Earnings Call: Q1 2019

May 7, 2019

Good afternoon, everyone, and welcome to NG Energia Tille'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. Ng 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. Our projections are subject to risks and uncertainties, and our actual results may differ materially. Please refer to the detailed note 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 the Energy at Chile's PR department for details. I will now turn the conference call over to Mr. Eduardo Milliken. Please go ahead, sir. Thank you, operator. Good afternoon and thank you for attending this call. Today, I'm going to read Enfante, Head of Corporate Finance Marcelo Munoz, Head of Investor Relations and I are very pleased to be once again with you on percentage year results from the Q1 of this year. So let's start and please go to Page number 6. This will highlight a difference with the previous presentation. We are now showing 2 more regions in the map of Northern Chile, including 2 solar PV plants acquired last April, the Los Floros and then the Pollo solar plant combined with capacity of 55,000,000. This acquisition is relevant because it is one of the first concrete steps into our asset rotation investment plan. We have done over the following Slide 7 in previous calls, but I think it's worth reminding the main drivers of our company's growth. 1st, the regulated PPA that started back in January 'eighteen, which allowed DCL to become an active player in the central system. 2nd, the importance of the interconnection for the Chilean system and its role to increase the overall efficiency of the system and third, the new investments associated with the 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 between 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 are aligned with the market, our stakeholders and society's expectations in terms of achieving a cleaner and more efficient power generation system. The energy matrix with our integration is also one of our ambitions. However, it must be gradual and responsible. The only steps into this path including developing the same project and deciding not to build any new coal plant besides I'm which was constructively committed since 2014 as part of the regulated PPA that was awarded at that time this year. Then in April 2018, we were a 1st mover by announcing the renegotiation of around 3 terawatt tower of PPA. 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 in 2021 and extending the life of these contracts. These renegotiations allowed us to close total units in Tuscania, operating almost 170 megawatts, which should materialize very soon once Inter Chile transmission line is fully operational. But more important, these agreements trigger our plan to develop and build almost 1 gigawatt of renewable capacity in the coming years, representing an investment close to $1,000,000,000 The acquisition of Los Nodos and Embacollo solar plant, which required a $35,000,000 cash payment, was the first piece of this plan. We also signed a long term power supply agreement to reduce our exposure to capital activity 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 Q1 results may seem to be behind our guidance for the year. However, although we had some unexpected events in the Q1, our results were pretty much in line with our budget. And as I will explain later, we have strong reach to maintain our guidance for the full year. 2nd, as discussed, we have renegotiated about future our tower future our power of The immunization triggers our plan to convert part of our thermal portfolio to renewals, and this is something we will discuss also later. First, 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 Ocean. Our development teams are now focused on the first three renewable projects of what we call the asset organization plan and are today in the process of obtaining the necessary approval to start construction during the second half of this year. And 4th, we continue to keep a sound and flexible capital structure with a stronger generation that will allow ICL to benefit from attractive conditions to refinance our existing debt as we 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 Azitanic 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 Chibicamata, also closed temporarily due to environmental improvement work as these smelters have to comply with new emission norms. This also explained the decrease in power demand uncertainty affected our physical sales and fleet lines. If we had to record the rains in the North, we had drops in the South, meaning that average spot energy prices during the Q1 were higher than those of the Q1 of last year. ATCO bought significant volume synergy from the spot market. These higher spot prices affected the cost side. In terms of company events, what we can mention, first, we already acquisition of we already mentioned a decision of the Los Loro san, the solar plants in April. 2nd, the DPA negotiations and new contracts signed for over $500,000,000 an hour including the negotiation with mining companies such as Antiporia, Polycom and QRS. 1st, the IEM completed its test. We already requested commercial operations to the market coordinator and hope to declare the plant in commercial operation during this month. During the Q1, IEM injected slightly above 200 gigawatts power to the grid in testing. 4th, we got environmental approval for our 120 megawatt Tamayo Celos project, which is a key milestone to put the project in a ready to build phase. 3rd, we reported a 80 4% increase in demand under our TCA with distribution companies in Central South Chile. And finally, on May 24, we will pay final billings of $22,000,000 which in addition to the 26 1,000,000 provisional dividend paid last October reached 48,000,000, that is 30% of our total net income deteriorated. On Slide 12, you can see the positive effects of our PPA with distribution companies in the Central South regions. Physical sales under this contract were 0.8 terawatts per hour in the Q1, 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 Arctic winter and environmental improvement works at Marine facilities. The interconnection of both rigs continue transporting up to 900 Megawatts, primarily in the south north direction, allowing, in general, solar power producers in the nearest region to the Gallo City to export their production to the north. Now Istas Inter Chile 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 plan that has become an important top loss lease mechanism for the overall system given the higher intermittency when operating more and more with the renewables. Then we already mentioned that we expect I'm to soon begin commercial operations. And we have signed CPA 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 Q1, I am now on Slide 15. Our EBITDA reached $96,000,000 a 5% year on year growth, and our recurring net income reached BRL42 1,000,000. Our SBA was positively affected by the increase in contracted demand under the regulated TPA, which affects the negative effects of the decreasing demand from free clients and higher energy supply costs that 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 terawatt hour supply from 2 main sources: our own production and energy purchases in the spot market. In summary, considering IEM partial injection in the spot, we supply a bit more than half of our demand with spot energy purchases, while 5% of our expected demand was hedged through 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 or maintenance or were requested to limit their output for these parts for other technical reasons. Our gas plants increased their production despite Unit 16, 28 days program maintenance These plants are better headed to cope with the internal financing caused by renewals. Even though I am getting 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 we do operations, IAM will help us reduce our core energy purchases and thus reduce the operation of our more expensive coal pipelines like Units 12, 13 and Units 14 and 15. In this regard to Units 12 and 13, our plans 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 were average fuel and electricity which is cost per megawatt hour increased. The main reasons behind these increases are: 1st, high coal prices and LNG prices, particularly in the last quarter of 2018. Even though coal prices decreased in the Q1, we burnt fixed purchase at higher prices, and there is some lag in the past through to contract parties. So we should expect decrease in prices and costs in the next quarter as a result of fuel price behavior. 2nd, marginal costs or stock price were higher this quarter as a result of the drop in the Central 1,000,000,000. 3rd, our coal plant reported an unusual number of coal 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 4th, 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 21 IEM in the last tranche of video connection within commercial operations. Now let's move to Page 15. We can observe the duration of our portfolio. It has a 12 year average to remain in line. We are working, as you know, in increasing this duration by signing new contracts or discussing options with our existing clients. I am now on the next page, number 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. Although we had some, we signed a 50 megawatt PCA renegotiation with Anticoia from the Anteslas and Minerals Group. And we also renegotiated PPAs with other free clients, including Molycop, Cuborex, MOL Plaza, Corto Mexicanes and Puerto Armos. The conceptual agreement of this renegotiation is the same applies to previous PPAs, and an initial discount in the short term, a further discount afterwards together with the change in the taxation formula moving to 100% inflation and finally, an extension of the PPA at latest market solutions. On Page 17, we show our main strength and our vision to 30. The green area, which represents renegotiated new PPAs with 3 clients, has continued widening as our commercial B2B team is delivering tangible results. Regarding the blue areas that represent our demand expectations under the related 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 a 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, 1,000,000,000 asset rotation plan, which comprises both acquisitions and development of greenfield projects. We already talked about our acquisition of the Los Louros and Amacollo solar plants, which will contribute 55 megawatts of renewable capacity beginning April and represented $35,000,000 investment. Our development teams are currently working to present for internal approval also the 150 megawatt Kalama Winderm 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 our 20 fourseven renewable of 20 fourseven 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. Capacity. Our idea is to keep several open options in parallel and deciding the production 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 €1,500,000 per year. As we explained before, these projects are interesting because they are located in areas in which we can create synergies. 2nd, they are linked to our renewal portfolio. And finally, they will contribute with regulated revenues. On Page 20, we can see our IEM project, which injected 206 gigawatts power to the grid during the Q1. 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 with a request last Friday. So we expect to be ready in the coming weeks. The projects, what we've been project and once in commercial operation, it will allow us to reduce our generation with the oldest coal plant. This will also allow us to replace part of our purchases and to lower our average energy supply costs to supply our constructive demand. On Page 21, we highlight the operation of Port Alimiport, which required a total investment of $120,000,000 and has been operating since late through Argentina. As you know, this is a mechanized port with the ability to receive key sized carriers. And the advantages of this port are related to economies of scale, better environmental standards, higher unloading speeds and lower denouement costs. As discussed in previous calls, the port full 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, 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, this year delivered solid results in 2018, reaching the high end of our 2018 guidance. For 2019, which is the 2nd year of an important ramp up period, we are keeping the guidance provided last year. You multiply the Q1 EBITDA by 4, it seems that we are behind this guidance. However, the Q1 EBITDA was only marginally below our budget as we had anticipated that the second half of twenty nineteen would be better than the first half due to the following main factors. The completion of the southern tranche of the Inchocilia 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 within the absence of the altiplamic winter, which, as I mentioned before, impacted our results during the Q1. Well, now let's move to the next section. So I will let Bernardo Vida 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 BRL96 1,000,000 in the 1st quarter, a 5% increase compared to the Q1 of last year. Our short summary is provided in the slide title. Higher regulated sales offset lower pre client demand and in constant performance and higher stock prices. So please note that these pre negative items can be largely attributed to temporary taxes. So now let's give a closer look to the EBITDA evolution. First, the new TCA distribution company, which had a ramp up beginning 2019, contributed additional physical sales of 3.70 kilowatt hour and $44,000,000 in additional revenue. 2nd, we reported an increase in average realized prices, which had an 8,000,000 positive impact on EBITDA. This was due mainly to higher fuel prices used in the tariff industry and the greater weight of the higher price regulated contracts. 3rd, we reported a $25,000,000 reduction in fuel costs due to the decrease in generation explained by plant maintenance and limitations owing to further dispatch and technical reasons, which among others included, for example, higher sea temperatures around water discharge structures. Our coal generation dropped to 1 half of what we produced in the Q1 of 2018, while gas generation increased by 3%, despite the maintenance of our Unit 16 complete cycle plant. Our fuel cost should have decreased even more had it not been for the number of plant products to cope with the systems intermittency, which results in higher consumption of diesel. 4th, our operating and SG and A expenses increased by $7,000,000 thanks to our continued cost saving initiatives. Among the effects that put our EBITDA under pressure, we have first, decrease in physical sales from 3 clients, mainly as a result of the properties of mining operations, as Eduardo already mentioned. And regulated clients in the North also reported a decrease in the physical sales. The physical sales decrease had overall a $15,000,000 negative effect on EBITDA. 2nd, higher fuel prices and the drop in Central Argentina caused an increase in spot energy prices. The average realized price at which we sourced energy from the stock market was $59 per megawatt hour versus $46 in the Q1 of last year. These higher stock prices explained a $15,000,000 impact in EBITDA. 3rd, given the significant sales increase, which was accompanied by a decrease in our own generation, we reported higher physical energy purchases, which represented a $40,000,000 cost increase. Finally, the capacity sales increase also requires higher capacity purchases. So the increase in the efficiency capacity provisions had a $10,000,000 impact from EBITDA. Now please turn to Slide 26. There's little to add here as it was the EBITDA increase, the item that explained the $4,000,000 increase in net income. There were very small variations in interest expense or in currency differences and depreciation and only 1 non recurring item, an insurance recovery which had an after tax effect of 1,000,000. Our Q1 net income then reached BRL43 1,000,000 up from BRL39 1,000,000 a year before. On slide 27, we can appreciate a $63,000,000 net debt reduction. In terms of uses of cash, capital expenditures amounted to only $16,000,000 as we approach completion of the I'm project. Then we paid $4,000,000 in dividends to our partner in CTH and we paid $11,000,000 in income taxes. All of these expenditures were financed with operating cash flow and also by a $22,000,000 cash payment from Chen. As you may recall, last year we had an extraordinary shareholders meeting to approve the extension of a corporate guarantee in favor of 10 creditors to free up the cash deposited in the debt service reserve account. With a corporate guarantee, we took release almost $15,000,000 of cash and the remaining $7,000,000 came from excess cash from its operation, it's allowed us to repay debt with its shareholders. Slide 28, which provides details of our liquidity and debt structure has remained changes. The net debt to EBITDA ratio decreased to 2 times at the end of March. Now to support our liquidity in terms of heavy capital expenditures back in 2015, we constructed a committed revolving credit facility In terms of credit ratings, both FMC and FICC have confirmed ECL's international ratings that will be stable, while both Fitch and Cellerate upgraded ECL's national rating to AA- On slide 29, you can see that in 2018, we paid $6,000,000 in dividends and that in the last 4 years, our dividends have been limited to 30% of net income to support our CapEx expansion. Last October, we paid provisional dividend of $26,000,000 on account of 2018 net earnings. And our shareholders approved a final dividend distribution of $22,000,000 on May 24. These two payments together account for 30% of recurring net income. As you may recall, in 2018, we reported $58,000,000 in non recurring losses, primarily explained by the impairment of 2 coal fired plants. Our supply chain solution generally followed the market, although in the last quarter or last month, we decoupled from the Itza and recovered clearly above the market. Over the last 12 months, Israel's share price increased by 1.7%, whereas IXAS thereby 5.1%. So this is all on my side, and I'll leave you with Eduardo to make some final remarks on this presentation. Thank you, Bernadista. Well, to conclude this presentation, as always, I just want to close with 3 main messages. 1st, we are very close as a system to reach the full interconnection of the former CINGA and the CIC systems. And at the same time, the OEM project is ready, only waiting the final green light from the market coordinator. All the events will bring higher efficiency, stability to the overall system solar PV plants totaling 55 Megawatts, and the plan is to continue the development and construction of the first 3 renewable projects during the second half of this year. And first, we can confirm our guidance on operational results for 2019. And therefore, we can confirm a stronger cash generation price that has worked for the company, which will allow further visibility to implement our transformation and development plan. So with this final message, we are concluding our Q1 presentation. Thank you all for your participation, patience, and basically, we are ready for any questions you may have. First question today comes from Ezekiel Fernandez from Credicorp Capital. Please go ahead with your question. Hi. Good day to everybody. Thank you for taking the time to prepare the materials. And I have 4 questions. I would like to go 1 by 1, if possible. The first one is related to Posseco Cardones line, if you have any expectations about when you go online. And sorry, by the way, if you commented on any topic I joined as it relates 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, represent slightly or would represent a slightly improvement in our thoughts because as you know, in our guidance, we consider the final CIB of this line on early July and not on June. Okay, perfect. My second question relates to the gas production during the Q1. And how much of that was Argentina and how much LNG? And if you have any Argentine gas, is it fair to say that the cost of the plant gate is around just $5.5 per Mptu or so? Basically, we started importing 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 income from Argentina will, of course, play an important role in the production of this gas. But in this quarter, the amount of gas was marginal. Okay, great. And I have 2 questions actually. My last one is the pitch to 5 precipitation 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 denying? Perhaps you have a few questions for us. Because we lost a little bit your question. The question was how marginal cost goes to 0 at some hours. Even though at that same point in time, you do have coal and gas output? Yes. Well, so clearly that is basically because of the flexibility of gas declaration. So what I mean is a follow-up. In certain times, like, Kendar or ourselves, 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. I know she would come. Exactly. So you have to we detail that at 0 cost, okay? Okay. And then at this time, the programs that are operating there in those parts, all of them disbarking at their technical need, which means they don't work in. 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 over cost mechanism. So they receive their remuneration, but not marking itself. That's very clear explanation. Thank you very much and the call from my side. And ladies and gentlemen, at this time, I'm showing no additional questions. I would like to turn the floor back over to Energia Choo for the closing remarks. Well, thank you very much for your participation, and see you during the next quarter. Thank you. This concludes today's presentation. You may disconnect your lines at this time and have a nice day.