Goodrich Petroleum Corporation
Q2 2017 Earnings Call Transcript

Published: 4 Aug 2017

[Operator:]

Good morning, and welcome to the Goodrich Petroleum Second Quarter 2017 Earnings Conference Call. 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 would now like to turn the conference over to Mr. Gil Goodrich, Chairman and CEO. Please go ahead.

[Walter Goodrich:]

Thank you. Good morning, everyone. Thank you for joining us this morning and we're pleased to have the opportunity to share our second quarter results with you as well as the outlook for the remainder of 2017. We prepared a slide presentation in conjunction with the call this morning and we invite you to follow along the slide deck during our prepared remarks. You can access the slide deck presentation on our website entitled Management Presentation and Haynesville Shale Overview 2Q17 Earnings Call. Our standard disclaimer and forward-looking statement and risk factors are highlighted on Slide 2. I will begin on Slide 3 with a quick overview of the company and our ongoing focus on the Haynesville Shale play. Given our acreage position, inventory and the extraordinary results we're seeing in the area, all of our near-term activity is focused on our acreage in the Northwest Louisiana are of the Haynesville Shale which is a 100% HBP. During the second quarter, we successfully transferred our stock listing to the NYSE American Platform and since April, we have been trading under the symbol GDP. Our core objective is to aggressively grow our natural gas production and EBITDA throughout 2017 and into 2018 while maintaining low debt metrics and a solid balance sheet. Following on the results of the first two non-operated 10,000-foot Haynesville wells we participated in late last year, we drilled and added two operated Haynesville wells to production in the second quarter and we are currently drilling our third operated well which we expect to complete later in the third quarter. As a reminder, in December, our board approved a 2017 capital expenditure budget focused on the Haynesville Shale plate of approximately $40 million to $50 million, which includes approximately 9 to 12 gross and 4 to 5 net wells drilled in 2017. While we still anticipate the same number of gross and net wells for the year, due to a small change in well planning whereby we now plan to drill two 7,500-foot laterals from a common pad versus two individual 10,000-foot laterals to maximize the development of our acreage configuration and take advantage of associated cost savings, we are reducing our range of anticipated CapEx for the year by $5 million to a range of approximately $35 million to $45 million. After reporting average daily production in the second quarter of 36.3 million cubic feet of natural gas and equivalents per day, it revised an updated planning results and guidance of an estimated exit rate for the year of 55 million to 60 million cubic feet per day. Moving to Slide 4. Our capital expenditures for the second quarter totaled $14.1 million. While we are just getting started, traction and production volume in the EBITDA growth is starting to be reflected in quarterly financials as production grew sequentially by 40% over the first quarter. Importantly, volume growth has continued with production in the month of July, averaging approximately 44 million cubic feet per day. The attractive aspects of the recent long lateral high proppant Haynesville wells including low finding and development cost, very low lifting cost and strong production volumes is driving very good margin expansion, which began to show up in the second quarter with adjusted $5.1 million of EBITDA during the three-month period and is expected to continue to grow as we drill and complete the upcoming planned and budgeted wells. The balance sheet remains in very good shape with $35 million of cash-on-hand at the end of the quarter and just $26 million of net debt. Finishing up on Slide 4 and going on to Slide 5. During the second quarter, we accelerated our plans with the drilling and completion of our Wurtsbaugh 26H-1 and Wurtsbaugh 25 and 24H-1 wells in the Bethany-Longstreet field of Desoto Parish in North Louisiana. These wells came online in May and June respectively at initial rates of 22 million and 31 million cubic feet of gas per day and were important contributors to the 40% sequential growth and production compared to the first quarter of this year. In addition, we recently sought [ph] in additional high working interest operated Haynesville well in the Bethany-Longstreet field, our Franks 25 and 24H-1, which is planned with another 10,000-foot lateral with very high proppant levels per foot. Including the Franks, we have three additional operated Haynesville wells planned for the second half of this year. The rig bid is currently being utilized to drill the Franks 1H scheduled to then move on to a two-well pad to drill the Wurtsbaugh 25 and 24 2 and 3 wells which are designed as I've said, as 7,500-foot laterals. We believe this level of development will continue the production and EBITDA growth as projected in our plans and capital budget. During the second quarter, we also completed two transactions where we acquired both on Haynesville acreage in the core of northwest Louisiana, which further expanded our overall core inventory. In particular, they increased our inventory of operated acreage and extended link laterals to be drilled. Increased proved reserves on a pro forma basis back to the year-end 2016, provides for lower transportation expense from these operated wells and increased our overall [indiscernible] reserve exposure in the Northwest Louisiana core to approximately 1.2 Tcf. If you'll turn to Slide 6, you'll see our estimated basic and fully-diluted share counts. We currently have approximately 10.5 million basic shares outstanding with approximately 1.1 million costless [ph] warrant unexercised. Once this common stock reaches $17 per share, an additional 1.35 million warrants become exercisable. Our convertible pit [ph] notes have a conversion price of $21.33 per share, which when converted, shares would increase to the fully diluted share count of approximately 14.75 million, but upon conversion into common stock would eliminate all of the associated debt and result in no net debt or negative net debt on a pro forma basis given the $35 million of cash currently on the balance sheet. Moving to Slide 7, you'll see our production level growth and guided exit rate for 2017. As you can see, Haynesville Shale volume growth is driving the overall company volume expansion. As I mentioned a minute ago, we averaged just over 36 million cubic feet of natural gas, of which 85% was coming from the Haynesville Shale. Since the end of the third quarter, we averaged 44 million cubic feet of gas per day in the month of July. As previously mentioned, the small change in well planning and current anticipated timing of the completion of fourth quarter has resulted into an exit rate of a set of 55 million to 60 million cubic feet of gas per day. While we've not set a preliminary budget yet for 2018, our internal planning anticipates continued sequential production volume growth end of 2018. On Slide 8 is a summary of our current natural gas hedge position where we were hedged at $3 per Mcf or greater, covering approximately 41% and 45% of the current volumes for the balance of 2017 and full year 2018 respectively. We plan to add additional hedges as additional wells and production volumes come online as part of our ongoing risk mitigation efforts. And with that, I'll turn the call over to Rob Turnham.

[Robert Turnham:]

Thanks, Gil. Our revenues for the quarter of $12.5 million were generated from an average realized price of $3.67 per Mcf equivalent, comprised of $2.89 per Mcf and $47.96 per barrel of oil, down from $4.05 [ph] per Mcf equivalent in the first quarter. Our per unit operating expenses were materially lower and will continue to drop due to a very low lifting cost in the Haynesville. LOE was $2.9 million for the quarter which included $700,000 of workover expense; LOE excluding work over expense of $2.2 million with $0.67 per Mcf equivalent, versus $0.94 per Mcf equivalent in the first quarter. Per unit LOE will continue to fall as we add significant volumes from the Haynesville which carry an initial estimated per unit LOE cost of approximately $0.05 per MCF. Production and other taxes were $400,000 in the quarter or $0.13 per Mcf equivalent versus $0.29 per Mcf equivalent in the first quarter. Haynesville wells drilled in the State of Louisiana have severance tax abatement until the earlier of payout or two years, which will continue to drive our per unit production taxes down near-term. Transportation and processing expense was $1.9 million in the quarter or $0.57 per Mcf equivalent versus $0.51 per Mcf equivalent in the prior quarter. Transportation and processing expense for the quarter included $145,000 associated with the gathering line amortization for the company's Wurtsbaugh 25 and 24 number 1 well, which we expect to be satisfied by the end of August. Production from the next three wells on the schedule, the Franks and the Wurtsbaugh 2 and 3 wells will have transportation expense of $0.22 per Mcf equivalent, which will help drive down our per unit transportation expense. G&A for the quarter was $3.8 million, which includes non-cash expenses of $1 million for stock-based compensation, $700,000 of estimated performance bonuses to be compensated in stock and $100,000 in amortization of office rent. Non-cash G&A totaled $2 million in the quarter or $0.59 per Mcf equivalent. Per unit G&A is expected to continue to fall as comps are expected to remain relatively flat and production volumes are expected to grow materially. Operating income for the quarter totaled $400,000. Interest expense total $2.4 million for the quarter which included cash interest expense of $300,000 and $2.1 million of non-cash interest in amortization of debt discount expense associated with our second lien notes. We reported a net loss of $1.2 million for the quarter. Moving back to our slide deck, Slide 9 shows our core properties where we retain approximately 50,000 gross, 26,000 net acres in the Haynesville; 108,000 gross, 80,000 net acres in the TMS; and 32,000 gross, 14,000 net acres in the Eagle Ford. Slide 10 breaks out are approximate acreage position for the Haynesville where the vast majority of our capital plans this year will be spent in the North Louisiana core position. In North Louisiana, we have an average working interest of 44%, with approximately 250 gross, 100 net locations in inventory with at least half of those locations capable of 10,000 foot laterals. We have gridded our acreage for the plan to maximize long laterals and expect to be in a position to swap acreage or drill joint wells with offset operators to further increase our long lateral inventory. We are also targeting additional swaps and built on acreage acquisition opportunities in the core to add to our inventory, similar to the 3,000 net acres we acquired during the second quarter. In North Louisiana, we estimate approximately 1.2 Tcf of reserve exposure at 2.5 Bcf per 1,000 feet of lateral, of which we operate approximately 50%. In addition, although we aren't currently focused on our Angelina River Trend acreage, an offset operator has been making very good wells directly offsetting our acreage which validates our analysis that the quality of the Haynesville is as good at Angelina River as it is at our core North Louisiana acreage. We have updated Slide 11 to show our current acreage position post the swap in recent acquisition as well as a few new well results in offset activity. For those that are looking for the first time, the old gray lines on this map are short lateral wells drilled prior to 2014. More recent short lateral wells are shown in green; recent 7,500-foot laterals shown in orange; 10,000 foot laterals shown in red; and our acreage in yellow. Our Franks well which is now drilling is on our southeast portion of our block and the two wells after the Franks, the Wurtsbaugh 25, 24 number 2 and 3 are west of the Wurtsbaugh 25, 24 number 1 well. We have also updated our cumulative production for our two ROTC 10,000-foot laterals at approximately 11 Bcf in seven months. There's an abundance of activity currently on and around our acreage including at Greenwood-Waskom and we expect a very busy year for the area in 2018. We have developed tight curves for each of our 4,600, 7,500 and 10,000-foot laterals as shown on Slides 12 through 14. Our tight curves are based off of 2 Bcf to 2.5 Bcf per 1,000 feet of lateral. However, our results are exceeding our high case type curves. When you examine the curves on each of these pages, you will see that the main driver, the superior well results is proppant concentration. Although as we have said before, lateral length, stage and cluster spacing blew a design pump rates and pressure maintenance programs designed to minimize draw down are all important factors driving results. We and other operators in the play have begun choking our wells back to conservative choke sizes to flatten the curves and minimize draw down and we expect to see very good long term recoveries from this strategy. You can see that we have done that on both Wurtsbaugh wells and are seeing very encouraging flat profiles today. Our economics as shown on Slides 15 through 17 show very competitive internal rates of return for all three lateral links at our tight curves ranging from 53% for short laterals to 76% for our longer laterals at $3. In summary, we think the company is executing well on our plan to materially grow volumes in EBITDA sequentially throughout the year. You will continue to see margin expansion as we add Haynesville wells at low-funding and development cost with very low per unit operating cost. We believe we can deliver these results while maintaining very low debt metrics and are estimating approximately 1x net debt to annualized fourth quarter of '17 EBITDA. With that, I will turn it back to Phil for Q&A.

[Operator:]

Thank you, Rob. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Neal Dingmann with SunTrust. Please go ahead.

[Neal Dingmann:]

Good morning, guys. Good details. Say, Rob, can you be able to walk through just - I know you haven't put out anything on '18 yet, but where I'm just trying to get a sense of upcoming plan after you laid out these five wells, thoughts of trying to run a full time rig or how you sort of see things progressing once this plan is finished? Provide us maybe just a very broad view?

[Walter Goodrich:]

Sure, Neal. This is Gil. Good morning. We don't have a firm plan. We obviously will set the firm plans with the board in December of this year, but we can tell you, our internal thinking is certainly at CapEx level higher than what we've seen this year. Whether or not that works out that one full time rig or not is still a bit of a question. I'd say probably not, but certainly, we expect to see CapEx levels higher. [Indiscernible] depending on what's happening exactly in the second half of the year where natural gas prices are, but currently thinking something along the order of 20% to 30% higher in CapEx, should we continue to drive growth throughout 2018.

[Neal Dingmann:]

Great. Thanks.

[Operator:]

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

[Ronald Mills:]

Good morning. My question is relative to the tight curve, the protection profile being flatter, Rob, related to the choke management program, do you think it has to do with proppant levels? Are you starting to hone in on what your desires are in terms of is longer always better and more proppant always better?

[Robert Turnham:]

Yes, Ron. Great question. Certainly and we've been consistent with this response which we see benefits to longer laterals and higher proppant concentrations. In fact if you look at our two ROTC wells that we participated in, one was 10,000-foot lateral at 5,000 lbs per foot; the other one 10,000-foot lateral at 3,000 lbs per foot, there's no question the higher proppant concentration in the one ROTC well is generating a better well result. I think all things being equal. Longer is better and more proppant is better, at least in the Haynesville. As far as choking these wells back, we think it's an integral part of ultimately getting the maximum recovery of the resource in place and we limit our draw down to roughly 30, maybe as much as 50 Psi per day. Simply put, it's just being gentle along the formation by not pulling the well too hard. We've seen some wells certainly historically and even recently that have been a little bit more aggressive. There's no question, those decline curves are steeper. So part of the reason you're seeing us outperform in the Q in July to date is certainly an outperformance versus consensus we think as not only optimum completion design, but being gentle along the wells and flattening those curves through pressure maintenance in monitoring that draw down. Our goal here is to obviously have the lowest funding and development cost, but also maximizing returns and creating bigger reserves over the long haul and we think the reduced choke program is going to allow for that.

[Ronald Mills:]

Okay. And then any commentary, other operators have talked about positive impact on legacy wells as you drilled new offset wells and also recent commentary about successful refracs in areas where you can't necessarily drill a new offset well. Any commentary on how your offset wells are performing and any initial thoughts on the refrac data?

[Robert Turnham:]

Yes. I'll take that, Gil. It's a huge benefit, obviously, to drill new lateral wells in an area where you have all sort of production. We're certainly seeing those old wells increase in production pretty significantly and we think over time, that production will drift back down at or close to where those wells were producing prior to getting kind of reenergized through the offset fracs. Ironically, none of us have ever really tracked how much incremental production coming from the offset well should truly be added to the production from the new well to generate an EUR [ph] estimate. So there's a huge benefit to that. If you don't have the ability to drill offset well, we clearly see the benefit of refracking, but for us, we're studying what other offset operators are doing as far as refracking and trying to determine, 'are we better off just drilling the offset well, the new well getting the incremental production from the parent well, if you will, to go with the new well versus refracking a well and drilling an offset well?' Clearly, if it's isolated and you can't drill an offset well, sure looks like the refracs are very economic and beneficial. But as we sit here right now, we're drilling in areas that are highly undeveloped. So we're seeing that benefit to the old parent well or the legacy well. And in fact, most of our acreage is highly undeveloped. Unlike some other operators, we may have a little less refrac potential, only because we can get the incremental volumes from the new wells since we're so highly undeveloped.

[Ronald Mills:]

And then lastly, how are the well cost coming in relative to the tight curves that you have presented in your presentations?

[Robert Turnham:]

I think our presentations which were based on 4,000 lbs per foot with some recent competitive bids on fracs, we're in the ballpark of what those estimates were. Yet, we're able to pump a little bit bigger frac job. So if you remember, Ron, we put those cost estimates in the presentation after we saw service cost escalating. We're seeing a little bit more competitive bidding now on the completion side. Whether that continues, we'll just have to see over time. But again, one of the reasons we switch to the two 7,500-foot wells off of the same pad, even though it pushed off our frac, we were able to get more competitive frac bids if we did the two well pad, which justified in our minds before going a little bit of incremental production along the way to maximize the return on those two wells with lower well cost. I think we're in the neighborhood even though we're able to pump bigger frac job with the current bids.

[Ronald Mills:]

Great. Thank you. I'll let someone else in.

[Robert Turnham:]

Thanks, Ron.

[Operator:]

The next question comes from Jeff Grampp with Northland Capital Markets. Please go ahead.

[Jeff Grampp:]

Good morning, guys. Following up on Ron's question on different completion methodologies. I'm looking at these two Wurtsbaugh wells that you guys are tracking here. It looks like the shorter laterals may be tracking a little bit flatter and more significantly above curve. I'm wondering if you guys have been able to identify how a little bit more proppant, but are any of the other variables as far as stages and [indiscernible] and things like that leading you to a particular design going forward? I know it seemed like the most recent well you guys are going with that 5,000-pound job.

[Walter Goodrich:]

Yes, Jeff. This is Gil. Ideally, we'd like to be pumping 5,000 lbs per foot on all of our wells. The real question is overall cost. We're looking very closely at integral stage spacing lengths and generally, we believe tighter is better. But again, it's ultimately a question of cost and cluster spacing we think is very important. So as Rob said, pump rights as well as integral stage length, as well as obviously proppant per foot are all drivers. Because it was a shorter lateral, we did choke the Wurtsbaugh 26H-1 back a bit more than we did the 25 and 24, which is a 10,000-foot lateral and it has had a slightly flatter-looking profile although we obviously feel very, very good about both of those wells. Maybe it's just picking up a little bit on Ron's question earlier, but these very, very high proppant per foot wells are delivering extraordinary early time conductivity and therefore artificial porosity and permeability, which is allowing for us to be able to choke them back and deliver a very flat decline curve. We'll just see how that plays out over time, but clearly, the tightness of the spacing, increased proppant is allowing us to both maintain fairly flat rates at pretty high levels with the reduced choke program. Hopefully that answers your question.

[Jeff Grampp:]

Yes, definitely. Very helpful comments there. And on the revised production numbers for the end of the year, just kind of making sure I understand what's baked into that. Do you guys have a sense or what's the assumption there as far as when do that [indiscernible] path starts to flow in the sales?

[Walter Goodrich:]

Yes. Again, this is Gil. Jeff, it really all depends on the timing of exactly when the wells get finished and the frac show up and the wells get frac in terms of sales and those are all a little bit of moving target. And when we're this far out, it's kind of difficult. It's at a late-November/early-December/mid-December. It's kind of moving around a little bit and therefore difficult to tie down any more than what we did. It's just kind of an exit range anticipated with those wells, all expected to come online sometime late in the fourth quarter. I should say the additional two wells coming on late in the fourth quarter would give us that exit rate.

[Jeff Grampp:]

Okay, that's helpful. And last one for me. Can you guys maybe just talk about the opportunities set for additional swaps and trades? I guess just looking at first half, it seems like you guys are pretty successful. Would you say the prospects for the second half of the year are better, worse, similar, or just any kind of commentary you could provide there will be helpful.

[Robert Turnham:]

Yes, Jeff. This is Rob. I'll jump in here. I think you will see us have some additional swaps with offset operators. At least the early indication is that will happen. Our goal here is to add to our operated position, add to our ability to drill long laterals and add to our acreage position that is going to have a low gathering fee - and as I said in my prepared remarks, that's $0.22 per Mcf equivalent. So if we can accomplish all of those goals and it's obviously got to be good for the offset operator also, which we think there's a real plan for that, then I think you could see us just continue to boat [ph] on more operated acreage position to what we have. In addition to that, there are certain areas where you're basically isolated with the 640 acre section and you have the offset operator who may be in a similar situation. So instead of drilling 4,600-foot laterals on that isolated section, we do think you're going to see the potential for joint wells being drilled where we combine our section with the offset operator. That makes sense for everyone. As far as tacking on additional boat on acquisitions, we're certainly interested in that. We're continuing to review certain opportunities, but until that happens, we can't really guide to it. It's in our focus. We're mainly interested in a certain defined area in the core of North Louisiana and hopeful you'll continue to see us boat on throughout the year.

[Jeff Grampp:]

Okay. Great detail and good quarter, guys.

[Robert Turnham:]

Thanks, Jeff.

[Operator:]

The next question comes from David Baird with Coker Palmer. Please go ahead.

[David Baird:]

Hi, good morning, gentlemen. A bit picture and a micro-picture question. Just on the micro side relative to sand costs and moving up to 5,000 feet, is there anything you could give us that's relative to sands specifically? Or either embedded cost in your decision to move higher? Or how much headroom is there for higher sand cost before you would drop below 5,000 feet? That's my first question.

[Walter Goodrich:]

You want to handle that, Rob?

[Robert Turnham:]

Yes. David, we hear comments there. We certainly know of the cost escalations in the Permian. We're probably not seeing that same phenomenon at least currently in the Haynesville. I think there's a reasonable amount of activity relative to capacity in the play. That doesn't mean it can't vary on a quarter-by-quarter basis. But right now, we've not seen over the last quarter cost escalations. In fact we've seen a little bit more competitive landscape on the completion side. So that's been very, very beneficial. We typically bid the full job out with all the various suppliers and services embedded into one bid. We're not seeing what the service providers' sand cost are. We just are seeing competitive bids to do the job. It doesn't feel like there's a whole lot of escalation - at least where we are in the Haynesville currently, but obviously that could change with increased productivity levels.

[David Baird:]

That's helpful. And the big picture question really relates to capital spending and cash flow and additional capital. Given your new guidance here and then the comments about ballpark for '18. It feels to me you're really trying to spend roughly within the cash flow and not really bring cash balances down a whole lot.

[Robert Turnham:]

That's right.

[David Baird:]

Is that kind of philosophically where you are for next year's so that there's no real need to raise capital right away because you're going to be within cash and cash flow very comfortably?

[Walter Goodrich:]

Yes.

[Robert Turnham:]

That's really the goal, David. Our goal here is to exit the year with plenty of liquidity. We also think you could see us roll into an RBL from our first lien term loan which would provide incremental liquidity. So really no necessity to raise additional capital this year and if you look at 2018, and as Gil said, you increase your CapEx. The margin expansion that we're seeing from these wells and basically the cash flow growth gets us very close in cash flow to what we think we could spend within our main. So no really needs right now, no plans right now. Obviously, it's a great acceleration story at the right time in the right market which it doesn't feel like it is right now, but we can live within our means through 2018 if that's the path that we choose to go.

[David Baird:]

That makes sense and appreciate the color. Thank you.

[Robert Turnham:]

Thanks, David.

[Operator:]

The next question comes from John White with ROTH Capital. Please go ahead.

[John White:]

Good morning and congratulations on such exceptional production results.

[Robert Turnham:]

Thanks, John.

[Walter Goodrich:]

Thanks, John.

[John White:]

As Ron Mills mentioned, you have some fracking new wells, has impact on existing offset well and I know you do some workover operations in preparation of that and we had some of that in LOE in the second quarter. What about the workovers in third quarter numbers?

[Walter Goodrich:]

Yes. I don't think you're going to necessarily see a lot with the handful of wells that are all being drilled right in that same area, John. We don't have any specific workovers planned and associated with those well. That work has already been done. We would however, expect to see some again, incremental impact as we begin the frac process on those three wells down in the southeastern part of our acreage. So it's certainly conceivable we'd get another bump from some of the parent wells as we begin the frac program later this year.

[John White:]

Okay. So workovers go away in third quarter?

[Walter Goodrich:]

Yes. We're currently guiding to very little specific workover in the LOE in the second half of the year, third and fourth quarters.

[John White:]

And how does transportation expense change in the third quarter?

[Walter Goodrich:]

We're expecting it to be lower just based on volume expansion and as Rob said in his prepared remarks, particularly the fact that all three of these wells are going now are operated wells that would be coming through $0.22 down from $0.57 per annum in the second quarter. With those wells coming on, we certainly expect that to drive the per unit transportation expense down in the second half of the year.

[John White:]

Okay and just curiosity, more than anything else. Is the production on the new Haynesville well, is it 100% gas or are there any liquids at all?

[Walter Goodrich:]

100% gas.

[John White:]

That's what I thought.

[Walter Goodrich:]

We might owe you barrel condensate every now and then, but basically dry gas.

[John White:]

Okay. Well, thanks again.

[Walter Goodrich:]

Great. Thanks, John.

[Robert Turnham:]

Thanks, John.

[Operator:]

[Operator Instructions] Seeing no further questions, this concludes our question-and-answer session. I would like to turn the conference back over to Chairman and CEO, Gil Goodrich for any closing remarks.

[Walter Goodrich:]

Thank you, everyone. We appreciate you joining us this morning and we look forward to presenting our third quarter results to you in early November. Thank you.

[Operator:]

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