ENGIE Energia Chile SA
SGO:ECL
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Good afternoon, everyone, and welcome to Engie Energia Chile's First Quarter 2019 Results Conference Call.
If you need a copy of the press release issued last week, it is available on the company's website at www.engie-energia.cl.
Before we begin, I would like to remind you that this call is being recorded and that information discussed today may include forward-looking statements regarding the company's financial and operating performance. All projections are subject to risks and uncertainties, and actual results may differ materially. Please refer to the detailed note in the company's press release regarding forward-looking statements.
We would like to advise participants that this call is dedicated to investors and market analysts, not for the press. We ask all journalists to contact Engie Energia Chile's PR Department for details.
I will now turn the conference call over to Mr. Eduardo Milligan. Please go ahead, sir.
Thank you, operator. Good afternoon, and thank you for attending this call.
Today, Bernardita Infante, Head of Corporate Finance; Marcela Munoz, Head of Investor Relations; and I are very pleased to be once again with you and present our this year's results for the first quarter of this year.
So let's start and please go to Page #6 just to highlight a difference with the previous presentations. We are now showing 2 more regions in the map of Northern Chile to include 2 solar PV plants acquired last April, the Los Loros and Andacollo solar plants, with combined peak capacity of 55 megawatts. This acquisition is relevant because it is in one of the first concrete steps into our asset rotation investment plan.
We have gone over the following slides, #7 in previous calls, but I think it's worth reminding the main drivers of our company's growth: first, the regulated PPA that started back in January 2018, which allows ECL to become an active player in the central system; second, the importance of interconnection for the Chilean system and its role to increase the overall efficiency of the system; and third, the new investment associated with new regulated PPAs. This included the IEM project, which has experienced some delays during the final commissioning phase, but it's already injecting power to the system and was within or even below budget.
Now please turn to Page 8 to talk about the future and our decarbonization strategy. As you know, this year, we're aligned with the market, our stakeholders and society expectations in terms of achieving a cleaner and more efficient power generation system. The energy matrix decarbonization is also one of our visions. However, it must be gradual and responsible. The early steps into this path included developing the TEN project and deciding not to build any new coal plants besides IEM, which was contractually committed since 2014 as part of the regulated PPA that was awarded at that time to ECL.
Then in April 2018, we were a first mover by announcing the renegotiation of around 3 kilowatts hour of PPAs. And as we will comment later on, we have advanced further in the PPA renegotiation process during this year. The renegotiation includes abandoning the tariff indexation to coal prices beginning 2021 and extending the life of these contracts. These renegotiations allowed us to request authorization to close 2 coal units in Tocopilla, totaling almost 170 megawatts that should materialize very soon once Interchile transmission line is fully operational. But more important, these agreements triggers our plan to develop and build almost 1 gigawatt of renewable capacity in the coming years, representing an investment close to $1 million. The acquisition of Los Loros and Andacollo solar plants, which required a $35 million cash payment was the first piece of this plant. We also signed a long-term power supply agreement to reduce our exposure to price volatility during the transition.
Now let's turn to Page 10 to review our 4 key messages, which have not really changed from the last presentation. First, our first quarter results may seem to be behind our guidance for the year. However, although we had some unexpected events in the first quarter, our results were pretty much in line with our budget. And as I will explain later, we have strong reasons to maintain our guidance for the full year.
Second, as discussed, we have renegotiated about 3 terrawatts hour of contracted PPA with some of our main clients, implementing a win-win scheme that will create value for both. These renegotiations triggered our plan to convert part of our thermal portfolio to renewals, and this is something we will discuss also later.
Third, our development and construction teams continue to be very busy. They have been involved in the commissioning of the IEM project as well as in the construction of transmission systems awarded in the 2018 auctions. Our development teams are now focused on the first 3 renewal projects of what we call the asset rotation plan. And they are today in the process of obtaining the necessary approvals to start construction during the second half of this year.
And fourth, we continue to keep a firm and flexible capital structure with a strong cash generation that will allow ECL to benefit from attractive conditions to refinance our existing debt and to finance our transformation plan.
Now let's skip to Page 11 to go over some industry and company developments during the quarter. Some of the events that we can measure include climatic factors. During our summer, we had record rains and floods in the North as a result of the Altiplanic Winter phenomenon, which affected several mining operations mainly from our clients in the North. Mines had to shut down for a few days, causing a reduction in their electricity demand. And at the same time, smelters, including Chuquicamata, also closed temporarily due to environmental improvement works as these smelters had to comply with new emission norms. This also explained the decreasing power demand and certainly affected our physical sales to 3 clients.
If we had to record rains in the North, we had drought in the South, meaning that average spot energy prices during the first quarter were higher than those of the first quarter of last year. As ECL bought significant volumes of energy from the spot market, these higher spot prices affected the costs side.
In terms of company events, what we can mention, first, the already acquisition of -- we already mentioned acquisition of the Los Loros and Andacollo solar plants in April. Second, the PPA renegotiations and new contracts signed for over 500 gigawatts hour, including renegotiations with mining company, such as Antucoya, Molycop and Quiborax.
Third, the IEM completed its tests. We already requested the commercial operation to the market coordinator and hope to declare the plant in commercial operation during this month. During the first quarter, IEM injected slightly above 200 gigawatts hour to the grid in test mode.
Fourth, we got environmental approval for our 120 megawatt Tamaya Solar project. We achieved a key milestone to put the project in a ready-to-build phase.
Fifth, we reported an 84% increase in demand under our PPA with the distribution companies in Central South Chile.
And finally, on May 24, we will pay final dividends of $22 million, which, in addition to the $26 million provisional dividend paid last October, reached $48 million. That is 30% of our total net income in 2018.
On Slide #12, we can see the positive effects of our PPA with the distribution companies in the Central South regions. Physical sales under these contracts were 0.8 terawatts hour in the first quarter, which, as I mentioned before, represents 84% increase compared to the same quarter of last year. This contract alone accounted for almost 30% of our physical sales. Our total energy sales did not grow as much because of lower demand from mining companies due to the effects of the Altiplanic Winter and environmental improvement works at mining facilities. The interconnection of both grids continue transporting up to 900 megawatts primarily in the South-North direction allowing, in general, solar power producers in the nearest region to Santiago City to export their production to the North.
Now ISA's Interchile project, which will allow power flows to reach the areas of greater demand, is still under construction. And once the final tranche starts operation, the interconnection will, of course, be enhanced.
On the supply side, we signed new gas supply agreements to run our combined cycle plants that have become an important stop-loss limit mechanism for the overall system given the higher intermittency when operating more and more with the renewals. Then we already mentioned that we expect IEM to soon began commercial operations. And we have signed PPAs with other generation companies as a financial hedge to our margin given also the delay in the full interconnection of the system.
To complete the review of our financial performance in the first quarter, I am now on Slide 13. Our EBITDA reached $96 million, a 5% year-on-year growth. And our recurring net income reached $42 million. Our EBITDA was positively affected by the increasing contracted demand under the regulated PPA, which affects the negative effects of the decreasing demand from free clients and higher energy supply costs, as we will discuss later.
Now let's move to Page 14 to see our supply and demand balance. Our total sales reached about 2.7 terawatts hour supplied from 2 main sources, our own production and energy purchases in the spot market.
In summary, and considering IEM partial injection in the spot, we supplied a bit more than half of our demand with the spot energy purchases, while 5% of our contracted demand was hedged through the supply agreements, which helped us reduce price volatility in the spot market. Our cogeneration fell because our coal plants were either out of service for maintenance or were requested to limit their output for dispatch for other technical reasons. Our gas plants increased their production, despite a unit 16 28 days program maintenance, as these plants are better suited to cost with the intermittency cost by renewals. Even though IEM injected power to the system, and we show in this graph its production for information purposes, since the plant is not yet in full operation, the revenues did not contribute to our results, but rather impacted the investment in fixed assets. Once in full operation, IEM will help us reduce our spot energy purchases and/or reduce the operation of our more expensive coal-fired plants, like units 12, 13 and units 14 and 15.
In this regard, units 12 and 13 are planned to be decommissioned soon, only produced 0.3% of our energy sales, while diesel generation was even lower.
You will note that both average realized prices as well as average fuel and electricity purchase cost per megawatt hour increased. The main reasons behind these increases are: first, high coal prices and LNG prices, particularly in the last quarter of 2018. Even though coal prices decreased in the first quarter, we burned [ stocks ] purchased at higher prices. And there is some lag in the passthrough to contract targets. But we should expect decreases in prices and costs in the next quarter as a result of fuel price behavior.
Second, marginal cost or spot prices were higher this quarter as a result of the draught in the South Central Chile.
Third, our coal plants reported an unusual number of startups compared to last quarter as they had to cope with the intermittency of renewables, and they had planned and forced outages. Startups require diesel, thereby increasing the cost of fuel.
And fourth, we increased our capacity purchase provision in line with the expected increased demand from distribution companies.
In sum, we should see a return to lower average cost in the next quarters due to declining fuel prices and once IEM and the last tranche of the interconnection begin commercial operations.
Now let's move to Page 15. We can observe the duration of our portfolio, which has a 12-year average remaining life. We are working, as you know, in increasing the duration by signing new contracts or discussing options with our existing clients.
I am now in the next page, #16. During our last call, I said we would be ready to move this slide to the Annex section, unless we had new developments to report. Well, we had some. We signed a 15-megawatt PPA renegotiation with Antucoya from the Antofagasta Minerals Group. And we also renegotiated PPAs with other free clients, including Molycop, Quiborax, Mall Plaza, Puerto Mejillones and Puerto Angamos. The contractual agreements of these renegotiations is the same applied to previous PPAs, I mean an initial discount in the short term, a further discount afterwards, together with the changing indexation formula moving to a 100% inflation and finally, an extension of the PPA at latest market conditions.
On Page 17, we show our main strength and our vision through to 2030. The green area, which represents renegotiated and new PPAs with free clients has a continued widening as our commercial B2B team is delivering tangible results.
Regarding the blue areas that we present our demand expectations under the regulated PPAs, it shows an increase for 2020. This is because in 2019, new supply from PPAs signed back in 2014 came into the market, so this caused a temporary reduction in the pro rata assigned to each generation company, but this imbalance in supply, vis-à-vis demand, should tend to be corrected beginning of next year.
Now let's turn to Page 18. To give some details here on our first steps into our 1 gigawatt $1 billion asset rotation plan, which comprises both acquisitions and development of greenfield projects. I already talked about our acquisition of the Los Loros and Andacollo Solar plants, which will contribute 55 megawatts of renewable capacity beginning April and represented a $35 million investment. Our development teams are currently working to present for internal approval also the 150-megawatt Calama wind farm and 2 solar PV projects with a combined capacity of over 200 megawatts to be ready to begin construction in the second half of this year. We will continue development of a 24/7 renewable portfolio by combining solar PV and wind technologies in the different regions we have identified in the country, together with our existing gas capacity. Our idea is to keep several open options in parallel and decide in construction and type of technology at best time-to-market conditions, so this will allow us to gradually replace our aging coal plants.
On Page 19, we show 3 new transmission projects awarded back in 2018, which are under construction. They will require around 2 years for construction. And the AVI will be close to $1.5 million per year. As we explained before, these projects are interesting because they are located in the areas in which we can create synergies. Second, they are linked to our renewable portfolio. And finally, they will contribute with the regulated revenues.
On Page 20, we can see our IEM project, which injected 206 gigawatts hour to the grid during the first quarter. We have filed our request with the coordinator to declare the plant commercial operation, which we expect to happen soon this month. In fact, we filed this request last Friday, so we expect to be ready in the upcoming weeks. The project was within budget. And once in commercial operation, it will allow us to reduce our generation with the oldest coal plant. This will also help us to replace part of our spot purchases and to lower our average energy supply cost to supply our contracted demand.
On Page 21, we highlight the operation of Puerto Andino port, which required a total investment of $120 million and has been operating since late 2017. As you know, this is a mechanized port with the ability to receive capesize carriers. And the advantages of this port are related to economies of scale, better environmental standards, higher unloading speeds and lower demurrage costs. As discussed in previous calls, the port's whole capacity will not be used for coal unloading, so therefore we are currently working into different alternatives to optimize this asset.
Now please turn to Page 22 where we show that our CapEx financing needs have considerably decreased releasing, of course, all balance sheet financing capacity for our asset rotation plan. We will be able to finance our investment in renewable capacity through a mix of operating cash flow and additional debt, while keeping our leverage ratios under full control.
In terms of guidance, please move to Page 23. As you know, ECL delivered solid results in 2018, reaching the high end of our 2018 guidance. For 2019, which is the second year of an important ramp-up period, we are keeping the guidance provided in last year. If you multiply the first quarter EBITDA times 4, it seems that we are behind this guidance. However, the first quarter EBITDA was only marginally below our budget as we had anticipated that the second half of 2019 would be better than the first half due to the following main factors: the completion of the Southern tranche of the Interchile project; the imminent commercial operation of IEM; and also lower coal prices and better hydro conditions should contribute to lower spot energy prices. And we can expect better conditions for the mining industry, giving the absence of the Altiplanic Winter, which, as I mentioned before, impacted our results during the first quarter.
Well, now let's move to the next section. So I will let Bernardita to give you more details on our financial results.
Thank you, Eduardo. Hello, everyone.
Please turn to Slide 25. Here we can see that our EBITDA reached $96 million in the first quarter, a 5% increase compared to the first quarter of last year. A short summary is provided in the slide title. Higher regulated sales offset lower free client demand, uneven plant performance and higher spot prices. So please note that these 3 negative items can be largely attributed to temporary factors.
So now let's get a closer look to the EBITDA evolution. First, the new PPA with distribution companies, which had a ramp-up beginning 2019 contributed additional physical sales of 370 gigawatts hour and $44 million in additional revenue.
Second, we reported an increase in average realized prices, which had an $8 million positive impact on EBITDA. This was due mainly to higher fuel prices used in the tariff industry and the greater weight of the high-price regulated contract.
Third, we reported a $25 million reduction in fuel costs due to the decrease in generation explained by plant maintenance and limitations owing to several dispatch and technical reasons, which, among others, included, for example, higher sea temperature around water discharge structures. Our coal generation dropped to 1/2 of what we produced in the first quarter of 2018, while gas generation increased by 3%, despite the maintenance of our unit 16 combined cycle plant. Our fuel cost should have decreased even more had it not been for the number of plant startups to cope with the system's intermittency, which results in higher consumption of diesel.
Fourth, our operating and SG&A expenses decreased by $7 million, thanks to our continued cost-saving initiatives.
Among the effects that put our EBITDA under pressure, we have: first, the decrease in physical sales to free clients mainly as a result of the stoppages of mining operations, which Eduardo already mentioned. Then regulated clients in the North also reported a decrease in the physical sales. The physical sales decrease had overall a $15 million negative effect on EBITDA.
Second, higher fuel prices and the drop in Central South Chile caused an increase in spot energy prices. The average realized price at which we source energy from the spot market was $59 per megawatt hour versus $46 in the first quarter of last year. These higher spot prices explained a $15 million impact on EBITDA.
Third, given the significant sales increase, which was accompanied by a decrease in our own generation, we reported higher physical energy purchases, which represented a $40 million cost increase.
Finally, the contracted sales increase also requires higher capacity purchases. So increasing the sufficiency capacity provision had a $10 million impact on EBITDA.
Now please turn to Slide 26. There is little to add here, as it was the EBITDA increase, the item that explained the $4 million increase in net income. There were very small variations in interest expense, foreign currency businesses and depreciation and only one nonrecurring item, an insurance recovery, which had an after-tax effect of $1 million.
First quarter net income then reached $43 million, up from $39 million a year before.
Now on Slide 27, we can appreciate a $63 million net debt reduction. In terms of uses of cash, capital expenditures amounted to only $16 million as we approach completion of the IEM project. Then we paid $4 million in dividends to our partner in CTH. And we paid $11 million in income taxes. All of these expenditures were financed with operating cash flow and also by a $22 million cash payment from TEN. As you may recall, last year, we had an extraordinary shareholders meeting to approve the extension of a corporate guarantee in favor of TEN's creditors to free up the cash deposited in the debt service reserve account. With the corporate guarantee, we could release almost $15 million of cash. And the remaining $7 million came from TEN's excess cash from its operations, which allowed it to repay debt with its shareholders.
Slide 28, which provides details of our liquidity and debt structure has little changes. The net debt to EBITDA ratio decreased to 2x as of the end of March. Now to support our liquidity in times of heavy capital expenditures, back in 2015, we constructed a committed revolving credit facility with the original maturity in June 2020. Given our strong cash generation and access to credit, we decided to request the cancellation of this facility as we were anticipating no use of this line.
In terms of credit ratings, both S&P and Fitch have confirmed ECL's international ratings at BBB stable, while both Fitch and Feller Rate graded ECL's national scale rating to AA-.
On Slide 29, we can see that in 2018, we paid $56 million in dividends and that, in the last 4 years, our dividends have been limited to third part -- to -- sorry, 30% of net income to support our CapEx expansion. Last October, we paid a provisional dividend of $26 million on account of 2018 net earnings. And our shareholders approved a final dividend distribution of $22 million on May 24. These 2 payments together account for 30% of recurring net income. As you may recall, in 2018, we reported $58 million in nonrecurring losses primarily explained by the impairment of 2 coal-fired plants.
Our stock price evolution generally followed the market, although in the last quarter -- or last month, it decoupled from the IPSA and recovered clearly above the market. Over the last 12 months, ECL share price increased by 1.7%, whereas the IPSA fell by 5.1%.
Well, this is all on my side, and I'll leave you with Eduardo to make some final remarks on this presentation.
Thank you, Bernardita. Well, to conclude this presentation, as always, I just want to close with the 3 main messages.
First, we are very close as a system to reach the full interconnection of the former SING and SIC systems. And at the same time, IEM project is ready, only waiting the final green light from the market coordinator. Both the events will bring higher efficiency, stability to the overall system and, of course, to our energy balance in the spot market.
Second, we started the asset rotation plan by acquiring 2 solar PV plants totaling 55 megawatts and the plan is to continue with the development and construction of the first 3 renewable projects during the second half of this year.
And third, we can confirm our guidance on operational results for 2019. And therefore, we can confirm a stronger cash generation phase that has started for the company, which will allow further flexibility to implement our transformation and development plan.
So with this final message, we are concluding our first quarter presentation. Thank you, as always, for your participation, patience. And basically, we are ready for any questions you may have.
[Operator Instructions] And our first question today comes from Ezequiel Fernández from CrediCorp Capital.
Thank you for taking the time to prepare the materials, and I have 4 questions. I would like to go one by one, if possible. The first one is related to the Polpaico-Cardones line, if you have any expectations about when it will go online. And sorry, by the way, if you commented on any topic. I joined a bit late to the call.
Well, the latest information that we have is that it should be ready during early June. This is the formal information that we have and the information that we received from the construction team. That's our best, let's say, estimate on when the line should be ready, which, in practice, will represent a slightly -- or would represent a slightly improvement in our results because, as you know, in our guidance, we considered the final COD of this line on early July and not on June.
Okay. Perfect. My second question relates to the gas production during the first quarter. How much of that was Argentina? And how much LNG? And if it's -- if you have any Argentine gas, is it fair to say that the cost at the flood gate is around just $5.50 per Mbtu or so?
Well, basically, what we started reporting from Argentina this year is marginal. What is important for us is that this is the first time that we imported gas from Argentina using the pipe in the North. But in general, most of the production comes from our existing contracts. In the future, this potential import from Argentina will, of course, play an important -- or could play an important role in the production with gas. But in this quarter, the amount of gas was marginal.
Okay. Great. And I have 3 questions, actually. My last one is Page 35 in your presentation where you have the marginal cost per hour. It's very interesting. I was wondering there are some points at which the dollar per megawatt curve goes to 0, even if you have coal and gas being dispatched. Is that related to out-of-merit thermal output? Or what is it behind? [indiscernible] of the coal, but perhaps, you have a quick answer for that.
And your -- sorry because we lost a little bit your question. Your question was how...
Yes, will the marginal cost goes to 0 at some hours, even though, at that same point in time, you do have coal and gas output?
Yes, yes.
Yes.
Well, [indiscernible] tariffs are basically because of the inflexibility of gas declaration. So what I mean is the following. In certain times, like Keller or ourselves, even ourselves have gas supply and the only way of assuring that we use the gas because we have that gas. And otherwise, we would have to leave it out there for the atmosphere...
Because of new shipments coming.
Exactly, so you have to -- we declare that at 0 cost, okay? So what happens at TENS -- yes. And then at that time, the coal plants that are operating there in those hours are all of them dispatching at their technical minimum, which means they don't press, they don't mark the marginal cost. So the marginal cost can go down to 0, even though we have coal plants and gas plants in the system. And now they are remunerated the over cost mechanism. So we see the remuneration, but not at margin cost.
[Operator Instructions] And ladies and gentlemen, at this time, I'm showing no additional questions. I would like to turn the floor back over to Engie Energia Chile for closing remarks.
Well, thank you very much for your participation, and see you during the next quarter.
Thank you all, and bye.
This concludes today's presentation. You may disconnect your lines at this time, and have a nice day.