we have done some testing with managed fall backs on wells, really trying to capture some more of that data, but we don't have any conclusions at this point.

[David Deckelbaum:]

And just the last one, if I may. I think you mentioned that you're getting close to optimization for the program. I guess can you kind of add some color to that as to, when you feel like you'll have enough data in hands to make decisions on what your sort of generic recipe would be?

[Tommy Nusz:]

Yes, that -- it really continues to evolve and what you've seen is do over the past years is we kind of have a base recipe that we're working off of and right now it's more like -- the average well is more or like 50-stage 10 million pound job and it's all sand and then we're testing a lot of things around that to understand what's going to be the optimal job going forward and so is -- if we see something like going from 36-stages to 50-stages, it's clearly making an impact and we'll make a move and make -- and blend that employing that into our standard job. So, it's kind of continue to evolve as we go.

[Taylor Reid:]

Yes, that -- it really continues to evolve and what you've seen is do over the past years is we kind of have a base recipe that we're working off of and right now it's more like -- the average well is more or like 50-stage 10 million pound job and it's all sand and then we're testing a lot of things around that to understand what's going to be the optimal job going forward and so is -- if we see something like going from 36-stages to 50-stages, it's clearly making an impact and we'll make a move and make -- and blend that employing that into our standard job. So, it's kind of continue to evolve as we go.

[Operator:]

The next question comes from Ron Mills with Johnson Rice & Company. Please go ahead.

[Ron Mills:]

As you look at the high intensity fracs and how that builds into your projected growth for the second half of this year and even to hit your 2017 and 2018 exit targets, have you factored in any incremental uplift from the use of higher intensity fracs or what are some of the assumptions behind that growth profile versus how you're completing was?

[Tommy Nusz:]

Yes, Ron, generally with a bigger job, we've factored in the benefit of doing them, but it's, as you make a step up from a four to a 10 and to a 20, it's on a percentage basis, and we use a type curve. So, when you look at some of these, we're going Page 5, some of the results from the wells as you get further out in time, some of those are probably outperforming what we've used on a percentage basis, when you look earlier time, especially these bigger wells, they're all flat profiles so, we're actually modeling them that way, so we've got flat production for an extended period of time. And then you'll see them outperform as that flat production continues. But I would say in general, we are definitely modeling for the bigger wells, but there's upside to what we're using just based on how they perform.

[Ron Mills:]

And the follow-up to an earlier question, in terms of pace of completions, I know the second half is up significantly versus the first half. But relative to the second quarters -- is the second half, is the pace completions expected to be pretty similar over each of the months, therefore the growth profile be a little bit more linear than what we've might have seen in the second quarter?

[Tommy Nusz:]

Yes, we're right on track with the math, if you looked at July, because being in the summer helps. But it should be more consistent.

[Ron Mills:]

[indiscernible] last, I was going to ask, we've talked a lot about Wild Basin, but you're obviously starting to bring more wells on from the older Indian Hills and even maybe Cottonwood areas. Where are you in those areas in terms of completion, intensity and the outlook for activity spread between Wild Basin and those other areas?

[Tommy Nusz:]

So, as we've stepped out to the other areas we've been testing these bigger jobs as well. And as I mentioned, we've got, for example, in Indian Hills, we've got couple of 20 million pound frac jobs. And those are early times, so we haven't shown them yet, we'll show them next quarter as we get more data that's meaningful. And Red Bank, we've got a couple of the bigger jobs paying us well, so the 20 million pound fracs and those will be done this quarter. And then as you look at -- and then we will, when I say done, we'll get them fracked, get them on production, so meaningful production data is going to be on that Red Bank stuff probably late this year, early next year. And then when you look over on the East side of the basin, the Teal well we've got in the presentation, that's the equivalent of the 20 million pound job for 10 thousand-foot lateral; great results on it so far. And then as we drill further south, right now we're in our -- in the [indiscernible] unit and again going to test range of bigger jobs there as well. So, as Tommy mentioned, the recipe be may not be exactly the same in all the places, but we're starting out with what we've seen work well in Wild Basin, applying that and then we'll work on optimizing those jobs further. But excited to see the results in these other areas.

[Ron Mills:]

Are any of those wells in areas that -- particularly in Red Bank that could pull more of your Extended Core into core like we saw last quarter?

[Tommy Nusz:]

Yes, it's a really good point. The wells in Red Bank, they're really on the edge of what we're calling core, some of them are just a little over what we call the boundary [indiscernible] impact on area around it based on the results that we see. On top of that, you've got a number of wells which we're tracking by other operators and so there's quite a few that are in the extended core and even in the fairway, that are being tested with 1,000 pounds per foot, 2,000 pounds per foot or more of proppant. So, we'll track those and talk about those as we get more data. And then as we go into 2018, we'll really push it out further on outside the core, into the Extended Core on our own pilots.

[Operator:]

The next question comes from Joshua Gale with Nomura Securities. Please go ahead.

[Joshua Gale:]

Thanks for taking the question, I know a couple of them have been answered already, but just wondering in terms of the differentials, if you could just highlight some of the flexibility that the integration with OMS gives you in terms of delivery points and how much that helps on a dollar per barrel basis day to day? Because, across the space we're seeing some differentials in your peers, and I just want to get a sense of what the strategic advantages there?

[Tommy Nusz:]

Yes, the differentials, as we talked about really have stemmed from kind of a strategy that has gone back five or six years of getting all of our oil onto a large gathering system that has basically access to every way out of the basin, including DAPL, which has been the impact here recently. DAPL came in with 450,000 plus barrels of takeaway capacity, a lot of long term contracts associated with it. And so, what it does is, it brings a lot of demand for us as producers in the basin. And one of the things that our marketing team did a great job of is really kind of thinking through what the production in the basin was forecasted to look like as well as what the takeaway capacity was going to look like and we're in a situation where there's a lot of takeaway capacity in the basin with much lower production levels. So, that's good for producers and it tightens our differentials, especially given that we are only -- we're 85% short term on our oil barrel. So, we can actually move our barrels to the best price at any given time. So, it gives us a chance to get very, very tight differentials and you've seen that in our results.

[Operator:]

This concludes our question-and-answer session. I would like to turn the conference back over to Tommy Nusz for any closing remarks.

[Tommy Nusz:]

Great. Thanks, Phil. We're looking forward to the second half of 2017 as we nearly double our completion activity from the year-to-date levels. The next six months represent the heart of the 2017 program and more importantly, lay the groundwork for everything to come in 2018 and beyond. The quality of the asset base we've built and the strength of the team we've assembled to develop it gives me great conviction around the future success of Oasis. We're confident in our ability to execute and to manage our business prudently and what continues to be constantly changing market. Thanks for joining us today.

[Operator:]

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.