Endesa SA

MAD:ELE

Earnings Call Transcript 2019-Q4

[Mar Martinez, Head of Investor Relations]

Good morning and welcome to our full year 2019 results presentation, which will be presented by our CEO, José Bogas; and by our CFO, Luca Passa.

In the following slide, we will elaborate on the progress of our strategic plan, according to each key strategic pillars. And after, we will go through the full-year operational and financial performance. Following the presentation, we will have the usual Q&A session, open to those connected on the call and on the web.

Thank you for your attention. And now, let me hand over to José Bogas.

[José Bogas Gálvez, Chief Executive Officer]

Thank you, Mar, and good morning, ladies and gentlemen; and let me start with the main highlight of the period.

Today, we present outstanding results, which have, once again, exceeded our announced guidance, highlighting the ongoing delivery on our strategic pillars. EBITDA increased by 6% compared to last year, mainly driven by the positive performance of the liberalized business. Regulated businesses’ EBITDA kept a steady pace during the period.

Adjusted fixed costs remained flat, as our continued focus on efficiency absorbed the increased investment effort. At the bottom line, net ordinary – sorry. At the bottom line, I said net ordinary income increased by 3% year-on-year, once adjusted mainly by the impairment that we will explain later on. It’s worth mentioning that dividends will not be impacted.

Lastly, I would like to stress the step-up of our decarbonization path by promoting the discontinuity of production at our mainland coal thermal power plants, while accelerating renewable capacity additions.

Moving now to the delivery of the strategic plan and starting from the chief financial target on Slide number 4. EBITDA amounted to €3.8 billion, ahead of the €3.7 billion target. Net ordinary income came in at €1,562 million, an increase of 3% year-on-year, and ahead of the €1.5 billion targeted. This magnitude does not include the €1,409 million impairments booked during the year in relation to the mainland coal fleet closure and to the non-mainland generation business.

This positive result has allowed us to consider a dividend per share proposal of up to €1.475 gross per share, consistent with our policy of 100% net ordinary income payout ratio.

Net CapEx rose by 48% when compared to 2018, clearly showing the acceleration of the company’s transformation leading into the energy transition in Spain. To sum up, we had an outstanding performance this year, exceeding set target across the board.

Moving to Slide number 5, our achievement render significant value creation for our shareholders. Total shareholder return attained a sound 25.3% in 2019, the highest in the last 5 years, considering both the effect of share appreciation and dividend return. The Board of Director proposes, subject to General Shareholders’ Meeting approval, a total gross dividend per share payment of €1.475 per share against 2019 results. This dividend is 5% above our DPS guidance and represent a 3.3% increase over last year’s DPS.

We move now to Slide number 6 on our CapEx deployment. Exceeding our business plan commitment, net CapEx has amounted to €1.9 billion, roughly a 50% increase year-on-year, out of which 53% has been devoted to asset development, especially in renewables. Enel Green Power Spain absorbed the lion’s share with 40% of the total CapEx channel mainly towards development of the 879 megawatt of 2017 auction successfully entering – sorry – successfully entering commercial operation by yearend 2019.

Distribution business followed with 28%, mainly devoted to grid digitalization, a key cornerstone of our business plan. In this sense, it should be noted that digitalization net CapEx amounted to €0.4 billion, a figure that is already 30% of the €1.3 billion committed to for the 2019 to 2022 period.

Following up on the SDGs commitments and in line with our business plan guidance, it is interesting to note that roughly 85% of our 2019 CapEx contributes to SDGs 7, 9 and 11 and overall to SDG 13.

Before diving into the financial performance of the year, I would like to review the progress and comments, the main achievement have made so far on our key strategic pillars.

Acceleration in the transformation of our generation mix is clearly visible in Slide number 7. We have taken the first, but decisive, step to phase out our coal fleet as structural changes in market conditions have heavily affected its competitiveness.

During 2019, Groups 1 and 2 of our Alcudia Power Plant have ceased operation, while we have submitted the formal application to close down Litoral and As Pontes, imported coal power plants, in addition to the Compostilla and Teruel requests already filed last year. Therefore, we expect mainland coal facilities to be phased out by 2021, 1 year ahead of schedule.

All in all, this decision has allowed us to reduce CO2 specific emission to 282 grams per kilowatt hour, achieving the target we set in our business plan for 2020, that is 1 year in advance.

Together with the formal closedown application, we have submitted relative gas transition plan based on a third value-creation policy applied to the specific generation site. These plans include significant investment in new renewable energy facilities in the areas surrounding the plants with the necessary condition for the installation.

These investments will lead to the creation of direct job for the dismantling of the coal-fired plants and for the construction of new ones. All these, whether with the development of professional training actions and the opening of competition for ideas for the future use of certain sites where renewable installations are not feasible, will allow activity and employment, thus mitigating the impact of the affected areas.

A relevant consequence of this process has been the low percentage of income from coal, reaching a level of 12% from total and possibly decreasing towards 0% in the upcoming years.

Moving now to Slide number 8, in order to compensate for the discontinuity of coal production and being fully aligned to our strategic target, we have incorporated 926 megawatt of new renewable capacity, mainly stemming from 2017 auction, reaching a total of 7.4 gigawatt, including hydro. Our solid track record has been proven as we had been one of the few companies to strictly fulfill the deadlines for the commissioning of the plants.

Additionally, on non-mainland system, Enel Green Power Spain was awarded around 72 megawatt of photovoltaic capacity in the auction held in the Balearic Island, and around 16 megawatt in the Canary Island. We estimate that the project will come into operation before the end of 2022 to ensure not only current business plan target, but also a long-term solid capacity addition pace, we are increasing our pipeline of renewable project, also reinforced by the recent transaction signed with Prodiel, which brought an additional 1 gigawatt solar photovoltaic pipeline, all with connection rights.

Our total pipeline now stands at more than 19 gigawatt up to 2025 with a significant weight of solar, around 76%. Out of this pipeline, around 30% has TSO awarded connection points.

Now looking at Slide #9, the new project in operation at the end of 2019 brought sound growth in total mainland capacity, which increased by 5% up to 19 gigawatt. Renewable capacity represents around 40% of total mainland capacity as well – and well on track to reach the target of 60% once coal plant have been phased out by 2022.

Regarding power generation, Endesa’s total mainland output decreased 19% as a consequence of the drop in coal output out of merit orders since April, and the lower hydro production due to the drier weather condition. This was partially offset by hydro nuclear output reaching normalized levels as well as higher load factor in our combined cycles. Our CO2 emitting technologies accounted for around 73% of total mainland output versus approximately 60% last year, well on track to meet our decarbonization targets.

Moving to Slide #10. Despite the drop in Spanish demand and increasing competition in the sector, total gross sales remained almost flat. Consumption by segment remained steady in residential volumes, while industrial sales increased by 1%. In the regulated market, the sales decrease is around 8%, mainly explained by the reduction in the demand and the loss of regulated customers.

The total customer loss has been very limited with a healthy 2% improvement in the liberalized market, where we have managed to retain about half of the regulated customer growth. The customer acquisition strategy and the retention plan put in place since last year has contributed to a sound reduction in the churn rate by 1.3 percentage points.

The unitary integrated margin in the electricity business increased by 7% to €27.6 per megawatt hour, ahead of our €26 guidance. This remarkable margin improvement was mainly supported by the higher OTC price references, a higher nuclear output, the increase in supply margin, mainly from lower ancillary services partially compensated by lower thermal spread and lower hydro availability.

Our liberalized supply margin is close to €10 per megawatt hour, up from about €8 per megawatt hour in 2018, mainly due to better portfolio management and lower cover costs of ancillary service this year. We have already hedged around 100% of our 2020 estimated price-driven output at an average all-in price of €73 per megawatt hour with an estimated all-in for integrated sales including index energy of €65 per megawatt hour.

For 2021, we have hedged around 63% of our estimated price-driven output at an average all-in price of around €75 per megawatt hour. Once we consider our total sales mix, the all-in revenue will converge to the levels similar to 2020 reference.

A few words on the gas business on Slide #11. Total sales have decreased by 3%, mainly due to the 10% drop in retail sales as a consequence of the milder temperatures during the year, while sales to combined cycles increased by 26%. Total customer increased by 50,000, mainly in the liberalized segment due to active client attraction campaigns. The strategy followed in the retail business had positive effects in the churn rate with a remarkable improvement of 3.7 points.

Our ordinary unitary gas margin climbed to €3.4 per megawatt hour, thanks to a steady performance of the retail margin, which was protected by the [higher] [ph] selling price references used last year and the excellent results of the wholesale segment and supply to combined cycles, driven by better sourcing and the active management of our flexible contract portfolio. Excluding the combined cycle sales and focusing on retail and wholesale activities, the adjusted unitary margin would have been €2.7 per megawatt hour.

Moving to Slide #12. In networks, Endesa’s distributed energy remains stable despite the drop in energy demand over the whole country. Operational performance indicators showed a steady result with a contention in losses at 10.7% and improving by 6% when it comes to minutes of interruption in a context of extreme weather events throughout the year. To this end, I would like to thank our technical team for the timely effort in the repair works of facilities affected by the Gloria storm. Being focused on maintaining quality of service, more than €156 million had been invested, around 50% more than the previous year.

All the above is aimed at enabling the policy increase of electrification of final energy consumption. Electric mobility contributed as well with an outstanding effort in electric vehicle charging points deployment, increasing by 67% versus 2018, up to around 5,000 charging points installed. Such an endeavor has allowed Endesa to reach the Spanish leadership position as charging points installer.

Moving to Slide #14. I would like to comment on the market context for the period of this financial release. Spanish electricity demand showed a decline both in gross, minus 1.7%, and at adjusted terms, minus 2.7%, affected negatively by milder temperatures during the period as well as some signs of an economic slowdown reflected in the decrease of industrial consumption.

In Endesa’s concession area, gross demand decreased by 0.6% and had a slightly positive behavior in adjusted term. This development is mainly driven by the drop in the residential segment for set temperature reason, not fully neutralized by the increase of the service sector activity.

Electricity pool prices decreased to €47.7 per megawatt hour on average during the period, 17% below last year. This price scenario is the result of some changes in commodity prices during the year. While CO2 references have remained high, around €25 per ton on average, the Spanish gas market benchmark, PVB, plummeted 58% to the historically low of €10 to €11 per megawatt hour.

Gas market has been affected by a deepening of the oversupply situation in global LNG market, a consequence of new U.S. LNG supply and a pullback in Asia demand affected as well by the drop in Chinese industrial activity. Coal price references saw a similar trend, but to a lesser extent. In particular, coal was quoting in December 2019 at a 37% discount to the €84 per ton recorded at the beginning of the year. Demand decreased, declining commodity prices and lower pool prices shaped the context in which Endesa operated during 2019 and operating successfully.

On Slide 15, just a recap on the regulatory context evolution. 2019 proved to be a very intensive year in terms of regulation. As far as the European Union framework is concerned, the approval of the Green Deal transforming zero carbon emission in 2050 in a binding target while setting very challenging target to 2030. Related to the Green Deal, the endorsement of the fair transition mechanism allows a fund deployment to finance the energy transition between 2021 and 2027.

In Spain, last January 22, the climate emergency declaration was approved, committing to 30 priority measures to fight climate change. Let me remind you that the Spanish government, in order to comply with European Directive, issued a Royal Decree Law handing back regulatory power to the CNMC. To date, 11 out of the 14 CNMC circulars that will regulate the electricity market from 2020 and the gas market from 2021 had been approved and published in the state bulletin, providing a high degree of transparency to our regulated businesses.

After having approved the new rate of return for renewables and non-mainland in November, last January 9, the Spanish ministry for ecology started a period of public consultation on its proposal to review the renewables remuneration parameters for 2020 to 2025.

Finally, a new ministerial order was issued last December 26 on non-mainland parameters confirming the reduction in the remuneration of O&M cost for 2020 to 2025 regulatory period parameters in line with our expectations. Indeed, defined fuel references, which are expected to be retroactive for January 1, 2020, are still undetermined. This backdrop of the new remuneration framework is the reason for the negative impairment test results conducted in this business.

And now I will hand over to Luca Passa, who will present the details of our financial figures.

[Luca Passa, Chief Financial Officer]

Thank you, Pepe, and good morning, ladies and gentlemen. Further deepening in analysis of the main financial figures of the period, EBITDA increased by 6% compared to 2018. And now on Slide 16. The net ordinary income increased 3%, affected by higher financial costs and D&A in the period, while reported net income decreased to €171 million, mainly driven by the impairment effects. A remarkable increase in free cash flow, around 40% higher than last year figure. Net debt increased by 11% over 2018 to €6.4 billion, mainly driven by higher CapEx, IFRS 16 impact and a total dividend on 2018 results paid this year amounting to €1.511 billion. Finally, net CapEx increased by around 48%.

Moving to Slide 17, to illustrate impairments registered in the period. The structural change in 2019 has made the continuity of our all mainland coal thermal power plants sound feasible. Low gas prices, the increasing carbon prices and policy changes have resulted in a structural coal-to-gas full switching, which deepened in the last quarter.

To this end, 2019 figures include an impairment in the value of mainland coal assets which, as of year-end closing, amounts to a growth of €1.469 billion, out of which about €500 million correspond to dismantling provision. This figure includes an effect of €1.366 billion in D&A and €103 million in EBITDA.

In non-mainland generation, the new ministerial order issued last December, which defines an updated remuneration for the 2020/2025 regulatory period, has triggered a negative result of the impairment test carried out at the end of this year, resulting in a gross impairment loss of about €400 million. Both impairments totaling a gross of €1.9 billion are not considered in the calculation of the ordinary net income in accordance with the current dividend policy, so that they have no impact on the elimination of the shareholder remuneration.

Moving to the detailed analysis of the EBITDA on Slide 18, let me now summarize the main drivers. Endesa reported an EBITDA of €3.841 billion, plus 6% versus 2018. Generation and supply EBITDA rose by 22% to €1.475 billion, supported by the sound increase in the integrated electricity and gas margins. Distribution EBITDA increased by 2% at €2.099 billion. Finally, non-mainland generation EBITDA reached €267 million, a 25% decrease. I will comment each business performance in the following slides.

Regulated business contributed to total EBITDA with approximately 60%, and I’m now on Slide #19. EBITDA decreased by 2% to €2.366 billion, with an almost flat gross margin, while fixed cost increased by 5%. Distribution margin increased by 2%, thanks to higher regulated revenues and regularization from previous years and incorporating now the full year consolidation of Empresa Eléctrico de Ceuta.

The non-mainland generation gross margin reduced by €73 million, mainly due to lower production by 7%, the reduction of the revenues related to fuel as a result of the settlement mechanism in non-mainland, which does not entail the full pass through of actual fuel cost. Additionally, a lower function remuneration income due to lower RAB was also booked in the period. Fixed cost increased by 5% year-on-year, mainly affected by non-recurring impacts.

On the liberalized business on Slide 20, EBITDA reached €1.475 billion or a sound 22% increase, driven by €288 million improvement in gross margin and a slight increase in fixed costs. The increase in electricity integrated margin was driven by higher OTC reference prices, the higher supply margin, higher nuclear production and the positive impact of the temporary suspension of the generation tax in the first quarter, partially compensated by lower thermal spreads and lower hydro availability.

Within integrated margin, Enel Green Power had higher contribution of €5 million. In gas, the combined effect of last year’s hedging strategy for retail customers and the extra margin brought by the flexibility of our procurement portfolio drove a 95% increase in the gross margin to €269 million. Endesa X gross margin remained almost flat. Fixed costs remained stable compared to last year once deducted the impairment effect, in a context of a strong acceleration of growth investments, mainly attributable to renewals development for an amount of more than €700 million.

Moving now to Slide 21, our efficiency program is consistently proving to be effective across all our businesses, containing cost despite growth and investment effort. Total reported fixed cost reached €2.065 billion or a 3% increase over last year figure. Once deducted non-recurrent effects, fixed cost would have decreased by 0.5%.

Adjusted figures exclude mainly the accounting effect of the application of IFRS 16 on leases, the stock impairment related to discontinuity of coal plants, as well as other O&M non-recurrent costs booked in both years. Our OpEx evolution remained stable versus previous years with efficiencies more than offsetting inflation, perimeter and growth, with higher CapEx in a new investment cycle.

The integration of the thermal and renewable capacity management is starting to allow synergies, which will deepen fixed cost control reaching a €44,000 per megawatt in 2019, higher of the 2022 target. In distribution, the digitalization initiatives of our processes and assets will bring further reductions in our operational costs.

Lastly, in supply, we have trimmed the cost to serve to €10.6 per customer by minus 3% versus 2018. This is a consequence of leveraging on the digitalization initiatives, such as the following: the number of contracts with the building rose by 36% versus 2018, up to 3.8 million contracts; digital sales climbed from 5.7% in 2018 to 10% in 2019; while, the number of digital contracts have grown 4.8 million.

Finally, just to mention at the beginning of 2020, a satisfactory collective agreement has been signed with the union representatives, which is expected to bring stability and increasing efficiencies in the coming years.

On the P&L evolution from EBITDA to net ordinary income on Page 22 now, starting from the €3.841 billion reported EBITDA, D&A increased by 102% to €3.453 billion as a result of the impairments for a total of €1.770 billion. These impairments compare to €158 million recorded in fourth quarter 2018 corresponding to Alcudia Power Plant’s Group 1 and 2. Excluding this, D&A would have increased by €133 million, mainly explained by the application of IFRS 16 for about €34 million, the amortization of digitalization investment for about €30 million and bad debt provision increase for about €50 million, and the adjustment of Almaraz useful life since April 2019.

Net financial results increased to €184 million, mainly driven by the impact of IFRS 9 and IFRS 16 and the update to the financial workforce provision. Associate and others item, positive for an amount of €26 million, includes €24 million capital gain from the surplus of the optic fiber network transfer agreement with Lyntia.

Income tax expenses amounts to €50 million, 87% lower than in 2018, basically explained by the positive fiscal impact of the impairments. Deducting said effect, the effective tax rate that would have been 24.4%, higher than the 21.6% recorded in 2018 coming from the lack of some fiscal deduction in 2019. As a result, net ordinary income increased by 3% over the period.

Moving now to Slide 23 on the cash flow evolution from EBITDA to free cash flow. Funds from operation increased by more than 30% versus 2018, reaching €3.181 billion, which has exceeded the financing needs required to carry out the important investment effort.

This increase, which represent a historical record cash flow generation since 2014, is due to the following effects: higher EBITDA after provision paid of around €180 million; working capital and others uplifted by €688 million, mainly due to the improvement of the net balance of receivables and payables accounts; lower inventories payment and by the increase in regulatory collections in mainland by about €400 million.

Income tax increased €114 million, mainly due to lower refunds than in 2018. Net financial expenses paid decreased by minus 4%. The increase on cash-based CapEx by 24% was entirely financed by our – by the FFO increase and led to free cash flow of €1.267 billion.

Moving now to Slide 24 on the evolution of the net financial debt, net debt amounts to €6.377 billion, €607 million higher than the previous year once considering the IFRS 16 impact of €274 million; but below the €7.1 billion guidance, mainly due to better results and the good evolution of the regulatory working capital. This item has decreased thanks to the increase in non-mainland collections from tariff settlements and from the general state budget at the end of the year.

On the opposite side, the dividends payments, corresponding mainly to a total gross dividend against 2018 results, added another €1.520 billion to the net debt final figure.

The leverage ratio was 1.7 times. Gross debt as an average cost of 1.8% at its historical lows, which implies a further reduction versus the 1.9% reported at the end of 2018.

Moving now to Slide 25, let me hand over to Pepe for his conclusions.

[José Bogas Gálvez, Chief Executive Officer]

Thank you, Luca. As shown throughout this presentation, once again in 2019, we succeeded in surpassing the target announced to the market. This notable set of result lead us to believe that we have established the basis for our business plan execution.

And finally, moving to Slide number 26, I would like to conclude with some remarks on our performance. The continuous and timely delivery once again, as has been the case every year since in 2014, of our financial target committed to in the strategic plan. The acceleration in decarbonization of our generation mix in accordance with our commitment with the National Energy and Climate Plans and in the COP25, this drives a strong investment effort mainly in renewables capacity development in order to decarbonize, while leading the energy transition.

As a consequence, these results in an outstanding total shareholder remuneration of 25.3% in 2019, providing some value to our shareholders. And lastly, we are highly confident that these results will allow us to work towards our 2020 announced guidance.

And ladies and gentlemen, this concludes our full year 2019 results presentation. Thank you very much for your attention and we are ready to take some questions.

[Mar Martinez, Head of Investor Relations]

Thank you, Pepe. We will answer now all the questions you may have.

[Operator]

Thank you. [Operator Instructions]

[Mar Martinez, Head of Investor Relations]

The first question comes from Harry Wyburd from Bank of America Merrill Lynch. Please, Harry, go ahead.

[Harry Wyburd, Bank of America Merrill Lynch]

Hi, morning, everyone. Three questions from me, please. The first one is on net debt, so it looks like you’ve beaten your guidance by a lot, about €0.7 billion. And if I’ve done my maths right, only about half of that is explained by the move in regulatory working capital since the 9 months and the EBITDA beat. So you mentioned sort of receivables and inventories, what exactly has happened here that’s generated such a big improvement in net debt? And is that sustainable or is it going to reverse out in the first quarter?

Second one is on power prices. You talked about the market situation when you went through the slides. But I guess you still notionally have about €53 Spanish power prices in your business plan and we’re currently at €44, irrespective of whether you agree with the forward market. Maybe you could just comment, if power prices are €44 and if you just assume that they are at that level in 2 years’ time, to what extent have there been positive offsets to that that could still allow you to meet your guidance?

And then, finally, just on gas – and then, talking about gas retail here, so ignoring the power price impact, how is the best way to think about gas? I guess, the first thought is your gas prices have fallen so it’s going to hit your margins. But, obviously, you have a much higher exposure to retail gas customers than many of your peers. And, obviously, retail prices are quite sticky. So should we assume that given how quickly gas prices have fallen is there an opportunity to actually increase margins in the short term? So could you give any sort of guidance as of right now as to what you think gas margins will do for 2020? Thank you.

[José Bogas Gálvez, Chief Executive Officer]

Okay, Harry, I will try just to give you some color or answers to the second and third question about the power price and the gas retail. Power price, you are absolutely right. First of all, I should say that we have something around €53 per megawatt hour in our strategic plan, in our business plan. This €53, as we explained in the presentation of the strategic plan, is based on some assumption.

Mainly these assumptions are the price of the CO2, that is €24 per tonne, and the price of gas, €20 per megawatt hour. What we have seen in the last quarter of the past year and also during this first month of this year is a huge drop in the price of gas. This huge drop is a consequence of weak demand mainly from Asia. It’s a consequence of the winter. And also, it’s a consequence of the significant increase of the offer in the market.

In that case, and also with the coronavirus now, what we have seen is that there are lot of gas in the market looking for some home, and one of them is the European one and the Spanish one. So prices are around €10 per megawatt hour. So, if you compare €10 per megawatt hour with €20 that we had or we use in our assumption that explains you many things. The first one is the drop in the prices, power prices from €53 in our assumption to roughly €40 that we have now in this year 2020.

But this kind of situation, first of all, let me try to be very simple. If we are [lone] [ph] in customers, these low prices will give us an opportunity more than rates. And that is the cases that we have today. We have an opportunity.

Second, what about the evolution of these prices? Well, what we think is, first of all, the forward gas prices for the year 2021 of around €15, €16 that means a recovery of the gas prices. Let me remind you that in the year 2018, the price of gas was €24.4 per megawatt hour. And we are sure, let me say sure, that in the year 2021 we will start to see the recovery of prices growing at least up to the €20 per megawatt hour that we have in our strategic plan. So we are now trying to optimize and optimizing for sure our margins. We did drop in the prices, in the power prices this year.

In terms of the gas retail for the next year, well, let me say, perhaps we will – being absolutely honest and thinking that just to reach the margin of the €3 per megawatt hour is going to be, today is going to be difficult. But we are expecting something around €2.5 to €3 that is slightly decreasing in the margin, but nothing more. And okay, Luca?

[Luca Passa, Chief Financial Officer]

And on the first question, Harry, yes, you’re right. I mean we had a very good evolution of our working capital. We had basically a net balance between receivables and payable accounts, which has been net positive. Obviously, on trade receivables, this was an impact of lower prices in the 4Q. And as well as for inventories we had a positive impact from, obviously, the impairment that we did for our stock of coal.

To give you specific numbers, the net balance of receivables and payable accounts payable were plus €630 million, receivable €455 million and inventories for €65 million. The regulatory collections in mainland was positive €430 million.

Now, part of the question is whether this is sustainable, I’d say going forward, we still expect, let’s say, working capital to be positive in 2020, obviously, not to the same magnitude, at least for now. And we expect the regulatory working capital to increase from where we closed this year, by about €300 million. So to – have an expectation of regulatory working capital of €1.2 billion for 2020, which should drive our net debt guidance at about €7 billion in 2020.

[Mar Martinez, Head of Investor Relations]

Thank you, Harry. We have now Alberto Gandolfi from Goldman Sachs.

[Alberto Gandolfi, Goldman Sachs]

Good morning. Thanks for taking my questions. I would like to go back to power price with a little bit more specific question, please. I was wondering if you can give us a very brief summary of the percentage hedges and the achieved power price for the year that just closed, 2019 and 2021, 2022. And if you agree that by the end of the plan, let’s say, 2022, the terawatt hour exposed to power prices, if we add hydro nuclear and we also take renewables within cap and floor and the merchant you’re bidding, are we going to see about 45 terawatt hours exposed to merchant prices by 2022?

So I’m trying to understand if €9, €10 per megawatt hour move can have up to €450 million un-hedged normalized risk for the portfolio?

The second question is about capital allocation and capital structure, so your CapEx is now going to accelerate and power prices are beginning to come down. So in your Investor Day you talked about a decline in payout to 80% and then 70%. Are you going to stick to that or maybe something has got to give, because you want to keep more firepower? I guess, what I’m trying to ask is where do you rank growth versus cash distribution? Will you want to chase more opportunities domestically in renewables at the detriment of dividends perhaps or is dividend may be the priority?

And the last question is on supply margins. Can you maybe help us out to see, maybe for 2020 you seem to say that margins will remain? Can we see any expansion perhaps, given the reduction in power prices we have seen which was not in your plan, and so supply can maybe mitigate some of the impacts from the power price decline? Or how you’re seeing, for instance, the first 2 months of the year developing? Thank you so much.

[José Bogas Gálvez, Chief Executive Officer]

Okay, Alberto, many question and very detailed questions. So I will let Luca just to answer some of them.

But the easy one, let me say, the supply margin for the year 2020. And I would say that you are right, there is some room just to improve just because of these low prices. But more than the supply margin, it would be the integrated margin. The integrated margin, it would be the one that we are sure that we are going to increase, because of our hedging policy and also because, as I have said before, been loaning customer this situation with low prices is a very good one situation for our interest. And now, Luca?

[Luca Passa, Chief Financial Officer]

Thank you, Pepe. On your first question, as far as hedges, as Pepe commented during the presentation, we have 100% hedged our production or our price driven output for 2020 at an average all-in price of €73 megawatt hour with an estimated all-in integrated sales, which includes also the index energy at €65 megawatt hour, so very similar to where we closed 2019. For 2021, we have hedged around 63% of our estimated price driven output at an average all-in price of around €75 megawatt hour. Once you consider basically total sales including the index portion, we are basically going to converge to the same integrated sales of €65 per megawatt hour.

Now just to comment on this, that 63% means we have an open position of about 13 terawatt hours for 2021, €1 megawatt hour difference between our assumption and, let’s say, the forwards, if you want to do the mark-to-market to the forwards, weighs about €30 million to €40 million to our, let’s say, gross margin. So that’s the gap vis-à-vis the mark-to-market that we have, let’s say, to face.

And as far as capital allocation. First, the dividend policy that we have announced is the dividend policy that we stick to. So 80% payout in 2021, 70% payout in 2022. Now what is the balance between, I would say, growth and let’s say cash dividend or cash returns to shareholders, the plan, as you say, foresees an increasing CapEx basically over the next 3 years with a CapEx deployment in 2022 of about €2.2 billion in that year, which is the maximum that we have in the plan.

Now to your questions, I mean here, we – the plan is to accelerate as much as we can. So if we have the opportunity to spend more CapEx even in 2020, we will do so. And the acquisition of the Prodiel pipeline is exactly to the tender, where we have in the pipeline about – more than 100 megawatt of projects, we’d have with the code in 2020. So there will be an acceleration vis-à-vis what is the CapEx deployment forecasted in the plan, and the current, I would say, capital structure of the company allows for that acceleration with the dividend policy we have announced.

[Mar Martinez, Head of Investor Relations]

Thank you. We now have Javier Suarez from Mediobanca.

[Javier Suarez, Mediobanca]

Hi, good morning to everyone. Three questions also on my side. The first one is on the regulatory context and the regulatory draft on the remunerations for the renewable energies in the period 2020/2025. If you can give us your contribution to that regulatory draft document and what do you believe has to be set in that document promote expansion and fair remuneration of renewables energy. So the question is what is your contribution into that regulatory paper to improve things?

Then the second question is on the Slide #10 on the expansion in the electricity margins on the liberalized market. I think that you mentioned the representation and expansion in 2019 from €8 to €10 per megawatt hour. If you can please remind and explain us again the reason for that expansion in the margin and where do you see that margin in 2020. And also, a clarification in the decrease in the regulated customer that are down by minus 4% in 2019, if you can explain us the dynamic there.

And the third and final question is on the renewable energy expansion. Obviously, there is plenty of debate in Europe, either or not the best way to expand renewable synergies is instead of auctions through contracted PPAs. If you can update on your latest views on what is likely to be the expansion strategy of Endesa on renewables on the Spanish market? Many thanks.

[José Bogas Gálvez, Chief Executive Officer]

Let me try to explain the margin. The margin – the expansion from €8 – above €8 per megawatt hour to the €10 per megawatt hour in the year 2019 is explained by the way in which we have been managing our customer base mainly what we have done is just to take care about these customers with loyalty programs and retention programs. And then as we have said many times, let me say, we are looking for – to increase the value of our customer base. Being the leader in this market, in the supply market, it is very difficult just to compete with others and take care about the prices.

So in that sense, what we are looking for is higher quality in all the sense and attention, et cetera, the loyalty programs and the retention program. With all these and also being feasible in the sense all the digitalization, the digital channels, they’re reducing – they reduced cost, yeah, because of that, has given us this margin of €10. And how we see the margin in the year 2020, let me say, very similar, very similar. That is what we are thinking now.

And what about the auction? As we have said many times, at least I’m not in favor of auctions. That doesn’t mean that auctions are not going to be launched, the government has said that they are going to launch these auctions. I said that I’m not in favor of auctions, because there are many players that mainly the incumbents, one that will go ahead with these renewables project without the auctions. And the auctions, in my opinion, have created the bubble that we have today in Spain with the connections of the renewables to the grid.

Having said that, the only thing that I ask for is just to take care in the design of these auctions just to avoid some kind of a negative effect that could be seen with the options. But in any case, I think that option would be something good for the system. And of course, we will take care and we will go ahead with the auction also and not only with the merchant plants that we are thinking about today.

[Luca Passa, Chief Financial Officer]

And then regarding your first question, Javier, our contribution to the regulatory, let’s say, context for renewables for the 2020/2025, obviously, we are participating as all other companies, but mainly for us it’s not going to change much in the sense that pre-2015 assets in terms of the, let’s say, contribution from that regulation is less than €100 million to our accounts. So the picture will not change dramatically for us whatever is going to be decided in that respect.

[Mar Martinez, Head of Investor Relations]

The next question comes from Fernando Garcia from RBC. Please, Fernando, the line is yours.

[Fernando Garcia, RBC Capital Markets]

Hi, good morning. I have 3 questions. First one is in gas. Could you provide details of the gas cargoes canceled for April delivery according to Bloomberg? An additional question there is did you cancel any cargo before? My second question is you call price impacts in depreciation of the 2020 impairments if with the breakdown of coal and non-mainland impairments there. And the third question, could you provide details of the solar PV portfolio acquired from Prodiel? And there, how much will you pay to Prodiel if all the megawatts are developed? Many thanks.

[José Bogas Gálvez, Chief Executive Officer]

Fernando, let me say, we have canceled 1 cargo – 2 cargoes, excuse me, from Cheniere. And the reason is what we have been doing during the last years. Well, it’s the first time that we canceled. But our contract has this flexibility that allow us to optimize our portfolio. And sometimes, this is just because of the reopeners. Other times, it was, yeah, because we have delays on cargoes or we have advanced orders. And in this case is that because we have canceled these 2 cargoes. But this is the usual management of our portfolio.

When we think that canceling or changing some cargoes and buying in the spot wholesale market it would give us better results than with our portfolio, we do that. We have been doing that during the last year, and we have obtained a lot of optimization or benefit on that. But trying to summarize, you’re right, we have canceled 2 cargoes, because we feel it’s better for us in a way to optimize our portfolio and our [indiscernible].

[Luca Passa, Chief Financial Officer]

Then on your second question, D&A impact from the impairments in 2020. From the coal, we will have a benefit of less D&A for €120 million. And for the non-mainland, benefit of about €40 million. Bear in mind that stripping out the impairment in 2019, D&A it’s €1.683 billion. For 2020, we expect D&A to be just below €1.6 billion.

And on your third question, the portfolio acquired from Prodiel, we paid €90,000 per megawatt or pipeline to Prodiel, which includes also the development of this pipeline. Bear in mind that we can develop, let’s say, our own pipeline in the region of €60,000 to €65,000, so we pay up a little bit. But clearly, here some of these projects have, call it, 2020, as I mentioned before and the majority of them between 2021 and 2022.

[Mar Martinez, Head of Investor Relations]

We have now Enrico Bartoli from MainFirst.

[Enrico Bartoli, MainFirst Holding AG]

Hi, good morning. Thanks for taking my question. I have 2 left. One is on the non-mainland business. You mentioned that the drop in EBITDA this year was due to the only partial recognition of part of the fuel cost. If you can elaborate on the outlook for 2020, and also the impact of that on the profitability of this business would arise from the ministerial order that you mentioned in one of your slides. And the second one is, I would like to go back to the auction system that actually the government is planning to implement. If you can elaborate a bit on what your expectation for this process in terms of timing, maybe the level of competition and the amount of capacity that could be auctioned this year. Thank you.

[José Bogas Gálvez, Chief Executive Officer]

Okay. In the non-mainland, our view for the year 2020 we’re at – you’re right in the sense that we have – just because of the mechanism or the methodology of the remuneration, fee remuneration regarding the non-mainland generation, we have got some difficulties. That means that we have, overall, slightly €40 million less than the ones that we have paid, let’s say that.

And while we’re waiting for the new renewable that was [indiscernible] I don’t know what happened with the microphones. [Technical Difficulty] I don’t know if you have made it better. Someone has changed me the microphone. What in any case, I don’t know where I was…

Now, okay, okay. So as I have said, we are waiting for a ministerial order that will fix the new methodology parameters for the remuneration of the fees. Well, we think that this problem that we have had in the year 2019 will be resolved with this.

[Luca Passa, Chief Financial Officer]

And as far as guidance, I mean, we were already accounting for this basically O&M remuneration in our business plan, which... [Technical Difficulty]

Sorry, we had a problem with the microphone now. We had a problem with the microphone. I was saying that we were already accounting in the business plan for the O&M remuneration that came at the end of December, which basically means that the plan is already forecasting the evolution of non-mainland with an EBITDA very similar in 2020 to the one that we recorded in 2019, which was about €270 million, going down to about €250 million in 2022. And that is driven by several things, including RAB declining. As we said in the plan, RAB at the end of 2019 was about €1.3 billion, it will go down to about €1 billion in 2022.

As far as the auction system that the government is thinking of what we know, because obviously there are no official proposal there, is that the quantity should be about – or the capacity about 3 gigawatt. It should be for different type of technologies and it should be a feed-in tariff. So basically, for the price of production. And we understand that we include 80% of the capacity only and 20% will be merchant. That’s our understanding as of now. But again, there are no official draft regarding the auction mechanism for renewables.

[Mar Martinez, Head of Investor Relations]

Sorry, because I think we have some difficulties with the line. Next question comes from Javier Garrido from JPMorgan. Please, Javier, go ahead.

[Javier Garrido, JPMorgan Chase & Co.]

Good morning. First question is a follow-up on Luca’s comment on 13 terawatt of open position in 2021. Can you let us know how much of that is outright hydro or nuclear renewals, how much is spread? And second question is looking into 2022. I think your comments basically suggest that you are still looking for an integrated margin of around €30 per megawatt hour in 2022, because you see the opportunity from being long clients offsetting the decline of wholesale power prices. Is that what you are saying? Are you still looking for the number – the €30 per megawatt hour target?

And the third question is on your gas operations. If you could elaborate a little bit on how you operate, particularly out of the 100 terawatts hour that you more or less sell every year, how much is the long-term contracted? And how much is bought normally in the spot market? And secondly, you disclosed the margins you make in the retail and wholesale markets. But in the CCGTs, in your sales to CCGTs, should I assume that that’s embedded into the power generation business, so that’s part of your margins in power generation with CCGTs? Thank you.

[Luca Passa, Chief Financial Officer]

Okay. Thank you, Javier. This is Luca. On the 13 terawatt hour position in 2021, it’s all basically what we got the price driven. So it’s a part of new hydro and renewables, which is open. If you do the mark-to-market today with current forwards, say, it’s about basically €120 million less in terms of margins. Obviously, as Pepe commented before, we will have means, not obviously to get this [hit] [ph], because, first, we think that, obviously, the forwards will recover given also where gas is forecasted in 2021. I mean, the current forwards for the PVB is around €16, and if you use this forward, the variable cost of producing through combined cycles is well above the €50 megawatt hour. And as you know, combined cycles will set – is the marginal technology that would set the price.

So we see basically support in that respect plus, obviously, we have other means of mitigating any, let’s say, negative impact especially in supply, where obviously we had a very good performance this year. We are forecasting a similar performance in 2020. And obviously, it depends on how we manage, let’s say, our client base or mix of clients.

When it comes to the 2022, basically, integrated margin, yes, you are correct. We’re still assuming the €30 integrated margin. And when it comes to the third questions on gas, let me just comment that, basically, all our sourcing is basically long-term contracted between – I would say half is, as you know, LNG and half is long-term take-or-pay index to Brent.

Now we basically don’t have a policy on how much we use of the contracted part regarding how do we source our – the client base. It depends year-on-year, whether we see opportunities. And that’s why we canceled some cargoes on LNG, because of an opportunity to source our client base through acquisition on the spot market which is much cheaper. So it really depends on a yearly basis.

And then when it comes to how do we calculate the gas margin in the €3.7 unitary gas margin that we reported in 2019. Obviously, there were also sales to CCGTs in that marginality. Excluding sales to CCGTs that margin would have €2.7 megawatt hour.

[Mar Martinez, Head of Investor Relations]

Thank you. Next question comes from Jorge Guimaraes from JB Capital Markets.

[Jorge Guimaraes, JB Capital Markets]

Good morning, everyone. Just 2 follow-up questions, firstly, regarding the write-off in the non-mainland systems, will it have any impact on the regulated asset price, and therefore, on the remuneration? And secondly, and I don’t know if it’s possible for you to share this information or not, what is on average the cancellation fee of a cargo of LNG? And how the economics of canceling versus going to spot markets work out? Thank you very much.

[Luca Passa, Chief Financial Officer]

Regarding the first question, the impact on regulated asset base is basically none. We just adjust our book value, which is now in the region for non-mainland of €1.5 billion. And as I said, RAB evolution goes from €1.3 billion in 2019 to about €1 billion in 2022. As far as the average calculation of cargo, it’s something that we cannot disclose, because it’s something which is binded by confidentiality with our sources of gas.

[Mar Martinez, Head of Investor Relations]

We have now Antonella Bianchessi from Citi. Please, Antonella, go ahead.

[Antonella Bianchessi, Citigroup Global Markets Ltd.]

Yes. Just a quick follow-up on your debt and on the regulatory receivables, so you are assuming that the debt will remain pretty stable in 2020, and which are your assumption about the dynamic regulatory receivable over the next, let’s say, few years.

The other question is on the financial cost. Do you expect the financial cost to normalize in 2020? And can you elaborate on if on the 2019 numbers, what are costs related to the revaluation of the pension, and if you can specify the number on that? Thank you a lot.

[Luca Passa, Chief Financial Officer]

Regarding evolution of regulatory working capital from 2019 to 2020, as I said, I mean, we have about €900 million in 2019, and we expect an increase of regulatory working capital of about €300 million, because we know that there is something that is coming for about €300 million in that respect. So our assumption of regulatory working capital in 2020 is about €1.2 billion, which is – the majority of it is actually for non-mainland. And this basically drives our net debt guidance in 2020 to €7 billion approximately.

Regarding financial cost normalization, I mean, we closed 2019 at a cost – average cost of debt of 1.8%, which has been record low for the company. Obviously, we will monitor evolution of interest rates and we will see whether there are opportunities to do some managing or better managing of interest rate.

But you should not expect a slight or a decrease in terms of the cost of debt, because we are already at, let’s say, a record low, which is not only a record low for the company, but is a record low for the sector. So it’s actually the lowest cost of debt of a utility in Europe.

[Mar Martinez, Head of Investor Relations]

Thank you. The last question from the call comes from Jorge Alonso from Société Générale.

[Jorge Alonso Suils, Société Générale SA]

Hi, good morning. Can you elaborate a little bit on the tax rate that you expect for the coming years on the back of the potential and current fiscal measures taken by the government? The next one is [indiscernible]. The non-mainland should benefit from lower fuel cost environment, right? So is that offset by the new remuneration framework and this is why you expect, let’s say, the EBITDA that you mentioned before?

But is there a possibility that this environment can have a positive impact on the non-mainland EBITDA list off in 2020?

And the last one is do you see the possibility of signing PPAs acquired in energy from other renewable producers in order to accelerate the expansion of the integrated margin? Or do you feel comfortable with the path of your own renewables development, which if I’m not wrong, do you expect now 3.5 new gigawatts between 2020 and 2022, right? Thank you very much.

[Luca Passa, Chief Financial Officer]

Thank you, Jorge. Regarding the first question, so what are our expectations? I mean, there are as far as potential tax proposals, 2 proposals, one at the central government level and one at local government level. The one at central government level is on the potential budget law, where they are planning to introduce a minimum tax rate for companies of 15% on the accounting result, means that you cannot take into account any tax credit.

For us, we’ll have a minimal impact, about €30 million. So we will see if that comes through or not. The other measure that supposedly should be in the budget proposal of this government is taxation of dividends from international subsidiaries to the holding companies in Spain. And for us, that should not have any effect.

And that at a local level, as you know, there’s been a proposal from the Catalonian government on the [eco tax] [ph] of Catalonia, which foresee basically the proposal of taxation of €5 megawatt hour on basically the generation fleet. For us, that would have an impact of about €120 million if it’s passed through.

Bear in mind that, obviously, this is overlapping with the existing 7% generation tax at central government level. So if they go through with this tax, we will definitely appeal and there are, I would say, grounds for our appeal.

Regarding the third question, whether we are, let’s say, seeing a possibility of acquiring PPAs in order to accelerate expansion of margins, the answer is yes. It’s something that we actually are doing, obviously, in very small percentages vis-à-vis our short position. But there are, I will say, opportunities in the market, where developers are willing to give out energy at very, very attractive prices.

Bear in mind that we retain always the options at the end of these PPA contracts to buy out the assets. So that’s basically a key requirement for us to consider some kind of PPA energy acquisition.

And then the second question was? Sorry, non-mainland. I mean the assumption that we have in the plan regarding fuel cost, as far as non-mainland, is basically a full pass-through. The proposal that has been issued by the ministry at the moment is not exactly full pass-through. There are still, on the gas portion, some basically cost to us. So I wouldn’t say that there is a positive – or potential positive effect from this going through vis-à-vis our business plan targets. So you shouldn’t expect, let’s say, a potential upside from this regulation going through in the next few weeks.

[Mar Martinez, Head of Investor Relations]

Thank you, Luca. Thank you, Luca. We have just 2 pending questions received from the web. The first one comes from Victor Peiro from GVC Gaesco, that he’s asking if we can give some color on the economics behind the electric vehicle charging points, the CapEx deployment during this year and the main figures.

And the other one is coming from Isidoro del Álamo from BBVA, that is wondering if we can give the network value of the non-mainland generation assets after the impairment.

[Luca Passa, Chief Financial Officer]

Thank you, Mar. On this last one. As I said, net book value is about €1.5 billion after the impairment for non-mainland assets. Regarding the EV charging points, CapEx plan, I mean, for the whole CapEx deployment of these charging points up until 2023, we have about €65 million of CapEx, the majority of it actually to the outer years of the plan in which we are going to install also the ultra-fast charging station, which are the most expensive one.

[Mar Martinez, Head of Investor Relations]

Thank you very much. We have tackled all the questions received from the call and from the web. And so, thank you very much for your participation and see you in the next Q1. Bye.