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, we 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. Our 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, Bernard Infante, head of corporate finance, Marcela Munoz, head of investor relations, and I are very pleased to be once again with you and present the ECL results for the first quarter of this year. Let's start and please go to page number six. This will highlight a difference with the previous presentations. We are now showing two more regions in the map of Northern Chile to include two solar PV plants acquired last April, the Los Loros and Andacollo solar plants, a combined peak capacity of 55 MW. This acquisition is relevant because it is one of the first concrete steps into our asset rotation investment plan. We have gone over the following slides, number seven 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 allowed ECL to become an active player in the central system. Second, the importance of the interconnection for the Chilean system and its role to increase the overall efficiency of the system. Third, the new investments associated with the new regulated PPA. 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 it was within or even below budget. Please turn to page eight to talk about the future and our decarbonization strategy. As you know, at ECL, 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 ambitions. However, it must be gradual and responsible.
The early steps into this path, including developing the same projects and deciding not to build any new coal plants besides IEM, which was conceptually committed since 2014 as part of the regulated PPA that was awarded at that time to ECL. In April 2018, we were a first mover by announcing the renegotiation of around three terawatt-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 two coal units in Tocopilla, totaling almost 170 MW, which should materialize very soon once Interchile transmission line is fully operational.
More important, this agreement triggers our plan to develop and build almost one gigawatt of renewable capacity in the coming years, representing an investment close to $1 billion. The acquisition of Los Loros and Andacollo solar plants, which required a $35 million cash payment, was the first piece of this plan. 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 four 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. As I will explain later, we have strong reasons to maintain our guidance for the full year.
Second, as discussed, we have renegotiated about three terawatt-hour of contracted PPA with some of our main clients, implementing a win-win scheme that will create value for both. This renegotiation triggers our plan to convert part of our thermal portfolio to renewables, 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 auction. Our development teams are now focused on the first three renewable projects of what we call the asset rotation plan and are today in the process of obtaining the necessary approvals to start construction during the second half of this year.
Fourth, we continue to keep a sound 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 mention 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 demands, 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 decrease in power demand and certainly affected our physical sales and free clients. If we had record rains in the north, we had droughts 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 you see, I've got significant volume of energy from the spot market. These higher spot prices affected the cost side. In terms of company events that we can mention, first, 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 power, including renegotiation with mining companies such as Antofagasta, Molycop, and Quiborax. Third, 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 power to the grid in testing. Fourth, we got environmental approval for our 120-megawatt Tamaya solar project, which is 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. Finally, on May 24, we will pay final dividend of $22 million, which in addition to the $26 million provisional dividend paid last October, reach $48 million, that is 30% of our total net income in 2018. On slide number 12, you can see the positive effects of our PPA with the distribution companies in the central south region. Physical sales under this contract were 0.8 terawatts power 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 MW, 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. 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 spot loss limit mechanism for the overall system, given the higher intermittency when operating more and more with renewables. We already mentioned that we expect IEM to soon begin commercial operations, and we have signed PPAs with other generation companies as a financial hedge for 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 15. 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 increase in contracted demand under the regulated PPA, which offset the negative effects of the decrease in demand from free clients and higher energy supply costs that we will discuss later. Let's move to page 14 to see our supply and demand balance. Our total sales reached about 2.7 terawatts power, supplied from two main sources: Our own production and energy purchases in the spot market. In summary, 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 to the supply agreement, which help us reduce price volatility in the spot market. Our coal generation 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 Unit 16's 28-day programmed maintenance, as these plants are better suited to cope with the intermittency caused by renewables. 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 other energy purchases and/or reduce the operation of our more expensive coal power 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 GLX prices as well as average fuel and electricity purchase cost per MWh 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 pass-through to contract parties. We should expect decreases in prices and costs in the next quarter as a result of fuel price behavior. Second, marginal costs or spot prices were higher this quarter as a result of the drought in the Central Valley of Chile. Third, our coal plants recorded an unusual number of cold 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. 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 costs in the next quarter 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, on increasing this duration by signing new contracts or discussing options with our existing clients. Now the next page, number 16. During our last call, I said we would be ready to move this slide to the annexes section unless we had new developments to report. Well, we had some. We signed a 50 MW PPA renegotiation with Antucoya from the Antofagasta Minerals Group, and we also renegotiated PPAs with other free clients, including Molycop, Quiborax, Mallplaza, Puerto Mejillones , and Puerto Angamos.
The conceptual agreement of this renegotiation is the same applied to previous PPAs, meaning an initial discount in the short term, a further discount afterwards, together with a change in the indexation formula, moving to 100% inflation. Finally, an extension of the PPA at the latest market conditions. On page 17, we show our main strength and our vision through 2030. The green area, which represents renegotiated and new PPAs with free clients, has continued widening as our commercial B2B team is delivering tangible results. Regarding the blue area that represents 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.
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. 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 Antucoya solar plants, which will contribute 55 MW 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 MW Calama wind farm and two solar PV projects with a combined capacity of over 200 MW 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 deciding the section and type of technology are best linked to market conditions. This will allow us to gradually replace our aging coal plants. On page 19, we show three new transmission projects awarded back in 2018, which are under construction. They will require around two 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 areas in which we can create synergies. Second, they are linked to our renewable portfolio, and finally, they will contribute with regulated revenues.
On page 20, you can see our IEM project, which injected 206 GW to the grid during the first quarter. We have filed our request with the coordinator to declare the plant's commercial operation, which we expect to happen soon this month. In fact, we filed this request last Friday, we expect to be ready in the coming weeks. The project was within budget, and once in commercial operation, it will allow us to reduce our generation to the oldest coal plant. This will also help us to replace part of our stock purchases and to lower our average energy supply costs to supply our contracted demand. On page 21, we highlight the operation of Mejillones 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 big-sized carriers. 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 full capacity will not be used for coal unloading. Therefore, we are currently working with the different alternatives to optimize this asset. Please turn to page 22, where we show that our CapEx financing needs have considerably decreased, releasing, of course, on-balance sheet financing capacity for our asset rotation plan. We'll 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 last year. You multiply the first quarter EBITDA by 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 trench of the Chile project, the imminent commercial operation of IEM, and also lower coal prices and better hydro conditions should contribute to lower spot energy prices. We can expect better conditions for the mining industry given the absence of the El Niño Pacific winter, which, as I mentioned before, impacted our results during the first quarter. Now, let's move to the next section.
I will let Bernardita 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 and an impairment of performance and higher spot prices. Please note that these three negative items can be largely attributed to temporary factors. Now, let's give 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 gigawatt hours 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 increase. A greater weight of the higher price regulated contracts. 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 temperatures around water discharge structures. Our coal generation dropped to one half 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 costs should have decreased even more, had it not been for the number of plant startups to cope with the system's intermittency, which resulted 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, a decrease in physical sales on free clients, mainly as a result of the stop of the mining operations that Eduardo already mentioned. Regulated clients in the north also reported a decrease in 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 fueling caused an increase in spot energy prices. The average realized price at which we sourced energy on the spot market was $59 per MWh versus $46 in the first quarter of last year. These higher spot prices explained a $15 million impact on EBITDA. Third, given the significant tariffs increase, which was accompanied by a decrease in our own generation, we reported higher physical energy purchases, which represented a $40 million cost increase.
The contracted sales increase also requires higher capacity purchases. The increase in the sufficiency capacity provisions had a $10 million impact on EBITDA. Please turn to slide 26. There's 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 or in currency differences and depreciation, and only one non-recurring item, an insurance recovery, which had an after-tax effect of $1 million. First quarter net income reached $43 million, up from $39 million the year before. On slide 27, we can appreciate a $63 million net debt reduction. In terms of uses of cash, CapEx amounted to only $16 million as we approach completion of the IEM project.
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 cross-of guarantee in favor of TEN's creditors to free up the cash deposited in the debt service reserve account. With the cross-of guarantee, we could release almost $15 million of cash, and the remaining $7 million came from TEN's excess cash from its operation, 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 two times as of the end of March.
To support our liquidity in times of heavy CapEx, back in 2015, we contracted a committed revolving credit facility with 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 BB stable, while both Fitch and Feller Rate upgraded ECL's national scale rating to AA-. On slide 29, you can see that in 2018, we paid $56 million in dividends, and that in the last four years, our dividends have been limited to 30% of net income to support our CapEx expansion. Last October, we paid a provisional dividend of $36 million on account of 2018 net earnings.
Our shareholders approved a final dividend distribution of $22 million on May 24th. These two payments together account for 30% of recurring net income. As you may recall, in 2018, we reported $58 million in non-recurring losses, primarily explained by the impairment of two coal-fired plants. Our share 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 three main messages. First, we are very close as a system to reach the full interconnection of the former SING and SIC systems. At the same time, AIM project is ready, only waiting the final green light from the market coordinator. Both events will bring higher efficiency, stability to the overall system. Solar PV plants totaling 55 megawatts, and the plan is to continue with the development and construction of the first three renewal projects during the second half of this year. Third, we can confirm our guidance on operational results for 2019, and therefore, we can confirm a stronger cash generation phase that is targeted for the company, which will allow further flexibility to implement our transformation and development plan.
With this final message, we are concluding our first quarter presentation. Thank you always for your participation, patience, and basically, we are ready for any questions you may have.
Thank you. The floor is now open for questions. If you have a question, please press star and one on your touchtone phones at this or any time. If at any point your question has been answered, you may remove yourself from the queue by pressing star and two. Questions will be taken in the order in which they're received. We do ask that when you pull your question, you pick up your handset to provide optimum sound quality. With that, we poll for questions. Our first question today comes from Ezequiel Fernández from Credicorp Capital. Please go ahead with your question.
Hi. Good day to everybody. Thank you for taking the time to prepare the materials. I have four 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. Sorry, by the way, if you commented on any topics I joined related 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 would represent a slight improvement in our results because, as you know, in our guidance, we consider the final COD of this line on early July and not on June.
Okay, perfect. Thank you. My second question relates to the gas production during the first quarter, how much of that was Argentina and how much Engie? If you have any Argentine gas, is it fair to say that the cost of the plant gate is around just $5.5 per MBtu or so?
Basically, what we started importing from Argentina this year, it's 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. In general, most of the production comes from our existing contracts. In the future, this potential import from Argentina will, of course, could play an important role in the production of the gas. In this quarter, the amount of gas was marginal.
Okay, great. I have two questions, actually. My last one is, page five 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 $ per MWh curve goes to zero, even if you have coal and gas being dispatched. Is that related to out-of-merit thermal output or what is it behind it? Maybe you have to call, but perhaps you have a quick answer for that.
Sorry, because you lost me a little bit, your question.
Yeah.
The marginal cost goes to zero at some hours, even though at that same point in time, you do have coal and gas output.
Yes.
Well, that is basically because of the inflexibility of gas declaration. What I mean is the following.
In certain times, like Kelar or even ourselves, have gas supply, and the only way of assuring that we use that gas, because we have that gas and otherwise we would have to, I don't know, leave it out there for the atmosphere.
Emission costs.
Exactly. We declare that at zero cost. Okay?
Okay.
At that time Yeah. At that time, the coal plants that are operating there, in those hours, are all of them dispatching at their technical minimum, which means.
Yes
they don't market marginal cost. The marginal cost can go down to zero, even though we have coal plants and gas plants in the system. Now they are remunerated at the over-cost mechanisms. They receive their remuneration, but not at marginal cost.
That's a very clear explanation. Thank you very much. End of call from my side.
Once again, if you would like to ask a question, please press star and then one. To withdraw your question, you may press star and two. Ladies and gentlemen, at this time and showing no additional questions, I would like to turn the floor back over to Engie Energia Chile for their closing remarks.
Well, thank you very much for your participation, and see you during the next quarter.
Thank you.
Thanks all.
This concludes today's presentation. You may disconnect your lines at this time, and have a nice day.