Goodrich Petroleum Corporation
Q4 2018 Earnings Call Transcript

Published: 5 Mar 2019

[Operator:]

Good morning, and welcome to the Goodrich Petroleum Fourth Quarter and Year-End 2018 Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please note that the 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, Nancy. Good morning, everyone. Thanks for participating in our fourth quarter and full-year 2018 call this morning. We are pleased to have an opportunity to share with you the result as well as discuss our ongoing activity and plans for 2019. In conjunction with the call, this morning, we have prepared a slide presentation, and we invite you to follow the slide deck during our prepared remarks. You can access the slide presentation on the Goodrich Petroleum website entitled 4Q and Year-end Earnings Presentation. The fourth quarter and full-year 2018 are both reflective of the success and tremendous progress we are making towards our goal of delivering superior value creation to our shareholders. The core of our strategy is rapid protection, cash flow and PDP reserve growth, while maintaining conservative debt metrics, which were at the low-end and we expect we'll remain at the low-end of our industry peers. To that end, 2018 was a very transformative year as we succeeded in more than doubling our net production. The greater than 100% increase in production also resulted in a more than doubling of the amount of EBITDA in which we reported a very strong finish to the year with EBITDA of $21.4 million in the fourth quarter. All of this is a testament to the quality and value of over core Haynesville position. In 2019, our planning, budget and guidance projections for another strong – project another strong year, where we again expect to essentially double net production and EBITDA versus 2018, while also expanding our cash margin through lower operating costs per unit of production. We are excited about how we are positioned and believe we will, again, deliver industry-leading growth in an otherwise challenging environment. I'll now turn to the slide presentation for those of you who would like to follow along. And our standard disclaimer forward-looking statements and risk factors are highlighted for you on Slide 2. On Slide 3, you will see a brief overview where we maintain our 10-year inventory of geologically derisked, high-return development drilling locations in the core of the Haynesville shale in Northwest Louisiana, which we were able to maintain versus a year ago through a series of small bolt-on lease acquisitions within the core. While we maintain upside exposure to crude oil through our Eagle Ford and TMS assets, the post-renaissance Haynesville shale is an exceptional play even today natural gas prices and is providing us the ability to rapidly grow our net production volumes, while maintaining low debt levels, improving debt adjusted per share growth and deliver top tier full cycle returns on invested capital. Production volumes continued their growth during the fourth quarter in which December volumes averaged approximately 100 million cubic feet of gas and equivalents per day and have subsequently increased, again, by approximately 25% to 30% with the recent addition of our Cason-Dickson 3H and 4H wells. Bob will provide you more details in just a minute, but our quarterly production growth led to strong EBITDA growth and solid net income in the fourth quarter. Our guidance for 2019 calls for capital spending between $90 million and $100 million and average daily production of 135 million to 145 million cubic feet of natural gas and equivalents per day in 2019. At current commodity prices, we expect this will deliver 2019 EBITDA essentially equal to our capital expenditures. On Slide 4, you will see our year-end 2018 SEC proved reserves, which grew to 480 Bcfe and under SEC pricing resulted in a PV10 of $418 million. Slide 5 provides a snapshot of our cap table, which as of December 31 had $27 million drawn on our senior credit facility and approximately $54 million outstanding on our second lien PIK notes. We are currently going through a redetermination of our borrowing base using our year-end reserves and we fully expect to refinance or amend our second lien notes in the near future. We have reporting both results to you at the appropriate time. Turning now to Slide 6. You will find detailed information on our 2019 guidance, which we recommend you review at your leisure and provide the ranges of expected full-year results on production, CapEx, natural gas price realizations, per unit costs as well as our planned activity for new wells to be drilled, their geographic location and current estimates of quarterly completion cadence, which you will see we expect to add four additional growth wells to production in the second quarter, which will provide another boost to net production volumes. Slide 7 illustrates, in short form, the tremendous progress we have made since emergence in growing our net production volumes as well as the expected doubling, again, production in 2019 to the midpoint of our guidance of approximately 140 million cubic feet of natural gas and equivalents per day. With that, I'll turn the call over to Rob, who will provide you a detailed review of the value proposition we offer investors, recent activity and results in the Haynesville as well as improving returns we are seeing from the Haynesville core.

[Robert Barker:]

Thanks, Gil. We had a very strong quarter across the board, where we beat consensus on revenue, EBITDA and earnings. Our revenues increased by 40% sequentially to $33.9 million, with an average realized price of $3.72 per Mcf equivalent. That was comprised of $3.50 per gas and $64.57 per barrel of oil. When including our cash settled derivatives, our average realized price was $3.45 per Mcf equivalent. Our per unit cash operating expense dropped by 8% sequentially to $1.17 per Mcf equivalent, resulting in a continuing expansion of our cash margin. We expect to see our total per unit cash operating expense to continue to drop at Haynesville Wells were added as these wells carried very low LOE and had no severance taxes until the earlier of payout in two years. As we shipped more capital in 2019 to our operated areas of Bethany-Longstreet, you will also see lower transportation fees fall through the income statement. In addition the EBITDA growing by 49% sequentially to $21.4 million, we posted earnings of $8.1 million or $0.68 per basic share, a significant beat over consensus earnings of approximately $6 million. Interest expense totaled $3.4 million in the quarter, which included cash interest of $400,000 incurred on the company's revolver and non-cash interest of $3 million incurred on the Company's convertible notes. The non-cash interest expense convertible notes. The non-cash interest expense was comprised of $1.8 million of paid in-kind interest and $1.2 million of amortization of debt discount. Moving back to our slide deck, as we have highlighted before, we have included several slides beginning with Slide 8 that show how we trade relative to our 50-company peer group. Review of Slides 8 through 10 will show you that the company still trades at a very cheap valuation, a little over 2x 2019 consensus EBITDA. Add the fact that we expect to maintain our debt-to-EBITDA through 2019 at 1 to 1.5 turns allows for a compelling argument as to why the company is undervalued. What is driving our significant growth in volumes and cash flow is our capital efficiency. Typically, capital efficiency is shown as a relationship of CapEx to growth and volumes, which if calculated would have us number one in our peer group, but we think it is more meaningful to show CapEx growth in EBITDA since we and the investment community are focused on returns, not growth in volumes. As you see on Slide 10, we ranked the second best company in our 50-company peer group at this capital efficiency metric, including Permian companies. In fact, if you eliminate companies who made acquisitions in 2018 that increased their projected EBITDA in 2019, we would rank first. It testifies that how these Haynesville Wells are generating superior returns regardless of the commodity, and I'll walk you through our economics shortly. On Slide 11, we currently have approximately 23,000 net acres in the core of the Haynesville with approximately 20,000 net acres in North Louisiana and 3,000 net acres in the Angelina River Trend of East Texas. Our North Louisiana acreage is approximately 80% undeveloped and 73% operated with 214 gross, 99 net locations as we entered the year. We have gridded our acreage with a plan to maximize long laterals and expect to continue to swap acreage or drill joint wells, will offset operators to further increase our long lateral inventory and operatorship percentage. We estimate a 10-year inventory at current CapEx ex rate and over 1 TCF of reserve exposure at 2.5 Bcf per 1,000 feet of lateral in North Louisiana alone. Moving to Slide 12. Activity remains high with over 50 rigs running in the play, which is more than any other gas basin due to high rates of return at current gas prices. All of our acreage has now been derisked and we are in development mode drilling predictable wells in proven areas and connecting those wells into existing pipes with excess capacity. We have allocated approximately 2/3 of our 2019 capital to Bethany-Longstreet and the other 1/3 to Thorn Lake area, where we recently announced a couple of wells that peaked at over 30 million cubic feet per day each. We continue to show an abundance of well results on our decline curved slides beginning on Slide 13. On Slides 13 and 14, we are tracking 59, 4,600-foot laterals with average profit of approximately 3,400 pounds per foot with two years of production on 28 of those wells. The composite production curve is generally following our 2.5 Bcf per 1,000-foot type curve as shown in red and our four operated well average is running well above the curve with higher proppant loading and interval spacing. Slides 15 and 16 reflect our 7,500-foot curves where we continue to show a composite of 87 wells with average proppant concentration of 3,100 pounds per foot, which, again, fits nicely with our 2.5 Bcf per 1,000-foot type curve. The older wells included in the composite curve are a handful of under-stimulated wells and we expect the composite results to pull up as the newer wells with higher proppant concentrations flow through over time. Our more recent operated wells, which carry higher proppant concentration are running above the high case curve. Slides 17 and 18 show composite results from 35 approximate 10,000-foot laterals with an average of 3,200 pounds per foot of proppant are also tracking our 2.5 Bcf per 1,000-foot type curves. Our six wells, which averaged approximately 9,500 feet of lateral and 3,700 pounds per foot of proppant are the most part tracking our 2.5 Bcf per 1,000-foot curve. There are many very good companies operating in North Louisiana and our results compare favorably. Slides 19 through 21 show that we are either first or second in cumulative production over three, six and 12-month periods. We also subscribe to a choke management program whereby we generally limit daily drawdown to 10 to 30 pounds, which we believe flattens the declines. We believe as data validates the quality of our acreage and optimum completion technique and maximizes cash flow generation, which is the number one driver in our corporate strategy. In general, there is a high correlation between longer laterals and higher proppant concentration to EUR, but we are more focused on IRR than EUR as return on capital employed is critical to creating a very profitable and growing enterprise. Our economics as shown on slides 22 to 24 show how exceptional this play is at current gas prices. We are now capturing the early time outperformance on our wells. And when you combine that with high netbacks, very low LOE at less than $0.05 per Mcf and no severance tax until the earlier of two years of payback, our returns not only compete or beat any natural gas base and they compete with most, if not all of oil basins. We have reduced our stage spacing to 100 to 125 feet, which has added more stages in a little to our CapEx per well, which by the way also includes a facilities estimate. As you will see it is worth based on our results. At $2.75 to $3 gas, we can generate 41% to 61% IRRs on short laterals, 65% to 89% IRRs on 7,500-foot laterals and 79% to 106% IRRs on long laterals. We have created our acreage and designed our drilling program to maximize returns, which are higher for longer laterals, but acreage configuration will also play into the ultimate development pattern. In summary, we are executing on all cylinders. Volumes are rapidly growing and per unit cash operating cost are falling, which is driving up our margin expansion and providing for a potential doubling of our EBITDA in 2019 over 2018 at current gas prices. The CapEx program for 2019 is designed to grow EBITDA dramatically while living within our means and keeping our debt metrics at very conservative levels. Whether you're an investor focused on value or growth, we check those boxes and look forward to delivering exceptional returns to our shareholders. With that, I'll turn it back to Nancy for Q&A.

[Operator:]

Thank you. We will now begin the question-and-answer session. [Operator Instructions] The first question comes from Welles Fitzpatrick from SunTrust. Please go ahead.

[Welles Fitzpatrick:]

Hey, good morning and happy [indiscernible].

[Walter Goodrich:]

[Indiscernible]

[Welles Fitzpatrick:]

I would miss this call. Well, Can we talk a little bit – the Angelina River Trend acreage BP others, they keep knocking it out of the park there. So it's obviously a huge asset. At the same time, if you get AFE, it seems like you can grow that CapEx guidance. Can you talk a little bit about how you see that fitting into the portfolio going forward?

[Walter Goodrich:]

Sure. Well, this is Gil. As you probably remember, we did make a sale of a portion of our acreage down there to BP for over $20 million last year. We thought that made sense. We were able to drag that capital forward, put it to work up in the core. I would say pretty much the same thing. As we have said many times, that acreage is a good, deeper – the Haynesville is a good, hotter, pressures were higher, and therefore, our capital costs are going to be higher, call it a $1 million to $1.5 million higher for a similar type well. We're still waiting to get enough on the production history that would demonstrate spending that incremental dollar is something worth doing at this point of time and we've got so much to do that in Northwest Louisiana core, that's the place that it makes sense for us to be spending our capital. So we kind of like keeping the 3,000 or so acreage we've got down there as some upside for us. Someone came in long and after this right price, we might consider dragging that capital up to the core and a little bit. But we currently say we're pretty happy with that mix and focusing on the core North Louisiana.

[Welles Fitzpatrick:]

Okay. Now that makes total sense. And then, if we can talk about the kind of rig moves, obviously, you guys have been working at Thorn Lake and then you happen to be at Bethany-Longstreet with two-thirds and one-thirds split. Is that rig going to go back to Thorn Lake towards the end of the year? What you guys got done in the first quarter? Does that represent the whole one-third for that area?

[Robert Barker:]

Yes, Welles. This is Rob. No, it's going back to drill two additional wells kind of late second quarter. There were basically five well – we had these two that were completed and two more to go with basically was a six-well commitment to drill it all up. We felt that it was beneficial to go ahead and get those wells on line in a similar timeframe. So we have two additional wells that we're building. One, is about 6,000-foot lateral and the other one is of 10,000-foot lateral, and that's incorporated into our completion cadence guidance in the presentation. Everything else really is budgeted for Bethany-Longstreet, we recently cut even more attractive gathering agreements in Bethany-Longstreet for operated wells. So once those wells start following through the income statement, you will start to see the gathering fee go down, again. Thorn Lake carries a higher gathering fee than Bethany-Longstreet, but either way, this year's gathering fee when you blend it is going to be lower than where we were in the fourth quarter.

[Welles Fitzpatrick:]

Okay. And then one last one. For the 2019 program, are you drilling all those wells at 880 spacing? Or there is a little bit broader? Could you just remind us on that?

[Robert Barker:]

Yes. So very good question. So Cason-Dickson wells are 880s between wells and they're fully – we're basically fully developing that block. When you look back at Bethany-Longstreet like the two Loftus wells that will be completed within 30 to 45days, those don't have any wells anywhere close to them. So those are going to be new wells, which will not likely require shutting in of old parent wells or new wells that we've been drilling. So that will be very helpful. We have a couple of additional Loftus wells that won't get fracked until January of next year. That will be two additional wells in the same sections as these two Loftus wells. So everything else is kind of a well that's on it's is own, which will obviously help on volumes and that we won't have to shut existing wells in.

[Welles Fitzpatrick:]

Okay. That’s perfect. I appreciate it. Congrats on the quarter, and for the record I like the purple, green, and gold that you guys have on Slide number 4.

[Robert Barker:]

Okay. Thanks Welles.

[Operator:]

The next question comes from Mr. Jeff Grampp from Northland Capital Markets. Go ahead please.

[Jeffrey Grampp:]

Good morning, guys.

[Walter Goodrich:]

Hi, Jeff.

[Jeffrey Grampp:]

Wanted to pick Gil's brain on kind of optimal lateral lengths in the play, I know traditionally longer is better and the type curves suggests as such. But it seems like you guys are getting some pretty strong outperformance on the one mile lateral, so I was just curious if that's giving you any different thoughts about optimal lateral lengths? Or is it still as simple as you get the cost efficiencies on the TMS side for longer still better?

[Walter Goodrich:]

Yes. So it’s a really good question, Jeff, and I kind of alluded a little bit to it in my remarks. You start with your acreage and then you grid that acreage in an attempt to maximize your longer laterals, but clearly, if you have an area where you have three sections or 640-acre units on top of each other, then it dictates that you drill 7,500-foot laterals north and south to maximize that – the capture of that acreage and we have quite a bit of that in Bethany-Longstreet. Our 4600s have outperformed. All 4600s, we think it's a completion technique where we've tightened the intervals and increased the profit loading. Another thing that you factor in and we talked about this at the DUG Conference, 7,500-foot laterals you can split those out pretty easily without busting your AFE. If you're between 7,500 and 10,000-foot laterals, it just adds time on your bid assembly in motors. So the question is the longer the lateral does generate better returns, but what is the risk of increasing or spending more money than AFE? It's a little bit higher. So we and other operators, I think, is the reason you see more 7500s than anything is the ability to kind of hit it on AFE and generate really good returns, and on top of that, the unit acreage configuration.

[Jeffrey Grampp:]

Got it. That’s really helpful. And my follow-up, and you guys, I think, touched on it in the prepared remarks, inventory looks basically unchanged year-over-year as a result of adding some of the tuck-ins and swaps you guys did. Is it – as you guys kind of see the market today, do you think that's – can you replicate that in 2019? Or maybe can you just touch on, I guess, both your comfort level with your inventory and prospects of future kind of bolt-ons and swaps and things like that?

[Walter Goodrich:]

Yes, Jeff. Good morning. This is Gil. So correct, we were fortunate enough to a series of fairly small bolt-ons in 2018 to effectively replenish the inventory that we drilled up in 2018. So we're very pleased with that. We are optimistic that we'll be able to duplicate that and maybe even get lucky and do a little bit better in 2019. Obviously, no deals done until it's done, but there are a number of smaller transactions that we are currently working on that would lead us to be able to replenish most if not all drill in 2019. So I think I'll just leave it at that. We feel good about it. We like the inventory. We'd love to add more the problem is that the Haynesville core is largely, as you know, locked down by a handful of players. And so transactions of size are going to be more challenging, obviously bigger. We've got some challenges on our balance sheet. So we'll look for bigger opportunities, but in the meantime we're working very hard to keeping bolting-on on very small deals that could replenish the inventory.

[Jeffrey Grampp:]

All right. Understood. I appreciate for the time guys. Nice quarter.

[Walter Goodrich:]

Thank you, Jeff.

[Robert Barker:]

Thanks, Jeff.

[Operator:]

The next question comes from David Beard from Coker & Palmer. Go ahead please.

[David Beard:]

Hey, good morning, gentlemen. Congratulations on the quarter.

[Walter Goodrich:]

Good morning.

[Robert Barker:]

Thanks, Dave.

[David Beard:]

Maybe if I missed it, but I don't know, did you or could you give us some color on 2019 exit production rate and a follow-on to that would be, if you hold CapEx around that $100 million and I know you got lot of moving parts, but what is that look like for 2020 production growth?

[Walter Goodrich:]

Yes. So we're not prepared to give 2020 guidance at this point in time, David. But that would be the first thing. In terms of an exit rate, as we've said, we will double production. We think, we'll essentially double production calendar year over calendar year. Whether or not that gets us to an exit rate of exactly $200 million, we obviously entered this year at approximately 100 million cubic feet of gas a day. We'll depend on some timing. I would tend to think there is a little less than 200 million a day as an exit rate, again, depending on timing of completions of wells because that cadence really matters. But we could with $100 million CapEx obviously generate – in our mind and under current commodity prices for 2020, generate free cash flow with $100 million program. Obviously, in doing so and adding cash, we would not grow as fast as a rate. So again without giving any guidance, I would – if you want to think about it in terms of modeling, I'll putting another 50% or so growth in 2020 over 2019.

[Robert Barker:]

And David just to accentuate what Gil said earlier, if you look at the completion cadence, second quarter and third quarter of this year, you're adding seven gross, six net wells of our 10. So clearly the production is going to surge in the second quarter and feed through the third quarter and then a little less completion activity in the fourth quarter. We'll see based on timing if that still plays out. But we do have a couple of wells that we're expecting to frac right at January 1 that will be long laterals. And as we've said in the press release and previous remarks, if commodity prices are supportive and we think back half of the year could be very interesting with a lot of incremental demand coming online, then you could see us accelerate the completion of those two wells, which will – would obviously have us growing a good bit more and exiting in a much more robust number.

[David Beard:]

Right, understood. I know there's a lot of moving parts and I appreciate all the color.

[Walter Goodrich:]

Thanks, David.

[Robert Barker:]

Thanks, David.

[Operator:]

The next question comes from Eli Kantor from IFS Securities. Go ahead please.

[Eli Kantor:]

Hey, Good morning, guys.

[Walter Goodrich:]

Good morning, Eli.

[Eli Kantor:]

Can you talk about any changes that you're seeing on the service cost front. And remind us what level of service cost inflation or deflation if any of these in the 2019 data?

[Walter Goodrich:]

Yes. We’re holding our estimates flat, mainly because we’ve seen lower service cost and particularly on the frac side. At the peak, we'll probably spending $10,000 a stage where, call it, 35%, 40% less than that, that's not apples-to-apples, we're using local sand. We're pumping more stages and tighter intervals therefore less sand per stage. So I think service companies are likely making some money, but it's certainly saving us a decent amount and the reason our CapEx is shown slightly higher just pumping more stages on these wells, which as I said is really proved good on our results. I would say rig rates are probably up a little bit from last year. However, as you are seeing rig utilizations is dropping. So we expect to not really see a whole lot of price inflation on that side of it. So it feels pretty flattish to us. It all depends on commodity prices and activity levels from here however.

[Eli Kantor:]

And then can you give us an update on your plans regarding the Eagle Ford and TMS position?

[Walter Goodrich:]

Yes. This is Gil. We like both for your upside potential. The good news for us is we don't need to spend any capital down there and what we are seeing is a renewed or increased level of activity directly offsetting our acreage in both places. You may have seen that Australis operator, who bought Encana's position and then TMS, has recently completed a well approximately 1,100 barrels of oil equivalent per day in their IP40. That's in the range of what we would have expected and again, proves the great quality of the TMS itself. I think what the TMS needs in addition to a little bit better oil prices is just some consistency of $10 million or sub-$10 million of well cost and then that play will, again, have its day. So we like where we are. We are happy to sit on our acreage, it’s largely held by production. And in the Eagle Ford, there's been a bit of a renaissance in the area with new operators coming in. They're permitted and/or drilled a number of new longer laterals Eagle Ford wells, so again we’re kind of happy to see that play out. And if someone want to come to us with a very strong offer to take us out of that position, we would certainly take a hard look at it.

[Eli Kantor:]

Thanks for the color.

[Operator:]

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

[John White:]

Good morning, gentlemen.

[Walter Goodrich:]

Hi, John.

[John White:]

You talked about some of the drilling and completion activity and you reduced stage length. Has there been any changes in the type of proppant that you're using as we've moved through 2018?

[Walter Goodrich:]

No, John, I think – this is Gil. In early 2018 we switched from Northern White to local or at least predominantly local sand. We can tell you that virtually every other Haynesville operators pumping some version of local sand. That's helped, as Rob said in his comments to reduce costs. And we're continuing to pump effectively local sand on all their jobs.

[John White:]

And what sizes are you predominantly using?

[Robert Barker:]

This is Rob. John, we start with a 100 mesh, that's probably 10% of our job, and then we finish it with 40-70. In some cases, we make tail-in with a little bit of Northern White, but as Gil said really the vast majority, if not all, is local.

[John White:]

I'm not seeing the type of progression as we've seen in other basins. So were you guys have executed in 2018 like you were reading a script? So congratulations on the year.

[Robert Barker:]

Thank you, John. Thanks for the support.

[Operator:]

Our next question comes from Rehan Rashid from B. Riley FBR. Please go ahead.

[Rehan Rashid:]

Good morning, guys. Thank you. Two quick questions. One on the sand front, the local sand, I presume you have seen enough history to be comfortable using that over the long-haul. And then second takeaway from the basin, just talk that as more Permian heads towards Perryville, as there's more Marcellus that heads down towards the Gulf Coast. There might be limitation on aggregate Haynesville growth from this point forward and its ability to go down to the Gulf Coast basically. Any thoughts on that those two places?

[Walter Goodrich:]

Yes. Rehan, this is Gil. I’ll take the first part of that. I would say that the initial wells pumping predominantly or exclusively local sand are pushing close to two years on now and that the number of wells has been dramatically increasing over the last two years. As we go back to years and we look at those locally pumped – local sand pumped wells versus Northern White wells, we are hard-pressed to see any difference over that two-year period between the Northern White wells and the local wells. And as I said in my comments few minutes ago, virtually every operator in the play today is pumping something close to or exclusively local sand. So we are in a crowd of virtually everybody else. It’s very comfortable with that. And the cost savings is leading to significant increases in IRR just giving the lower cost of popping the local today. And everybody kind of feels like, if there is a point out in the future where it needs some remedial work, restimulation or something, then that's still dollars ahead, but doing what we're doing today.

[Robert Barker:]

And then Rehan, I’ll jump in on the takeaway. So we sell our gas at the lease. We have high demand from purchasers to buy the gas. We have pipes that go either east to Perryville or west into Carthage, it ultimately some of that gas obviously makes its way to the Gulf Coast and there's two or three pipes in the works taking gas from North Louisiana to the Gulf Coast. So we’re not seeing any effects of it yet, perhaps it gets tighter at some point in the future, but with multiple outlets, we feel comfortable that we're really not going to see either or below add-on basis or takeaway capacity reduced to a point where you're finding the Marcellus gas for it. I think there is – it's an obvious need as the Haynesville grows to take that gas to feed the LNG export market on the Gulf Coast and that's why these pipelines are moving forward pretty fast.

[Rehan Rashid:]

Okay, thank you.

[Robert Barker:]

Thanks.

[Operator:]

[Operator Instructions] This concludes our question-and-answer session. I would like to turn the conference back over to Gil Goodrich for any closing remarks.

[Walter Goodrich:]

Thank you, everyone. We appreciate your participation this morning. As we said earlier, we're very excited about where we're positioned and look forward to delivering the exceptional growth again in 2019. Thank you.

[Operator:]

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