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Edited Transcript of GDPAO.PK earnings conference call or presentation 7-Nov-19 4:00pm GMT

Q3 2019 Goodrich Petroleum Corp Earnings Call

HOUSTON Nov 26, 2019 (Thomson StreetEvents) -- Edited Transcript of Goodrich Petroleum Corp earnings conference call or presentation Thursday, November 7, 2019 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Robert T. Barker

Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO

* Walter G. Goodrich

Goodrich Petroleum Corporation - Chairman & CEO

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Conference Call Participants

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* Joseph David Allman

Robert W. Baird & Co. Incorporated, Research Division - Senior Research Analyst

* Welles Westfeldt Fitzpatrick

SunTrust Robinson Humphrey, Inc., Research Division - Analyst

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Presentation

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Operator [1]

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Good morning, and welcome to the Goodrich Petroleum Corporation's Third Quarter 2019 Earnings Conference Call. (Operator Instructions) Please note, this event is being recorded.

I would now like to turn the conference over to Gil Goodrich, Chairman and CEO. Please go ahead.

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Walter G. Goodrich, Goodrich Petroleum Corporation - Chairman & CEO [2]

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Thank you, and good morning, everyone. Thanks for participating in our third quarter earnings call this morning. Despite extraordinarily weak natural gas prices in the quarter, we again achieved solid EBITDA for the quarter on the strength of our hedge position and lower lease operating expenses. As has become our practice, we have again prepared a slide presentation, and we invite you to follow of the slide deck during our prepared remarks this morning. You can access the slide presentation on the Goodrich Petroleum website entitled 3Q '19 Earnings Presentation.

While we maintain a 1 rig drilling program in the Haynesville, we slowed the completion cadence during the third quarter with only 1 gross and 0.9 net wells completed in the quarter. We are currently fracking our Loftus 27 and 34 1H well, which is a 7,500 foot lateral in the Bethany-Longstreet Field, and we expect initial production in the third week of this month.

Looking forward, we are monitoring the markets closely, but our current expectation is that we will build some drilled but uncompleted wells or DUDs as we enter 2020, including 3 drilled and currently uncompleted 10,000 foot nonoperated Haynesville wells in the Bethany-Longstreet Field.

We will review a range of CapEx and budget options for 2020 with our Board in early December, and given our current hedge position and 2020 natural gas future strip prices, we are confident in our ability to both reduce full year CapEx compared to this year and grow production volumes more modestly, while generating an attractive free cash flow yield. Once our Board has formally approved the preliminary plan for 2020, we'll provide you with more details on the budget and planning for next year.

As I said, operationally, we continue running 1 rig in the core of the Haynesville and Northwest Louisiana, and this morning, we announced the completion of our Harris 2H well in the Thorn Lake field, which is -- which was recently completed as a 9,400 foot lateral in Red River Parish.

I will now turn to the slide presentation for those of you who would like to follow along and our standard disclaimer, forward-looking statements and risks factors are highlighted for you on Slide 2.

On Slide 3, we have, again, included an overview of the company and our assets, which highlights our core Haynesville shale position in Northwest Louisiana, where we continue to maintain a 10-year net inventory of delineated development locations, which contain over 1 Tcf of natural gas reserve potential. While we maintain upside exposure to crude oil through our Eagle Ford and TMS assets, all of our current activity is focused on the core Northwest Louisiana, Haynesville. Our Haynesville position is yielding low finding cost, decreasing per-unit expenses, solid rates of return on capital invested. At the end of the third quarter, our calculated return on capital employed was 17% when annualizing 3Q EBIT.

As I said earlier, the strength of our hedge position and lower per-unit LOE led to third quarter EBITDA of $21.3 million and an EBITDA margin of 64%.

On Slide 4, we again highlight our year-end 2018 SEC-proved reserves of 480 Bcfe, which had a present value at 10% of $418 million.

On Slide 5, we provide an updated cap table as of the end of the third quarter. During the third quarter, our borrowing base under our senior credit facility was redetermined, which resulted in a $10 million increase from the initial borrowing base in May to $125 million. Our third quarter annualized EBITDA equals $85.2 million, and when compared to approximately $99 million of net debt results in a net debt to EBITDA of just over 1.1x.

Turning to Slide 6, we have updated our quarterly production chart to illustrate our production growth over the last few quarters and couple of years as well as the current expectation for the fourth quarter of this year. As I said a minute ago, we continue to watch the markets and set the appropriate completion cadence designed to achieve the right rate of growth and generate free cash flow.

On Slide 7, we have updated the detailed volume and price information on our current natural gas and crude oil hedge positions. As you can see, we are very well hedged for the remainder of this year with 100 million cubic feet of natural gas hedged at $2.89 per Mcfe, which represents a little over 75% of the reported third quarter natural gas volumes hedged at these prices.

During the third quarter, we added to our natural gas hedge position in 2020 and early 2021 with a combination of additional swaps and costless colors, which now provides us solid downside protection equal to almost 50% of anticipated 4Q '19 production through that period of time. We continue to watch the natural gas markets closely and look for additional opportunities to hedge our additional -- add to our additional hedge position and support and protect our capital planning.

Finally, we have updated our 2019 guidance on Slide 8 to adjust for the current anticipated completion cadence and a midpoint of production guidance for the full year to approximately 130 million cubic feet of natural gas and equivalents per day. In addition, the guidance provides the anticipated ranges for per-unit cash expenses of LOE, taxes, transportation and cash G&A. The quarterly completion cadence reflects the adjustment to our 2019 gross and net well counts, in particular the adjusted cadence, I mentioned earlier, where we have 3 nonoperated wells in Bethany-Longstreet, in which we have a 25% work interest that we now expect will get completed in early 2020.

And with that, I'll turn the call over to Rob.

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [3]

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Thanks, Gil. Revenues totaled $27.2 million in the quarter with an average realized price of $2.01 per Mcf, $59.67 per barrel of oil and $2.17 per MCF equivalent. When adjusted for our settled hedges, revenues were $33.1 million with an average realized price of $2.65 per Mcf equivalent, down $0.05 from the previous quarter.

Our per-unit cash operating expense, which is defined as operating expenses, excluding DDNA and noncash G&A, continued to drop in the quarter, decreasing by 23% over the prior year period and 5% sequentially to $0.98 per Mcf equivalent. The sequential drop in per-unit cash cost was driven by a reduction in LOE by 13%, the $0.21 per Mcf equivalent and transportation and processing by 11% to $0.41 per Mcfe.

Capital expenditures for the quarter totaled $25.5 million of which 97% was spent on drilling and completion cost associated with Haynesville wells. We expect to spend $10 million to $15 million in the fourth quarter as we complete 2 gross 1.7 net wells and enter the year with 5 gross, 2.5 net Haynesville wells drilled but uncompleted.

Interest expense totaled $2 million in the quarter, which included cash interest of $1.2 million incurred on the company's revolver and noncash interest of $800,000 incurred on the company's convertible notes. The noncash interest expense was comprised of $400,000 of paid-in-kind interest and $400,000 of amortization of debt discount and debt issuance cost associated with the company's second lien note insurance.

The interest expense for the quarter decreased by $1.1 million from the prior year period due to refinancing the majority of our old second lien notes with our revolver, which carries a much lower interest rate.

Moving back to our slide deck, as we have highlighted before, we have included several slides beginning with Slide 9 that show how we compare to 55-company peer group. As Gil said earlier, and as you will see on Slide 9, our return on capital employed for the quarter was 17%, despite very low commodity prices, which ranks in the upper tier in the peer group as of October 30.

Moving to Slide 10, if we were to show true capital efficiency, defined as CapEx to growth in volumes, we would likely be at or near the top of the rankings due to making very high-volume wells, but we believe a more compelling evaluation is a modified definition being CapEx to growth in EBITDA as everyone is focused on returns versus production growth. As you see, we rank very high again on this modified capital efficiency analysis as our returns, including our hedges, are extremely competitive even when comparing to oil basins as evidenced, again, by our return on capital employed. Under this modified capital-efficiency analysis, there are fewer companies in the peer group due to fewer companies actually growing EBITDA year-over-year.

In addition to returns, it is critical to maintain low leverage in these challenging times for commodity prices, and we're focused on maintaining a debt-to-EBITDA ratio of 1.5x or less, and as Gil stated earlier, we stood at 1.1x annualized and 1.25x trailing 12-month EBITDA at the end of this quarter.

Even though our capital efficiency and return on capital employed are near the top of the peer group and our debt to EBITDA is extremely conservative, we only trade at a little over 2.5x consensus enterprise value to '19 EBITDA, as shown on Slide 12.

As everyone likely knows by now, all of our current activities are centered in the core of the Haynesville, beginning on slides 13 and 14. We entered the year with 22,600 net acres in North Louisiana and 214 gross, 99 net locations on spacing of 880 feet between wellbores. As reflected in our first quarter 10-Q, we sold a small portion of our Greenwood-Waskom acreage that we viewed as out of the core and leaving approximately 22,000 net acres currently. The acreage that was sold was not originally in our 214 gross, 99 net location count, therefore, that count does not go down.

As Gil alluded to earlier, we and the operator of 3 nonoperated wells made the decision to defer completions on 4 gross, 1.75 net wells due to low gas prices at the time, which have obviously rallied a good bit since the decisions were made. We expect to have 5 gross, 2.5 net drilled but uncompleted wells as we enter the year, and all 5 are expected to be fracked in the first quarter of 2020, with 4 of the 5 currently expected to commence fracking operations in January.

As stated in the press release, this deferment affected fourth quarter volumes by 14 million cubic feet per day but sets us up well for a surge in volumes early in 2020 and hopefully, higher prices which will provide momentum for the year from which we can deliver a very good free cash flow yield to our shareholders.

Due to the deferred completions, we now expect to complete 8 gross, 7.2 net locations this year, down [2.1] net wells from previous guidance. At this completion cadence, we will lengthen our inventory life from 18 gross, 10 net wells currently to approximately 25 gross, 12.5 net years from North Louisiana only as we enter 2020. The acreage in North Louisiana is over 70% undeveloped and 73% operated. We have gridded our acreage with the plan to maximize long laterals and expect to continue to swap acreage or drill joint wells with offset operators to further increase our long lateral inventory.

As Gil said, we estimate over 1 Tcf of reserve exposure at 2.5 Bcf per 1,000 feet of lateral and 880 foot spacing in North Louisiana alone versus year-end '18 book-proved reserves in North Louisiana of 471 Bcf equivalent.

We also maintain approximately 3,000 net acres held by production in Angelina River Trend of the Shelby Trough for future development. The Haynesville and Bossier formations are both prospective on our Angelina River Trend acreage.

As shown on Slide 15, all of our acreage has now been derisked, and we are in development mode, drilling predictable wells, improving areas and connecting wells into existing pipes with excess capacity. We have allocated approximately 2/3 of our 2019 capital expenditure budget to Bethany-Longstreet and the other 1/3 to the Thorn Lake area. We announced another well result with this release, as Gil stated, which was a 9,400 foot lateral in Thorn Lake at a stable 24-hour production rate of 26 million cubic feet per day, which is similar with its closest offset. This is the sixth new vintage well we've drilled in Thorn Lake on an approximate 1,280-acre unit, and as we stated in the press release, our previous 5 new vintage wells have produced an average of 7 Bcf in 13 months from an average lateral length of 6,900 feet, and the wells continue to produce at high rates. We are currently drilling our last well in the acreage with plans to frack that well in January.

On Slide 16, we are tracking 299 4,600 foot laterals with average proppant of approximately 3,100 pounds per foot. As you will see, the older wells are underperforming the newer wells, as average proppant is lower on the older wells. Our 6 wells shown in green were stimulated with approximately 4,100 pounds per foot of proppant loading, and they're not only a good bit better than the prop -- than the industry average composite curve, they -- but they exceed our 2.5 Bcf per 1,000 foot curve by a good bit. In fact, our more recent wells are pulling up the composite curve over time, which we expect to continue.

Slide 17 reflects our 7,500-foot curve, where we now show a composite of 206 industry wells with average proppant concentration of approximately 3,000 pounds per foot, which, for the most part, fits our 2.5 Bcf per 1,000 foot type curve. The older wells included in the composite curve are a handful of understimulated wells with approximately 2,400 pounds per foot and the newer wells average 3,500 pounds per foot, which we expect, again, will pull up the curve as the newer wells flow through over time. Our more recent operated wells, which carry higher proppant concentration are running well above the 2.5 Bcf per 1,000 foot curve.

Slide 18, which now shows a composite result from 187 10,000 foot laterals with an average of 3,000 pounds per foot of proppant, are also tracking our 2.5 Bcf per 1,000 foot type curve until the older wells with lower proppant concentration kick in a little over 2 years out. Our 9 wells, which average approximately 9,600 feet of lateral and 3,500 pounds per foot of proppant, are for the most part tracking our 2.5 Bcf per 1,000 foot curve.

We believe this data validates the quality of our acreage and optimum completion and flowback technique and maximize cash flow generation, which is the #1 driver in our corporate strategy. In general, there is a high correlation between tighter interval spacing and higher proppant concentration to EUR, but as we have said before, we are more focused on the returns we are generating versus just EURs, return on capital employed is our primary objective.

Our economics, as shown on Slide 19 through 21, show how exceptional this play is at reasonable gas prices. If you bake in our hedges of 100 million cubic feet per day at $2.89 through the end of the year, we should average predifferential in the $2.65 to $2.75 range, which would generate approximately 55% to 65% IRR at the midpoint for our average lateral length for the year using our 7,500 foot curve and assumptions. We capture the early time outperformance on our wells, and when you combine that with high netbacks relative to other gas basins, very low LOE, initially at less than $0.05 per Mcf and no severance tax until the earlier of 2 years of payout. Our returns are very competitive with any basin as evidenced by our 17% return on capital employed for the quarter at similar pricing.

In summary, we can't control commodity prices, but we have a balance sheet that carries low debt metrics, an asset that is working very well, a nice hedge position that is minimizing our commodity price risk, a unit cost structure that is declining, creating very attractive margins and a capital efficiency and return on capital employed that competes with any basin.

With that, I'll turn it back to the operator for Q&A.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from Welles Fitzpatrick with SunTrust.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [2]

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You guys talked to it in the prepared remarks, but the delayed completions due to gas pricing, to be clear, that was Henry Hub pricing, not any basis issues, is that correct interpretation?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [3]

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Yes, Welles, this is Rob. Yes, clearly, we monitored NYMEX just like anyone else, and Henry Hub can fluctuate but ultimately gets back at the end of the contract term. But yes, it's all about gas prices. Obviously, gas prices have moved dramatically over the last 30 or 45 days. Those decisions were made at a much lower price per Mcf than what we currently see, but we're going to stick to our guns. We think the market is balancing. We think prices assuming weather continues to be cold as it has been in November, the prices likely could get better. And I think as you pointed out in your morning note, price realization, Henry Hub less $0.20 to $0.30, frankly, it has been widely fluctuating on a daily basis. In fact, yesterday, I think it was $0.09 -- $0.05, yesterday. So I mean it's all over the place. It's a product of supply and demand. We expect the basis to tighten back as more Marcellus gas stays in the Northeast, and in the shoulder months, the basis widens. So the question is just where is it going to stabilize? We think it's a product of just overall supply versus demand and regional demand, primarily the Marcellus sucking up that Marcellus gas.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [4]

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Okay. No, that makes sense. And I know we had a sidebar on it, but it's great to see the public E&P is essentially flat if you believe consensus year-over-year and the same year, you're still going to get 34 bs of LNG demand.

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [5]

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Correct.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [6]

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The -- and I'm sorry, if you hit this in your prepared remarks, but the pipeline maintenance that hit you in Q3, is that ongoing or has that been resolved?

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Walter G. Goodrich, Goodrich Petroleum Corporation - Chairman & CEO [7]

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No. This is Gil. That was a phenomenon that came as a supplier to us, but is now behind us and all those wells are back on at full rate.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [8]

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Okay. Perfect. And then just one last one from me. Obviously, both the Harris 23 and 14 are great wells. On a per foot one, the 23 is a little bit below. I assume that's for the same reason it always is when you have a longer lateral, but it's just kind of choking itself off. Is that a fair interpretation?

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Walter G. Goodrich, Goodrich Petroleum Corporation - Chairman & CEO [9]

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Yes, I think that we probably held that one back a little bit more. As Rob mentioned in his prepared remarks, we do have several other wells in that area and they really are fantastic wells, and we didn't feel like it was necessary to push it. So we just kind of held the choke to try to, we think, get a little bit flatter curve over time. So that's why that piece of a little bit lower per 1,000.

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Operator [10]

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Our next question comes from Joe Allman with Baird.

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Joseph David Allman, Robert W. Baird & Co. Incorporated, Research Division - Senior Research Analyst [11]

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My question is on capital efficiency. So -- and I saw all the things you put in the presentation on capital efficiency. But like my main metric for capital efficiency is PD F&D. So when we look at 2019, say, versus 2018, do you think that capital efficiency has improved in 2019 versus 2018? And then even during 2019, do you think as the years progress that you've improved capital efficiency? And I know Slide 16 to 18 kind of help address some of it, what are the factors if, in fact, capital efficiency has improved, what are the factors that are helping to improve capital efficiency?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [12]

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Well, Joe, this is Rob. I'll tell you, first of all it's up to Netherland Sewell, who prepares our -- 100% of our gas reserves as to what those EURs are. We continue to plot against 2.5 Bcf per 1,000 feet. They're a little bit less than that mainly because they take the future off at a steeper pitch. So their terminal decline rate, they may pick a point in time in the future and just take it off steeper to be more conservative. So that clearly factors into proved developed finding cost. I will say that we've added a number of these wells, in particular, Thorn Lake, and we've got 2 Loftus wells. They're just -- that have been really good, another well called our Melody Jones has been very good. So again, we'll just have to see at the end of the year, whether those get us a lower proved developed finding and development cost. Our DD&A rate was $1.06, I think, which is certainly reflective of finding cost over time, and we'll just have to see. But the well results frankly, as you know because you plot Haynesville operators by foot, show us as #1 productive wells by foot, and we expect that to translate well once we deliver our reserve report at year-end.

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Joseph David Allman, Robert W. Baird & Co. Incorporated, Research Division - Senior Research Analyst [13]

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Got it. So in terms in the numerator of that equation, so have you seen things improved kind of in the numerators in terms of cost per well as -- in 2019 versus 2018 and even through 2019?

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Robert T. Barker, Goodrich Petroleum Corporation - Senior VP, Controller, CAO & CFO [14]

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Yes, so -- yes, just as a follow-up on that. So I think and maybe we've discussed this with you and certainly with others before. We are really focused on increasing our well results versus cutting cost because we see real benefit, in particular, because of our hedge book and delivering the best production results that we can. And so that's why instead of adjusting our CapEx numbers in our economic slides down because of lower service costs, we basically kept those costs similar, and we're tightening our frac intervals, which -- even though the cost per stage is a lot lower than it used to be. We're doing more stages because we're doing tighter frac interval spacing. And we just -- we see the benefit instead of keeping the completion the same as what we were doing back when we were pumping a stage over 150 to 200 feet, we've reduced it on average to about 125 feet. And again, even though the price per stage is a good bit lower, the costs are similar on our assumptions. And so I think all things being equal, we would hope to have a similar improved -- a similar DD&A rate as we enter 2020. But again, it's out of our control until we see the Netherland, Sewell report.

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Operator [15]

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(Operator Instructions) If there are no further questions, I would like to turn the conference back over to Gil Goodrich for any closing remarks.

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Walter G. Goodrich, Goodrich Petroleum Corporation - Chairman & CEO [16]

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Yes, thank you very much. We appreciate everyone's participation this morning, and we look forward to reporting our fourth quarter numbers to you at year-end early in 2020.

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Operator [17]

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