Canacol Energy Ltd

Good morning and welcome to Canacol’s third quarter 2019 earnings conference call. This is Carolina Orozco, Director of Investor Relations.

I am with Mr. Charle Gamba, President and Chief Executive Officer; Mr.

Jason Bednar, Chief Financial Officer; and Mr. Ravi Sharma, Chief Operating Officer.

Before we begin, it is important to mention that the comments in this call by Canacol’s senior management team can include projections of the Corporation’s future performance. These projections neither constitute any commitment as to future results nor take into account risks or uncertainties that could materialize.

As a result, Canacol assumes no responsibility in the event that future results are different from the projections shared on this conference call. Please note that all finance figures on this call are denominated in U.S.

dollars. We will begin the presentation with our Chief Financial Officer, Mr.

Jason Bednar, who will discuss financial highlights; followed by Mr. Ravi Sharma, our Chief Operating Officer, who will cover the operational highlights for the third quarter 2019.

Mr. Gamba will close with a discussion of the Corporation’s outlook for fiscal year 2019 and beyond.

Mr. Gamba and Mr.

Sharma are joining us from Bogota, and Mr. Bednar is joining us from Calgary.

A Q&A session will follow Mr. Gamba’s closing segment.

I will now turn the call over to Mr. Jason Bednar, Chief Financial Officer of Canacol Energy.

Thank you, Carolina, and welcome everyone to our third quarter conference call. Q3 was a historical quarter for Canacol, as it marked the completion of the new 100 million cubic feet of production pipeline expansion, which was finalized in late August 2019, resulting in record natural gas sales and production revenues.

Total natural gas revenues net of royalties and transportation expenses for the 3 months ended September 30, 2019, increased 25% to $55.1 million compared to $43.9 million for the same period in 2018. Funds from operations increased 41% to $36.4 million for the three months ended September 30, 2019, compared to $25.8 million for the same period in 2018.

Funds from operations per share increased 33% from $0.15 per share to $0.20 per share. The Corporation realized an EBITDAX of $46 million and $122.9 million for the 3 and 9 months ended September 30 respectively, compared to $36 million and $105 million for the same periods in 2018, respectively.

For the quarter ended September 30, 2019, total realized contractual sales were 26,020 barrels of oil equivalent per day, including 146.4 million cubic feet of gas a day and 329 barrels of oil a day from our Rancho Hermoso property for the quarter. As you can see, Canacol generated a 146.4 million cubic feet a day of gas sales in Q3, which is a 27% increase over the 115.3 million cubic feet day that we averaged in Q3 of 2018.

We anticipate total realized contractual sales to increase from 2019 corporate guidance of 150 million standard cubic feet per day to over 200 million standard cubic feet per day in 2020. The average natural gas sales price net of transportation was $4.84 per Mcf during the 9 months ended September 30, 2019, which is higher than our announced 2019 guidance of $4.75 per Mcf.

The sales prices of the Corporation’s natural gas contracts are largely fixed. But the portion of its portfolio sold on the spot market.

Transportation expenses associated with fixed price contracts are generally passed through to Canacol’s customers with the exception of the Corporation spot sales. The Corporation’s transportation expenses associated with the spot sales are compensated by higher growth gas sales prices, resulting in a higher realized price net of transportation that once again are consistent with the Corporation’s fixed price contracts.

As such, despite an increase in Q3 transportation cost, the third quarter net sales price is still $4.74 per Mcf, in line with our annual guidance of $4.75 per Mcf net of transportation. Natural gas operating netbacks of $3.92 per Mcf for the 9 months to date were positively impacted by both higher-than-anticipated prices and historically low OpEx, which Ravi will touch on later.

General and administrative expenses per boe decrease 29% during the 3 months ended September 30, 2019 compared to the same periods in 2018. The result, this decrease is the result of our focus on cost efficiencies and the increase in natural gas production during the period.

G&A per boe is expected to continue to decrease as the Corporation’s production base grows for the remainder 2019 and into 2020 with the new 100 million cubic feet a day pipeline now completed. Funds from operations increased 41% to $36.4 million for the 3 months ended September 30 compared to $25.8 million for the same period in 2018.

Funds from operations increased 22% to $91.9 million for 9 months ended September 30 compared to $75.6 million for the same period in 2018. As of September 30, 2019, the Corporation had $4.6 million in restricted cash, $33.4 million cash and equivalents, and a working capital surplus of $49.1 million.

Canacol remains well capitalized, while also generating cash flow in excess of its planned 2019 capital budgets. Also of note, in August of 2019, we entered into a USD to Colombian peso foreign currency hedge in the form of a costless collar.

The amount of the peso hedges for US$30 million being US$2.5 million over 12 months, with the collar being at 3,383 to 3,535. The peso is now today sits at 3,345, which puts us in the money on that contract despite a small unrealized loss being posted in Q3 on that particular contract.

That’s it for today. Thanks very much.

I’ll hand it now over to Ravi Sharma, our COO.

Thanks, Jason. In late July 2019, we announced that the works associated with the expansion of the gas pipeline between our operated Jobo gas plant at Cartagena was completed.

These works included in the 85 kilometer of 20-inch pipeline and the installation of compression at the Philadelphia station. Both resulted in an increase of 100 million standard cubic feet per day of transportation capacity for the corporation to its clients in Cartagena and Barranquilla.

In mid-July, we announced the successful results of the Ocarina-1 well, which encountered significant gas play in the Cienaga de Oro sandstone reservoir with an average porosity of 23% and tested a 30 million standard cubic feet per day. The Acordeon-1 discovery earlier in June and the Ocarina-1 wells were tied into the 8-inch Pandereta flowline and now flow to the Jobo gas processing facility.

In late August 2019, we announced record gas sales of 217 million standard cubic feet per day, with the expansion was brought fully online. In late September 2019, we announced the successful results of Clarinete-4 encountered a record 297 feet true vertical depth of net gas play in the Cienaga de Oro sandstone reservoir with an average porosity of 22%.

This well tested 40 million standard cubic feet per day and has been tied into the new debottleneck manifold and [Yiddish] [ph] flowline between the Clarinete field and the Jobo gas processing facility. For the third quarter 2019, total natural gas operating expenses per Mcf decreased by 40% to $0.24 per Mcf for the 3 months ending September 30, 2019 compared to $0.40 per Mcf for the same periods in 2018.

The decrease is mainly attributable to the increased natural gas sales volumes, because of the completion of Jobo 3 in the pipeline expansion. And the majority of the Corporation’s operating expenses are fixed.

The Corporation’s purchase and operation of the Jobo 2 natural gas facility and the commissioning of the Jobo water treatment and disposal plant also resulted in lower operating expenses due to operating efficiencies. On a historical basis, Canacol has achieved 85% commercial success rate in its gas exploration and appraisal drilling programs, which is remarkable for an onshore conventional gas play.

Our commercial success rate on gas development drilling is 100%. These statistics bode well for the future drilling of the over 140 exploration prospects in a lease we have identified on our 1.1 million net acreage exploration position in the Lower Magdalena Basin of Colombia.

Net capital expenditures for the 3 and 9 months ended September 30, 2019 were $30.8 million and $79 million. These numbers are net of the $14 million disposition proceeds related to sales of Canacol’s interest in the Sabanas pipeline in the second quarter.

Full year gross CapEx is still anticipated to be approximately $119 million as per our 2019 guidance related late last year. Net capital expenditures during the 3 months ended September 30, 2019 are primarily related to facilities cost of VIM-5 in Esperanza blocks, seismic cost of the VIM-5 block, drilling of the Clarinete-4 and Pandereta-5 wells.

Post drilling costs for Nelson-7, Ocarina-1 and Acordeon-1 and Jobo 3 completion costs. I would like – I would now like to turn the call over to Mr.

Charle Gamba, CEO of Canacol to close with the strategy and outlook for the remainder of 2019. Thanks.

Thanks, Ravi. For the remainder of 2019, the Corporation’s focused on executing this exploration drilling program as well as executing the necessary agreements related to the construction of a new gas pipeline to Medellin, which will transport 100 million standard cubic feet per day of new gas sales in 2023.

The 2019 drilling program has been successful today with 2 discoveries Acordeon-1 and Ocarina-1, and 3 successful development wells Palmer-2, Nelson-7 and Clarinete-4. The success of the Acordeon-1 and the Ocarina-1 lifts Canacol’s commercial success to 85% in industry leading metric for conventional onshore gas play.

The remainder of the drilling program for 2019 includes the Arandala-1 well, which the Corporation has recently cased and completed. With respect to the Medellin pipeline project, the Corporation anticipates executing a take-or-pay sales contract with a major Colombian utility during the current month of November 2019, whereby half of the capacity of the new pipeline will be contracted for a period of 12 years.

The next step, to be completed by the end of Q1 2020, will be the formation of the consortium which will build and operate the pipeline, including the selection of an EPC Contractor. Finally, commenced in the fourth quarter of 2019, the Corporation is pleased to announce a regular recurring quarterly dividend.

The Board of Directors has approved a US$7 quarterly dividend to be paid on December 31, 2019 with a record date anticipated to be December 16, 2019 subject to regulatory approvals. This now represents approximately CAD5.02 per share or a yield of approximately 4.4% annually at current share prices.

This concludes my remarks concerning the outlook.

Hello, everyone, Charle, Jason. Thanks for the presentation First, I have two questions here.

The first one relates to Medellin pipeline project. You have already mentioned in the call that you are expecting to complete the construction of the pipeline by 2023 and you expect to have close to 100 million cubic feet per day in terms of transportation volume.

So, maybe provide more color on the economics of the product and its timeline. And the second one is regarding the company operational expense.

The company has increased almost 40% of its operational cost year-over-year. And how should we expect this operational cost going forward?

If there is still no more room to cost cutting, taking in account that the company had not fully ramped the Promigas pipeline in third Q? Thanks for the questions.

Okay, okay. We will answer those questions.

With respect to the pipeline project itself, the completion of the project is tied to the start-date of the take-or-pay contract, the gas sales contract, which we expect to sign within the next 2 weeks with the utility company in Medellin. So that sort of pins the start-date of the contract.

The majority of time between now and then will be consumed by the preparation and filing of the environmental license as well as the starting of the various communities’ purchase of right of ways and Consulta Previas that require to be done. So we anticipate that we should have the license come out no later than the end of 2021 or early 2022, which would put us into the position then to start construction mid to late 2022 and see the construction completed by mid to late 2023, and in time for the December 1, 2023 start-date.

With respect to the economics of the pipeline, we have formed a consortium at Canacol. Due to regulatory conditions in Colombia, can own no more than 24.9% of the consortium.

We have a consortium partner who is going to have the other 75.1% and the financing will be 30% equity, 70% debt structure. And we are well advanced with respect to negotiations with major banks on the debt side of the equation as well.

The consortium, of course, will benefit in the form of a transportation tariff. We are trying to target a certain IRR, which would satisfy our partners with respect to that.

So those are sort of the economic conditions. And of course, the pipeline will be used exclusively to transport our gas from Jobo to Medellin, and then onwards from Medellin to Sebastopol – portion of the gas onwards to Sebastopol to inject into the TGI line to the remainder of the interior of the country.

With respect to OpEx, I’m going to turn that over to Ravi. He’s been in charge of that effort, which has been very successful to date.

Yes, we plan to continue to reduce OpEx through additional operational efficiencies such as eliminating a lot of some rental equipment that we have and also through automation. And through that we’re expecting to reduce our operating cost further, also of course improved gas sales will help as well as the decline of the Colombian peso.

Okay, very clear. Thanks a lot.

Hi, guys. Thank you for the presentations.

I have four questions, first, about the expansion to Medellin. Can you give us more detail about the contract that you are expected to be – the contracts that are expected to be signed around November 18.

Maybe if you can tell us the price per 1,000 cubic feet, it would be great. And the second question is about the Medellin expansion as well.

I’m wondering if you may have already a plan for the orders at 50 million cubic capacity to Medellin. I understand the contract you are expected to sign is just for the half of the capacity.

And my third question is about dividends. Maybe if you can explain us what are the approval you need to get the dividend payment.

I’m wondering if it is just a shareholder meeting. Finally, my last question is if you have maybe any expectations about [rest of life] [ph] in the short-term and the long-term.

Thank you.

Okay. Thanks, Ricardo.

I’ll answer the Medellin pipeline questions and then – or I should say, Jason Bednar will answer what regulatory approvals are required for the dividend. And then, Ravi Sharma, our COO can answer the question around resource base.

With respect to the take or pay contracts, with the utility in Medellin. We will not disclose sales price, of course, in any individual contracts.

But it is well within the average of our existing sales contracts, which with respect to this, the gas we sell to the Coast. So we’re looking at wellhead pricing in the range of around US$4.80 to US$5, escalated at PIV over the 12-year period.

So the pricing, I can’t give you the exact pricing. But I can tell you that it is well within the range of our current contracts, which average between $4.80 to $5 per MMBtu.

With respect to the remaining volume of the pipe, the pipe is being designed to transport a minimum of 100 million cubic feet per day, of which half of it approximately would go to the utility company in Medellin. We are in advanced negotiations with other gas consuming clients in Medellin and gas distributors in and around Medellin, as well as other consumers and distributors further into the interior in Cali and in Bogota to take up the remainder of that 50 million or so.

So we see the appetite being very good. 2023 of course is when Cusiana, Cupiagua gas from the interior starts to decline or is projected start to decline.

Hence the importance of this project, which will allow us to connect our gas fields into the interior market of Colombia, so that in 2023, when Cusiana, Cupiagua will start to decline, there will be another source of gas to meet demand. I’ll turn the question regarding the regulatory approvals required for the dividends over to Jason Bednar.

Okay. Thanks, Charle.

Hi, Ricardo. So the approvals are just normal course filings with the exchanges, no need for a shareholder meeting or anything like that.

So after we get those are anticipate issuing a slightly more detailed press release, just confirming the record date and things like that. But we don’t expect an onerous process to get that approved.

Yeah. Okay.

So in regards to the reserve life index, our current reserve life index something for 15 million cubic feet a day in our current reserves that we expect for year in 2019 is 8 years. I’d like to add that we’ve had over 200% reserve replacement ratio over the last 5 years and we have the resources of 2.6 Tcf with historical success rate of 85%.

Perfect. Thank you.

Good morning, guys. I had a quick question just on production for the quarter kind of mark to market for what you guys reported in July through August, it looks like September production came in quite a bit below the 2 kind of 10 to 15 million cubic feet a day.

And just wondering, if there’s anything in that number but kind of an indication that there might be a limiting factor on delivering full 215 million cubic feet a day into Q4. I’m just wondering, if that is the case and what is that condition maybe a little bit of color around that.

Second question is just on the CapEx side that you have for next year in the October presentation you disclosed about $120 million. So it looks like after dividends are free cash flow would be about $50 million.

How are you prioritizing that in terms of exploration acceleration buybacks, and say, debt reduction? And then my last question is just once you’ve reached and as you’ve reached the full 215 million cubic feet a day.

What percentage or what amount of that is still being sold that spot pricing?

Jason, [indiscernible] question, please.

Sure. Okay.

So with respect to September production, as you can imagine when a pipeline comes on, there’s always some small hiccups you need to go to hit the full stride immediately, right. So indeed that’s what happens, we don’t anticipate that moving forward.

With respect to free cash flow, you talked about $50 million even after our dividend was normal course issuer bid, et cetera, so I’ll just deal with these one at a time. Our normal course issuer bid is set to expire on November 19.

We will be renewing that we had a board meeting yesterday approving the renewal of that. And of course, as we move forward into our 2020 budgets will be considering things like how aggressive to be on the normal course issuer bid, how much more money to throw at exploration.

We’re on deep into our 2020 budgets, there are some additional wells that we’re looking at adding, so – those will be announced. We announced our 2019 guidance in December of 2018.

My expectation this year is sort of probably be in a similar timeframe which would be the middle-ish of December this year for 2020 guidance. Just a touch on the normal course issuer bid briefly, we did not do any in this particular quarter.

To date, we bought about US$2.4 million worth of stock, if I take us back to when we initiated that in November of 2018. Our share price at that point time was $3.70 which obviously, we thought was too low.

So we began buying shares at that stage, and of the 800,000 shares we bought, our average price was $4.06. So we’ve been a very good performer in the last 12 months, our stock prices increased by 35%.

And as such heading into a budget time and dividend decisions, and that balancing act of what more do grow at dividends versus exploration versus normal course issuer bid. We just felt prudent to lay off on this particular quarter.

With respect to debt production, as you know we have a $320 million bond that we issued in May of 2018, and other significant debt if you would be a $30 million term loan. To refresh everyone’s memory, we took out that term loan to simply buy out a different loan, which was the lease of Jobo 2 gas plant, right.

So it wasn’t new data at the time was just different that. That would allow us to operate to – own and operate the Jobo 2 gas plant.

And you’ve seen the efficiencies that in our operating cost. So 2018, our OpEx was $0.40 or $0.42 in Mcf for the first 2 quarters of 2019.

It was roughly $0.30 and you see their widens in that position in this quarter it was $0.24, but to deal with that $30 million specifically. It begins turning out basically $10 million a year at 2020 and 2021 and 2022.

Actually the amount to do in 2020, because we enter that loan part way through the year is $8.2 million. So we’re currently scheduled to pay out $8.2 million of that particular debt in the year 2020.

Hope that answers everything.

The last question just on the spot market, what percentage of the 215 million cubic feet a day is subject to spot pricing?

Yeah. So typically we run it 10% to 15%.

I don’t have the exact numbers in front of me, but it’s not going to shock me if we run closer to 15% or 20% this year, as we view the economics of supply and demand in our favor as all the other major gas fields continue their decline. And we feel are one of it’s not the only active explore of gas in the country.

So we may loosen up on that amount dedicated to spot sales this year.

Perfect. Very clear.

Thanks for the detail. Thanks.

Thanks very much, guys. But given Gavin’s questions and Jason your detailed answers I really got everything answered that I was going to ask.

So appreciate that.

All right. Thanks, Ian.

Hi, guys. Thank you very much for the presentation.

Just got a couple of questions. So the first one is, could you please expand on the cost efficiencies that we reach in this quarter that led to [29%] [ph] reduction on gen expenses.

Second one would be, could you also tell us a little bit more that your plant expanding to the energy generation business. That was mentioned on the previous conference call with [thermal plans] [ph] look at non-gas production areas place?

And also my last question would be how different is your kind EBITDAX from your EBITDA? Thank you.

Okay. So with respect to EBITDAX, EBITDA, you say, it’s the same number, there was no extraordinary things were moved from this quarter and/or in the last previous quarter.

So it’s the same number. With respect to G&A, we’ve been very cost conscious for the last several years that’s – G&A a result with staff and other related administrative items.

So I feel we’ve done a very good job even though our production let’s just take it back through 4 years was 20 million cubic feet of gas a day and now it’s over 200 million cubic feet of gas a day. We’ve actually been able to lower that amount, right.

So I think we’ve done a good job on that and you’ll see our 2020 numbers will be in line or conceivably less than this year, right. So to reiterate we’re not expecting any additional G&A growth as the company’s production growth grows.

I’ll leave it to the other 2 answer your remaining operational questions.

With respect to the electrical power generation as we disclosed recently, we were part of a consortium that was awarded a project to generate electricity, backup electricity under the Ronda, [indiscernible]. So we formed a consortium with Celsia and Proelectrica.

We submitted a bid in one project that will provide 200 megawatts of backup generation schedule for 2023 on stream. So we’re going to be building that 200 megawatt plant in the vicinity of our gas fields the idea being that obviously from Canacol’s part and our economic interest is the sale of that gas.

That will power that that power plants, obviously, we don’t need to put into a pipeline. So we can have additional gas that we would normally not be able to sell, because of pipeline constraints going to a power project like this.

So those are the details concerning that particular plant, which is called the El Tesorito project. The consortium is working together essentially to license the plant and have that plant ready to generate by the end of 2021 well ahead of the December 1, 2023 start date for backup generation.

All right. Thank you very much.

Hi, good morning guys. I have a couple of questions here.

My first question is on the upcoming bidding round that Colombia is going to host. And I wanted to know if you could share with all your thoughts on the attractiveness of this round.

And give us some color, if Canacol is planning to be an aggressive be doing this round or not? My second question is regarding the Promigas pipeline.

So we saw in the local media that Cartagena/Barranquilla phase was temporarily suspended and I wanted to know if this is going to have any negative implications for Canacol resulting for 2019.

Okay, Daniel. Thank you for the questions.

With respect to the upcoming expiration bid round, which will occur on November 26 of this month. Several new exploration areas has been offered by the ANH within the Lower Magdalena Valley in and around our operating blocks.

So yes, we are very interested in several of those blocks, obviously, so we’ve been working, we qualified a bidder of course, and we’ve completed our technical analysis of all of the blocks in the Lower Mag, which we are interested in and we are preparing to participate and submit bid on the November 26 with the intention of winning several of those blocks that we can put into our exploration portfolio in the coming years. With respect to the Promigas pipeline expansion.

Again some more delays associated with that on the part of probably gas. But happily as that pipeline expansion really between Cartagena and Barranquilla, not particularly impactful to us.

Very disappointing to see additional delays, obviously, but not hugely impactful with respect to our forecast 2020 gas sales.

Hi, everyone. Thank you for the presentation.

Just 2 quick questions. After the 5 or 6 wells this year, what is the estimated cost per well and for this year.

And Canacol – I mean, how different can these number be for the next finding the development expenses?

So in terms of the – the typical average cost for the well, which includes the drilling and completions, typically it’s around $5.5 million. This is for the wells in the Cienaga de Oro, which is deeper.

In the Porquero, it’s typically around $4.5 million. Going forward, we expect similar cost for these wells, because these are the similar formations, similar depths.

If there is a well that’s deeper than the cost would go up or at a higher pressure, higher [port] [ph] pressure.

Okay and just one last question. What will be the sales mix in terms of percentages for 2020?

I mean, with the ramp up of the Promigas pipeline? And in terms of – how much sales will be for industrial thermal plant or retailers in terms of percentages?

Yeah, I mean the majority of our gas sales historically have been to thermal electric power generation companies in Cartagena and Barranquilla; second largest sales probably to commercial gas distributors in Cartagena to and Barranquilla; third to industrial users, which would include Cerro Matoso, Yara, Reficar. So I expect the average mix will remain relatively constant, with the majority of the sales, as always, been to thermal electric power generation.

With the issues associated, with the lack of generation from Hidroituango project, there’s a real squeeze on the electrical generation markets and a lack of generating capacity. So we expect certainly over the next 2 or 3 years to see gas-fired thermoelectric power generation take an increasingly important part in providing the electricity that was supposed to come out of the Hidroituango project, which is now scheduled to perhaps come on stream as late as 2023.

So to just sort of cut a long story short, we expect that most of our gas sales will continue to be directed towards gas-fired thermoelectric power generation.

Okay. Thank you very much.

Yeah, with respect to the new contract, yes, that is encompassed within our existing reserve base. And with respect to our exploration plans, we continue to – we expect to continue exploring our existing land base, we’ve identified over 2.6 TCF of prospective resource in over 140 locations to drill over the next 10 years.

So we expect to continue exploring at a fairly moderate pace as we have been in the past, 8 to 10 wells per year. And as we have been in the past as well, successfully replacing produced reserves in general over 200% reserve replacement per year.

So we expect to maintain the pace of exploration as we drill our way through our prospective inventory of 2.6 TCF of gas in our portfolio.

Yeah, certainly, certainly. Well, there is a lot of operational synergies that can be achieved.

And a lot of this is through remote monitoring, consolidation of our control systems, automation. This results in reducing personnel.

And also reduction in transportation cost. So that’s what we would do to really – to start reducing additional operational costs.

There’s also with the plants themselves, the way we operate these plants we can cut the costs by operating certain plants at certain times. So there’s a lot of – it’s a lot of small details, which I won’t get into.

But, yes, we will certainly achieve additional reductions. And I think probably another $0.03, $0.04 per Mcf.

Yeah, I mean, perhaps I can answer this, right. So we implemented a US$7 million dividend for the quarter.

Obviously, heading into 2020 we’ll give more guidance on that. But you know we have – our bond indenture limits us, as every bond indenture does, to the amount of dividends that can be issued, right.

So we’re relatively comfortable in this particular age and it’s certainly possible that we’ll see you know an increase on that. I don’t want to comment too much on that.

But we are not able to give out all our free cash flow, let’s say, $60 million, $70 million, $80 million in the form of a dividend, given our current bond indenture But given a rate of 4.5% now and the potential to increase it further, it’s not going to be double or triple i.e., using all of our free cash flow, because that’s simply not allowed under the terms of our covenant. So we’ll be examining, as I touched on earlier, what portion goes to dividends, what portion may go to a normal course issuer bid, what portion may go to increased exploration, which portions go to debt reduction like I spoke to earlier.

So it’s a general answer, if you will.

Thank you. Thanks for participating in Canacol’s third quarter conference call today.

Please join us again in March 2020 for our fourth quarter and fiscal year end 2019 conference call. Have a great day.