EDP renováveis -utlities

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THIS REPORT WAS PREPARED EXCLUSIVELY FOR ACADEMIC PURPOSES BY [INSER STUDENT’S NAME], A MASTERS IN FINANCE STUDENT OF THE NOVA SCHOOL OF BUSINESS AND ECONOMICS.THE REPORT WAS SUPERVISED BY A NOVA SBE FACULTY MEMBER, ACTING IN

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ASTERS IN

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INANCE

▪ Renewable energy market in the U.S.A. prepares itself for the phase out of PTCs. In 2015 and 2016 more than 8 GW of new wind capacity is installed as developers rush to qualify as many projects as possible for 100% PTC.

▪ The Tax Cuts And Jobs Act serves as a reminder to investors that regulatory risk still exists, even in the U.S. The initial proposals by the House and the Senate are especially threatening for renewables, but the final version has impact mostly on Tax Equity Financing. EDPR is the first company to announce a Tax Equity transaction after the final approval of the Act. The U.S. is still expected to be the most important and valuable market. ▪ In Europe, over 70% of the countries are lagging in estimated necessary wind installations to meet the 2020 targets. However, there is room to further growth, especially in France, Belgium and Italy, as governments and the European Commission are likely to push for more installations to meet the EU directive. ▪ We initiate coverage of EDPR with a BUY Rating and a total upside of 13.59% (with expected dividend included).Our Fair Value is €7.71 per share. Existing Capacity is valued at €6.72 per share, pipeline is worth €0.79 per share and repowering/salvage value accounts for €0.20 per share.

Brief company description

EDP Renováveis is a renewable energy company that operates wind and solar pv farms. Since 2008 the company doubled its installed capacity and currently has a portfolio of more than 10 EBITDA GW installed, making it the fourth largest company in the world in wind installed capacity. EDPR’s core businesses are onshore wind farms located in North America, Europe, Brazil and Mexico.

“EDP

R

ENOVÁVEIS

”

C

OMPANY

R

EPORT

“U

TILITIES

”

3JANUARY 2017

S

TUDENT

:

“B

ERNARDO

U

NAS

”

20679@novasbe.pt

Fuelled by inevitability

Support fades but renewables keep going

Recommendation: BUY

Vs Previous Recommendation HOLD

Price Target FY17: 7.75 €

Upside / Downside (%) 13.59%

Price (as of 3-Jan-18) 6.83 €

Reuters: EDPR.LS, Bloomberg: EDPR PL

52-week range (€) 5.70-7.32

Market Cap (€m) 5954

Outstanding Shares (m) 872.3

Source:

Source: Bloomberg, Nova Equity Research

(Values in € millions) 2016 2017E 2018F Revenues 1650.8 1824 1928 EBITDA 1171.0 1281 1352 EBITDA Margin 71% 70% 70%

EBIT 564 685 764

Net Income (Attributable) 56.3 203.9 215.6 EPS 0.06 0.23 0.25 Net Debt 2755 3040 3414 Source: Bloomberg, Nova Equity Research

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“EDPRENOVÁVEIS” COMPANY REPORT

Company Overview

EDPR is a renewable energy company currently operating in the USA, Canada, Brazil, Portugal, Spain, France, Belgium, Poland, Romania, Italy, Brazil and, most recently, Mexico.

The company was initially created under the brand Enernova – Novas Energías to operate the renewable assets of the parent company EDP – Energías de Portugal. First, the company focused on expansion in the Iberian market and then, in 2007, it entered in North America through the acquisition of Horizon Wind Energy making it the fourth largest wind company by Gross GW installed. In June 2008, following the trend of the largest European utility companies, EDP decided to take EDPR public through an offering of 20% of the renewable energy unit capital. The company was priced as the fourth largest wind power company with a market cap of €7.2 billion. In March 2017, EDP launched a buy-back offer over the remaining 22.5% of EDPR, but the bid was not successful.

By the end of the third quarter of 2017, EDPR had 10 321 MW installed wind capacity.

Shareholder Structure

EDPR is controlled and consolidated by the parent company EDP which owns 82.5% of share capital and voting rights, followed by MFS Investment

Management with 3.1% while the remaining 14.4% is spread amongst other investors. EDPR is a company that does not have very high liquidity which was one of the reasons presented by EDP for the buyback offer.

Strategy

The company’s initial strategy was to consolidate itself in its core markets (Iberia and North America) taking advantage of the incentives in place, mostly through feed-in-tariffs and tax credits. Then, it started to expand mainly in Europe to countries that were shifting to a more favourable renewables policy such as Poland and Romania. More recently, EDPR started to focus on emerging economies such as Brazil (€325 million invested from 2009 to 2016) by expanding its capacity and Mexico by building its first installation through a project finance transaction of $278 million. Still, the company’s strategy is very much the same in its core: pursue projects that have stable and predictable cash flows, either through long-term contracts or determined remuneration schemes, in order to mitigate risk of profitability swings. In that sense, until 2020, most of Chart 3: Shareholder

Structure

Chart 1: Installed Capacity (MW)

Chart 2: Cumulative Installed Capacity per company (MW)

Chart 4: CAPEX per region Source: Company Reports Source: Company Reports

Source: Company Reports, Nova Equity Research

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the growth is expected to come from North America supported by long-term PPAs and the Production Tax Credit legislation, followed by Europe fuelled by its Renewable Energy Directive and then Brazil for its natural resources when it comes to wind energy coupled with long-term agreements through auctions. Additionally, EPDR has focused on delivering quality operational performance by engaging on a strategy to reduce its O&M Costs through a mix of internalization and outsourcing, superior load factors due to more efficient maintenance, site locations, track-record and know-how. The company’s EBITDA margin has been slowly improving over time and in 2016 it was 70.9%, almost 100 basis points up from 2013.

Finally, the company tries to use a self-funding model through an asset rotation program that allows EDPR to gain flexibility regarding its financing sources, while retaining operational control over its farms.

Valuation

The valuation methodology was based on a Sum of the Parts Discounted Free Cash Flow (DCF) Model. Three scenarios (base case, optimistic and pessimistic) were built and weighted according to different probabilities (85%,5% and 10%, respectively).

The optimistic scenario assumes countries in Europe correct the problems and uncertainties regarding existing capacity but, most importantly, aggressively push for the 2020 and 2030 targets. Both Europe and U.S. create new support

schemes or extend those in practice (such as the PTCs) to incentivise new installations. It also assumes that CAPEX is drastically reduced as a result of technological improvements which also lead to higher load factors. Hence, the value is driven mostly through pipeline. The pessimistic scenario assumes the regulatory risk materializes in some European countries with retroactive changes which has a significant impact on the value of existing capacity. Moreover, in aftermath of the sovereign crisis, not enough long-term reforms were made which, again, hinders the support governments can provide to the development of renewable energy. In the U.S. it is assumed that a policy of anti-renewable, or support of other non-clean sources, is put into practice, reducing the value of existing capacity but, most importantly, significantly reducing new installations and their value creation. We also assume that the load factors and CAPEX will not have such a positive evolution as the one expected, as a natural

consequence of the environment surrounding renewables.

Geographies were divided into Portugal, Spain, North America (including USA and Canada), Brazil, Mexico and Rest of Europe (aggregates France, Belgium, Romania, Poland and Italy by splitting top lines but merging costs as reported by Chart 5: EBITDA Margin per

company

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the company). Existing capacity, pipeline (onshore and offshore) and salvage value were valued separately.

For future pipeline we assumed EDPR to continue installing new wind capacity in North America and in Europe at a rate consistent with its past performance. In NA, until 2016 EDPR was able to capture, on average, around 4.4% of new capacity each year and about 2.88% in Europe1_{. We proceeded to forecast what}

would be the future total installed capacity for these markets and assumed EDPR would continue to have these historical market shares regarding new capacity. However, in forecasting of total installed capacity, we are less optimistic the consensus. In Europe, it is expected wind energy capacity to surpass 320 GW by 2030 but we only expect around 290 GW. In NA, the White House had defined in 2012 a very “ambitious but feasible” scenario of installing 11 GW per year until 2050, but in our opinion installations will not surpass a maximum of 10 GW and from 2018 to 2050 we estimate an average new capacity per year of only 6 GW. The reason for this is that the recent developments in the U.S. serve as a

reminder of the regulatory risk in the country and that the support and expansion of renewable energies may be hindered by political forces, making such

ambitious targets harder to achieve.

In Europe, the National Renewable Energy Action Plan hasn’t been followed by most countries, so the push towards meeting the 2020 European Union targets may be compromised. According to our estimates, in 2016 over 70% of the EU-28 countries didn’t have the expected installed wind capacity by then to meet the targets, and the deficit was over 7 GW. Although these expected capacities are merely indicative, and countries may choose the most optimal mix of renewable energy technologies, they should serve as guidance for the future evolution and we would have to see more clearer measures by countries regarding wind installations to be comfortable assuming more optimistic scenarios with more confidence.

2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E 2021E 2025E 2030E 2035E EDPR EU Installed Capacity (MW) 3 876 4 167 4 231 4 965 4 986 5 252 5 518 5 799 6 098 6 414 7 491 8 818 9 957 Total Installed Capacity EU-28 (MW) 106 454 117 384 129 060 141 726 153 730 162 954 172 731 183 095 194 081 202 814 241 860 287 253 325 001

EDPR NA Installed Capacity (MW) 2 876 2 877 3 221 3 629 4 016 4 446 4 875 5 309 5 520 5 838 7 366 9 047 10 067 Total Installed Capacity NA (MW) 60 005 61 108 65 877 74 472 82 171 86 442 90 560 93 624 95 707 102 885 137 400 175 361 198 404

We assume EDPR will still be able to sign PPA agreements in NA since the company has been able to diversify beyond signing contracts with other utility

1_{Historical data provided by windexchange for the USA and windeurope for Europe}

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companies as shown in 2015 when EPDR and Amazon agreed on a PPA for the 100 MW Amazon Wind Farm US Central in Ohio. In our opinion demand for long-term contracts will continue to grow as companies other than utilities, such as tech and apparel companies increase demand for these agreements.

In Europe from 2020 onwards, we evaluate the pipeline onshore based on a theoretical project in European soil and not specific to a country. The reason for this is the limited information regarding projects beyond 2019 in Europe and the difficulty to pinpoint which installations will be made in which country. Hence, we believe it is more reliable to model a project at a European level with the 2020 and 2030 Renewables Energy Targets in mind.

Regarding the offshore pipeline in Europe it consists of two projects: Moray Offhore Windfarm in the U.K. and two wind farms in France at Le Tréport and on the islands of Yeu and Noirmoutier.

The Moray project consists of a 15-year Contract for Difference with tariff set at £57.50/MWh in real 2012 terms for an installed capacity of 950 MW . EDPR owns 77% of the project and ENGIE the remaining 23%. Given the low tariff and the high CAPEX of offshore wind (which we estimate at €3.41 million per MW in line with NREL estimates) coupled with high O&M costs (above €32 thousand per MW), we estimate very limited value creation, below €30 million for EDPR, even with expected load factors above 48%.

In the 1000 MW French project consortium led by ENGIE in which EDPR holds 43%, the value creation is much higher given the high tariff (we estimate the tariff to be close to €135/MWh in line with the minimum price for previous offshore auctions in France) although the load factor won’t exceed 40%. We estimate this project to create a value around €270 million for EDPR.

Capital Expenditures (CAPEX)

EDPR is in a business which is, naturally, very capital intensive. Building a wind farm requires a significant amount of capital investment that will only be returned a few years into the future. To determine the CAPEX we based our analysis on historical data from EDPR but also from other reports and studies to get a better sense about the future evolution of these costs.

It is estimated that, in 2015, Turbine Costs which include the rotor, the nacelle and the tower module represented over 70% of the total CAPEX2_{, while the}

Balance of System that comprises engineering, site access and development and grid connection only represented 20%, with the remaining belonging to other minor costs such as contingency funds. Overall, the cost of wind installations has suffered important reductions over the years. Between 2014 and 2015, CAPEX

2_{National Renewable Energy Laboratory (NREL)}

Graph 6: Wind Onshore Cost Breakdown ($/kW)

Graph 7: CAPEX per geography forecast

Source: NREL

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for a theoretical wind onshore installation decreased about 1.2%. Graph 6 shows the evolution of wind onshore costs since 2010 and although the cost related with turbines hit its lowest point in 2011, the higher cost in 2015 is more than offset by the increase in Load Factors and reduction in Operation & Maintenance Costs which translates into a clearly lower Levelized Cost Of Electricity for Wind. For future installations we assumed a CAPEX of $1.69M per MW for North America in line with the latest NREL estimates, €1.3M for Europe and R$5.9M for Brazil in line with EDPR’s historical expenditures, which will be depreciated over 30 years. In our opinion installations in European Union countries should be slightly lower than in the U.S. given that there is more track record of gross installed capacity in the EU-28, while in Brazil it reflects extra costs regarding legislative issues, site accessing and grid connection.

It is very likely that we see further decreases in CAPEX, as turbine manufacturers keep delivering more efficient technology but also start to get more pressure by the end of important renewable energy incentives such as in the U.S. which reduces the ability for renewable energy companies to pay as much. Moreover, historically, the burden associated with lower returns on renewable energy projects has been translated mostly to the turbine manufacturers instead of the developers themselves, as shown by the recent evolution of turbine prices3_.

Given the importance of turbines in the financial structure of the overall project, we expect CAPEX to follow the same trend as turbine costs.

Average Selling Prices

Although most of EDPR’s portfolio is under PPAs or incentive schemes that grant limited or no exposure to market prices, those will eventually end. Therefore, we expect prices in the long-run to converge towards market prices.

To estimate future average selling prices, we used historical data and energy futures market when available. Due to the regulatory framework, in the short-run, we expect some countries to have an average selling price well above the market which we estimate to evolve in line with inflation4_{. In the long-run, as assets}

gradually stop being under incentive schemes, we converge the selling price towards the market price which is assumed to evolve according to inflation. In Portugal, we estimate the Average Feed-in-Tariff for the original assets to be decreasing from around €101/MWh in 2015 to just over €98/MWh in 2016. This tariff evolves according to inflation, but we reduce (proportionately) the value of it in years where we expect assets to stop being remunerated by this regime or to be transferred to the option regime where we expect tariffs to be very close to the

3_{Resort to Wind Turbine Section for historical data on Turbine Prices} 4_{IMF Estimates}

Graph 8: CAPEX per company

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floor (€74/MWh). For the ENEOP Assets, the tariff for the first year was established at c.€74/MWh and is subject to monthly CPI updates. According to our estimates the Average Feed-in-Tariff in 2016 was €74.63/MWh. Again, we proportionately reduce the price according to the eligible capacity under this regime, but these should only happen much later at around 2030. Regarding the VESTINVESTE Assets, our estimates point towards a tariff around €87.72/MWh in 2018 which is derived from the median of the cap and floor of the latter remuneration scheme in 2016 and then adjusted for expected inflation, and we assumed a future evolution according to inflation.

In Spain, the average selling price is expected to be around €48.78 in 2018, representing 95% of the pool price (percentage computed based on historical reported selling price versus MIBEL pool price). The pool price was forecasted based on OMIP Spanish Future Prices and then assuming a 0.25% growth rate to match the Spanish Government’s posture regarding electricity prices. Spain and Portugal are going under a period of severe drought which has cause electricity futures to jump mostly driven by the lower hydro production which may lead to higher average selling price in 2017 (because of higher prices in the fourth quarter) and in 2018 (as a result of higher prices in the first quarter) but we see this situation as temporary and not structural. According to our estimates, the Remuneration to Investment should be close to €182M until 2026, around €152M in 2027, €118M in 2028 and gradually decrease to €0 in 2033 as assets stop being eligible for the remuneration.

For France, Belgium and Italy we expect prices to evolve according to local inflation, as the remuneration schemes are expected to be fairly constant. In Poland and Romania, there were significant decreases in past years on average selling prices due to the cut back in incentives to renewables mostly driven by the green certificates issues, but recent developments lead us to expect the situation to be relatively stable in the medium term. For 2017, we estimate a 2.5% reduction in average selling price in Poland and only a 1% increase for Romania.

Regarding the pipeline from 2020 onwards we assumed a price of €50/MWh in 2016 based on the values of recent auctions (wind and broad technologies) across Europe. This price evolves according to the EU-28 Inflation rate which translates into €53.28/MWh by 2020.

In North America, we assumed the assets under PPA/Hedge to be mostly remunerated according to a variable price escalator linked to inflation and we estimate an average selling price of $49.47/MWh. In our opinion, in the short-run there is some downward pressure in PPA prices, however, we forecast EDPR’s

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PPA portfolio to evolve according to inflation until 2020 since new additions aren’t expected to severely affect the portfolio as a whole, then we assume a growth rate of only 0.75% until 2025 as PPAs signed in those years are more likely to be signed at slightly lower prices or with lower escalators as a result of more

competition for stable remuneration schemes due to the fade out of PTCs in some older projects, although we don’t expect sharp decreases in the coming years due to the benefits of PPA agreements for the purchaser as well. From 2026 we assume PPA prices to rise according to inflation. At the same time, we must take into account that the PPA price shouldn’t be too far from the merchant prices. Regarding EDPR’s portfolio, in the past 3 years merchant prices have been, on average, 22% below the PPA price. In previous years this difference reached 42%; for the medium-term our estimates point towards a difference of 23%, which is in line with recent behaviour. For the assets exposed to merchant prices, we assumed a growth according to inflation.

In Canada, we also assumed evolution according to inflation but in 2020 we expect a decrease of around 15% in average selling price as a result of 248 MW entering into operation which are expected to have a very low tariff ($29/MWh according to our estimates). According to BNEF the results of this auction lead to the lowest levelized auction tariff of the Americas. The weighted average price per MWh is set at C$37, which we consider fairly low, but it is still a 68% premium over the average market price in 2017 which was around C$22. It suggests that the Canadian government is expecting an increase in market prices as a result of coal retirements in order to decrease the tariff burden, which BNEF estimates to be C$630 million in real 2017 dollars in case prices remain flat for the 20-year duration of the contract.

All in all, in the long-run, we expect prices of EDPR’s portfolio to follow the inflation rate as some of the support schemes are indexed to inflation and it provides a good theoretical basis for linking contracts such as PPAs, although demand and supply dynamics may prove otherwise in the short-run, and they should be close to the evolution of gas prices, such as the Henry Hub Curve in North America, as the electricity price will tend towards following the natural gas trends.

Again, when a significant quantity of assets with a very different remuneration scheme enter into operation, the average selling price is proportionately reduced to grow below the inflation level for that particular year.

In Brazil the average selling price decrease by more than 40% in 2016 which we attribute to 120 MW of new capacity coming into operation. In 2018 we expect a 20% decrease and, in 2023 a 30% reduction in average selling price also due to new capacity. Except for these increases in capacity we expect prices to follow

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local inflation.

In Mexico, EDPR’s electricity supply agreement is set in USD and we assumed it to be linked to U.S. Inflation. For 2017, we estimate an average selling price of $57.22/MWh based on a weighted average of the North American quarterly results for 2017.

Operations And Maintenance (O&M) Costs

We considered the bulk of O&M costs to be comprised of Core Operational Expenditures (OPEX) which consists of External Supplies and Services, Personnel Costs and Other Operating Costs. EDPR’s strategy regarding these costs has changed in recent years as the company becomes more experienced in dealing with maintenance and full scope contracts expire. This means EDPR is shifting towards internalizing the main maintenance activities in Europe (M3 Model) while looking to insource preventive, logistics and small corrective activities in North America (Self Perform Model). The company has shown in the past the ability to optimally choose which operations should be outsourced (usually labour-intensive tasks) and which should be under control of EDPR, without compromising the operational performance; for instance, in 2014 the company announced that the implementation of this strategy led the time needed to replace major components from5 months to 3 days according to the company. The portfolio of wind farms under M3 or SP Model in 2015 was 30% and the company expects this to increase to 50% by 2020.

Load Factors

The load factors measure the output of each turbine during the year. They are naturally volatile as they depend on the location of the farm, the type of turbines and the materials used, the efficiency of the companies in performing scheduled and non-scheduled maintenance and so on. In the short-run we assumed load factors close to their historical averages however, going forward we expect technological breakthroughs to continue. There should be a continuous investment to search for more efficient ways to build and operate ever larger turbines, due to increasing returns to scale in a sense that when we double the width of a turbine we more than double the output that it can provide, which should drive load factors up. Moreover, these turbines should be able to be installed at greater heights to benefit from better load factors and should be capable of withstanding more damage since these places will often be harsher and more intensive from a maintenance point of view. Companies will seek to improve the designs of the systems used to control KPIs related to the wind farms and to weather conditions itself which will impact load factors in a sense Graph 11: U.S. Average Load

Factor

Graph 9: OPEX per company

Graph 10: EDPR load factor per geography

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that companies will be even better at predicting the optimal times to perform fixed maintenance as well as the most efficient response to unplanned issues.

Forecasts were made based on estimated historical performance, company’s guidance on expected load factors given the location of wind farms and operational efficiency, as well as a long-term expected trend for technological improvements.5

Weighted Average Cost Of Capital (WACC)

The market is currently under very low interest rates due to the intervention of Central Banks namely through quantitative easing. In our opinion the current situation is not fully representative of the risk because of these distortions and using such low interest rates would overestimate the valuations. To correct for this situation, we relied on the 10-year sovereign forward curve for each country and then proceeded to correct the cost of debt according to a country risk

premium and a company specific risk premium based on an EDP long-term bond yield. We assumed a market risk premium of 5% in line with the consensus of an historical implied MRP between 4% and 6%. To compute the Beta we proceeded to gather the Debt to Equity ratio and Levered Beta for the companies that we perceived as most comparable to EDPR, then we unlevered these Betas and averaged them to get a theoretical Unlevered Beta for EDPR. We assumed a 100% target Debt to Equity ratio going forward based on an optimal capital structure for EDPR.

For European countries we used the German sovereign curve and for the operations in North America we used the U.S. sovereign curve. Regarding emerging economies in Latin America (Brazil and Mexico), we started with the U.S. sovereign curve but on top of the credit rating adjustment we added a rating-based equity spread to each of them, rating-based on Professor Damodaran’s

methodology. For Rest of Europe, since we aggregate several countries, we compute the country credit risk premium and tax rate as a weighted average based on installed capacity.

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Table 2: WACC Assumptions

Portugal Spain Rest Of Europe North America Brazil Mexico

Risk Free Rate (%) 1.83% 1.83% 1.83% 2.39% 2.39% 2.39%

Country Credit Risk (%) 1.71% 1.10% 1.00% 0.00% 1.89% 1.20%

Rating Based Equity Spread (%) 3.00% 1.20%

Company Credit Risk (%) 2.05% 2.05% 2.05% 2.05% 2.05% 2.05% Market Risk Premium (%) 5.00% 5.00% 5.00% 5.00% 5.00% 5.00%

Unlevered Beta 0.57 0.57 0.57 0.57 0.57 0.57

Levered Beta 1.02 1.00 1.01 1.14 0.95 0.97

Tax Rate (%) 21% 25% 23% 21% 34% 30%

Debt To Equity Ratio (%) 100% 100% 100% 25% 100% 100%

Debt To Capital Ratio (%) 50% 50% 50% 25% 50% 50%

Tax Equity To Total Capital Ratio (%) 50%

Cost Of Debt (%) 5.59% 4.99% 4.89% 4.44% 6.33% 5.64%

Cost Of Equity (%) 6.95% 6.84% 6.91% 8.11% 9.99% 8.42%

Cost Of Tax Equity (%) 7.50%

Weighted Average Cost Of Capital (WACC) 5.68% 5.29% 5.34% 6.65% 7.08% 6.18%

Market Regulations

EDP Renováveis operates in highly regulated markets, however, each country in which EDPR is present has its own legislation. The regulations themselves aren’t the same throughout time, they have suffered amendments in the past, and there is possibility for future changes as well. This creates different dynamics from one country to another, both in terms of risks and opportunities.

Portugal

Portugal has committed itself to a 31% share of renewable energy on total gross consumption by 2020. In 2016 renewable sources accounted for 58% of total production.

The renewable energy sector in Portugal was once very attractive to investors, leading the cumulative installed capacity to almost double between 2007 and 2009, but the IMF bailout led to the re-negotiations of the support to renewables which hindered the development of new projects. Now, as the country starts to pick up pace again, the focus seems to be on small-scale and self-consumption generation mostly through solar pv and lowering energy prices and the electricity tariff deficit.

In early 2017 the Portuguese government announced an investment of €800 million in renewable energies for a capacity of around 750 MW. 380 MW of solar energy was already approved as well as 41 MW relative to biomass.

In our opinion, the legislation for previously installed assets is still quite

favourable and the most beneficial for renewable energy out of all the portfolio of EDPR, confirmed by our estimates (Portugal has the highest value per mw of existing capacity). However, there are risks of adjustments of the tariffs as one can see by the proposal by one of the left-wing parties that supports the current left minority government of a 30% tax on the “difference between the average Graph 12: Estimated necessary

capacity for 2020 Target vs current capacity

Graph 13: Production of electricity by source 2016 Source: NREAP Targets, Nova Equity Research

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price of electricity on the day of sale and the guaranteed tariff” that would apply to renewable energy companies. This proposal was negotiated with the government on a first instance, but three days later the government decided to vote against the tax in the parliament.

In Portugal there are three different regimes based on the assets. The older, original assets are remunerated according to a Feed-in-Tariff during 15 years of operation with an option to extend the regime for an additional 7 years under a cap and floor system (€74/MWh to €98/MWh). The tariff is subject to monthly CPI updates.

The assets related to the ENEOP consortium which EDPR acquired and fully consolidated are remunerated according to a price defined in an international competitive tender and set for 15 years with an option to extend the regime for an additional 7 years under a cap and floor system (€74/MWh to €98/MWh). As mentioned previously, the tariff for the first year was established at c.€74/MWh and is subject to monthly CPI updates. The Vestinveste assets are remunerated according to a price defined in an international competitive tender and set for 20 years.

Spain

Under the EU Renewable Energy Directive 2009/28EC, Spain must achieve a 20% share of renewable energy in gross final consumption.

Spain has gone through some regulatory changes over the last years. Before 2013, assets were under the RD6_{436/2004 or RD 661/2007 regime which}

defined a fixed or variable tariff indexed to inflation. In 2013, the assets under RD 661/2007 shifted to the RD 2/2013 which removed the variable tariff scheme and changed the inflation index. Still in 2013, Spain announced a new legislation created under the RD 9/2013 which defined a whole new framework that indexed the return to the 10-year Spanish bond yield and eliminated remuneration received for reactive power.

On June 2014, Spain approved the RD 413/2014 that structures the wind remuneration as a pool price and a premium per MW based on the date of operation of the asset if necessary for a “standard asset” to receive a pre-tax return (7.4% for the first regulatory period - until 2019) defined as the yield of the Spanish 10-year bond plus 300 bps. On February 2017, the first interim revision was conducted which adjusted the caps and floors by lowering them as a result of lower expected pool prices, and it also increased the capacity complement per MW for all assets.

6_{Real Decreto. Some assets were under a transitory regime, when shifting from the old RD 436/2004 regime to the RD 661/2007}

Graph 14: Estimated necessary capacity for 2020 Target vs current capacity

Source: NREAP Targets, Nova Equity Research

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The Spanish Energy Minister has been known for trying to keep pool prices low, supporting an energy mix consisting of coal and nuclear energy and going as far as clashing with Spanish electrical companies to stop the closure of coal plants as that would lead to sharp increases in prices.

North America

North America is the most important market both in terms of revenue as well as growth opportunities. Most of EDPR’s assets in the USA are under PPAs, long term bilateral contracts with other companies for the sale of electricity at pre-defined prices and therefore have no exposure to market prices. There are several incentives in place for wind energy on a federal and state level, such as Production Tax Credits (PTC), Investment Tax Credits (ITC) and Green

Certificates (GCs).

Production Tax Credits are inflation adjusted credits collected for 10 years since the commercial operation date and are expected to phase out until 2020. The value of the PTCs depends on the start of the construction.

The legislation states that, in order to qualify for the PTCs, wind farms must be put into operation four years after the start of their construction.

There is also a safe harbour clause that allows EDPR to secure the full value of the PTCs if 5% of a project’s capital components (CAPEX) are safe harboured in a given year and construction is complete within 4 years. This clause, in theory, protects EDPR’s future projects as well as adds flexibility to its decision over which wind farms to build, in a sense that EDPR may choose to safe harbour 5% of the CAPEX for a specific project but later allocate these rights for the PTCs to a new wind project that is more favourable.

The U.S. Tax Cut And Jobs Act voted in December 2017 reminded investors of the regulatory risk that renewable energies still face. The new tax reform bill introduced by the Republicans in the House of Representatives would make significant changes to the current wind energy incentives and in our interpretation proposed to change the terms of the PTC qualification by requiring the

construction to be continuous rather than to be put in service within four years of when construction began. This would disqualify projects under current safe harbour and for these projects to qualify to the PTC regime, immediate

construction would be required, which would pose immense problems in terms of financing and engineering, procurement and construction. Another massive change would be the elimination of the PTC inflation adjustment for certain facilities. The Senate proposal was smoother in terms of impacts on the renewable energy industry with less extreme measures, yet it still included the Corporate Alternative Minimum Tax and, most importantly, the BEAT provision,

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which is essentially a minimum tax designed to apply when U.S. taxpayers make payments to foreign entities that are deductible in their taxable income. Since PTCs and ITCs reduce the tax liability, the BEAT provision would offset their benefits which, in turn, would have a very negative impact on the Tax Equity Financing market.

The final version of the Tax Cuts and Jobs Act turned out to be much more renewable friendly than the initial proposals. It eliminates the Corporate Alternative Minimum Tax and maintains the PTC Inflation Adjustment and MACRS. Most importantly, it introduces changes to the BEAT provision by allowing PTCs and ITCs to be used against the BEAT. This change means that the BEAT liability is reduced by the PTCs and ITCs. It also decreases the Corporate Tax Rate to 21%, but this is should have limited impact in the short-term for EDPR given the expected low taxable income. In our opinion, at least in the short-run, the effect on the Tax Equity will offset the Corporate Tax Rate reduction.

Nonetheless, this tax reform will surely have impact on the Tax Equity Financing market since the value of the PTCs and ITCs in the long-run will be harder to estimate and more uncertain, given that this relief expires in 2026 but its extension may be a possibility.

In order to take advantage of the PTCs, EDPR uses Tax Equity financing. Through these agreements, EDPR sells a stake in its in exchange for a percentage of the capex. The company retains control of the operations, but allocates virtually all benefits related to the operations, production tax credits and depreciation (through MACRS – Modified Accelerated Recovery System) to the tax equity investor. This system will remain until a specified date in the case of a fixed flip or until the investor receives a pre-determined after-tax Internal Rate of Return (IRR), after which most of the benefits flip to EDPR.

As mentioned previously, our most relevant concern is the newest tax reform law which, in practice, introduces limits to tax equity. Since this form of financing can represent up to 70% of the investment in some cases, we expect the size of the tax equity market to decrease and the yields required by investors to increase. The changes will most likely hit small and medium scale developers, so we believe EDPR’s new project will not suffer too much with these changes since investors already required a lower yield for the company’s projects than for other renewable energy companies. Moreover, EDPR was the first company to announce a Tax Equity transaction of $507 million after the tax reform was approved and signed into law, of which $439.6 million relates to the Meadow Lake V, Redbed Plains, Quilt Block and Hog Creek ($115 million were already funded back in September 2017) and $67.6 million relates to three solar plants.

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Although the yield of the deal was not disclosed, in our opinion it proves that the company has been able to adapt to the new environment and keep signing new agreements.

All in all, financing costs may increase in the coming years due to this reform, but EDPR has enough track record of successful cash flow generation to, most likely, ensure yields that, although higher, won’t compromise future projects nor the long-term profitability of the company.

France

In France, wind assets are remunerated according to a Feed-in-Tariff for 15 years indexed to inflation. In the first 10 years they receive €82/MWh and from then onward the tariff depends on the load factor (€82/MWh for 2400 hours of production, decreasing to €28/MWh for 3600 hours).

France committed itself to achieve a target of 23% from renewable energy sources in gross final consumption of energy by 2020 as part of the EU Renewable Energy Directive 2009/28EC.

We estimate a very promising outlook for France when it comes to renewable energy. President Macron has set the target to reduce France’s share of nuclear power from 75% in 2017 to 50% by 2020, to reduce greenhouse emissions by 40% in 2030, to phase out coal power by 2021 and to double wind and solar capacity by 2022.

More recently on September 2017 the European Commission approved four schemes to support electricity production from renewable sources in France. The onshore wind scheme will support 3 GW of new capacity until 2020 and will take the form of a premium on top of the market price for medium or large-scale project. However, the scheme is complemented with a technology-neutral tender, meaning wind and solar effectively compete with each other for contracts. Overall, we think installation of new projects in France will depend on the

country’s ability to reduce bureaucracy, as it currently takes about 6 to 8 years to get onshore wind farm approved and built since the legal processes, such as permitting and acceptance, tend to take very long. President Macron’s supportive posture regarding the Paris Agreement is very encouraging and it is in reach of the country to take the necessary measures to meet its renewable energy targets, which should translate into future wind installations. According to the NREAP database, to meet the 2020 targets France will need 19 GW of

cumulative onshore wind capacity, meaning from 2017 to 2020 the country must install around 8 GW. In 2016, France had a record year with almost 1.6 GW of wind installed, the best year since 2010 when the country installed nearly 1.4 GW. The only country to surpass France in new installed capacity in 2016 in EU Graph 15: Estimated necessary

capacity for 2020 Target vs current capacity

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was Germany. In 2015 France ranked fourth with more than 1 GW of wind installed, again behind Germany but also U.K. and Poland. In our opinion the country will be able to keep these strong trends and will meet the 2020 EU target.

Romania

In Romania, the legislation in place contemplates the attribution of Green Certificates (GC) in addition to the pool price. Assets installed until 2013 receive 2 GC/MWh until 2017 and 1 GC/MWh after 2017 until completing 15 years. 1 of the GCs is restricted from trading until 2018. Assets installed before 2013 receive 1.5 GC/MWh until 2017 and 0.75 GC/MWh until completing 15 years.

Romania’s support of renewable energy started in 2008 with the approval of Law 220/2008 which introduced the incentives to renewable energy sources. This was a very successful program that captured large investments. According to

Romanian Wind Energy Association (RWEA) from 2008 to 2013, €5 billion were invested. However, it was at the expense of imputing the cost of GCs onto the final consumer. The law was amended in 2011, 2013, 2014 and, more recently, in 2017. The latest amendment brings significant changes to the GC support scheme.

Romania took longer than other countries in which EDPR operates to develop its wind industry. In 2009 it had less than 20 MW of cumulative capacity and only it was in 2012 that the country surpassed the 1 GW milestone. However, it also allowed Romania to benefit from the newest and most efficient technologies right from the start. After the amendment of the Law 220/2008 in 2011, wind

installation started to pick up pace. From 2011 to 2013, more than 2 GW were installed in a country with barely any track record.

The development of renewable energy sources came at a cost since industrials and households had to bear the burden of the GCs. In 2013, it is estimated that GCs represented almost half of the increase in the electricity tariff in Romania. Hence, the country had to cut back on its incentives. The most threatening measures during 2013 and 2014 were reducing the validity of GCs from 16 months to 12 months, temporary postponement from trading some GCs relative to projects put into operation before 2013. Moreover, the annual mandatory GC acquisition quota was initially established by the 220/2008 Law which set out a gradual increase each year from 8.3% in 2010 to 20% in 2020, but this was changed so that the quotas from 2014 to 2020 were set out by ANRE who would estimate the quota each year, which resulted in very significantly lower quotas than those anticipated by investors (2016 initial quota was 17%, but ANRE determined a 12.5% quota).

Graph 16: Electricity generation by source 2016

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Graph 19: Electricity generation by source 2016

The latest change comes in the form of the Emergency Governance Ordinance No. 24/2017, with the purpose of avoiding the collapse of the renewable energy industry but, at the same time, without overwhelming consumers with price increases. The most relevant measures are the change of the calculation of the GC acquisition quota which will be based on a fixed annual quantity of GCs that takes into account the years left until the end of the support scheme as well as the GCs postponed form trading during 2013 and 2014, and the final electricity consumption, the extension of the GCs validity and the extension of the recovery period for GCs postponed related to wind technology to 8 years (previously 3). We believe these changes are very much needed to revitalize the Romanian renewable energy sector. EDPR also suffered quite a bit due the past legislative issues, as the average selling price fell by 11% in 2013, 22% in 2014 and 23% in 2015, which we attribute mostly to the oversaturation of the GC market. In 2016, the average selling price was 45% lower than in 2012. The newest changes should help the market absorb more GCs, bring more long-term visibility to the support scheme and clear some of the uncertainties regarding it, which could even open opportunities for bilateral contracts for the sale of GCs.

In our opinion, the measures are still not enough to lead to significant new installations in Romania, but it should help the existing assets of EDPR in the medium and long-run.

Poland

Under the EU Renewable Energy Directive 2009/28EC, Poland has to achieve a target of 15% from renewable energy sources in gross final consumption of energy by 2020. It currently has a 12% share.

Electricity can be sold to the distributor at a regulated price or through bilateral contracts. On top of this, wind assets receive 1 Green Certificate (GC) per MWh that can be traded in the Polish Power Exchange or over-the-counter.

For installations after 2016, producers have to compete for Contracts for Difference in an auction system with a fixed, indexed strike price for 15 years. In the GC market, supply greatly outweighs demand since the obligation quota is too low. Although the GC market is also facing an oversupply, it is our opinion that the situation in Poland is different from the one in Romania because EDPR has been able to sign bilateral agreements that usually contemplate the sale of the GCs associated with the contract. When it is not possible, EDPR specifically tries to arrange contracts to sell the GCs which protects EDPR from

oversaturation of the GC market, although probably at a cost of a discount. In our opinion Poland is in a difficult position as it tries to meet the EU’s

Renewable Energy Source target for 2020 (that also contemplates reductions in

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CO2 emissions) by incentivising new installations without putting too much burden onto end-consumers and, at the same time, keep supporting its struggling coal industry.

Moreover, onshore wind as a source of renewable energy seems to be put in a secondary position versus other sources. Poland’s latest amendment to RES Act puts different technologies in the same bundle in auctions, meaning they

effectively compete with each other, and the government seems to favour more reliable technologies such as biomass over wind which, for example, generates a large portion of its power during the night when demand for energy is lower. In the most recent auction, on 27th_{July 2017, although the government did not}

disclose the information, it is estimated that the majority of the projects awarded were solar pv. On top of this, in 2016 Poland adopted a bill that makes it illegal to build turbines within essentially 2 km of other buildings or forests (not retroactive) which rules out a massive portion of the territory (99% according to windeurope), and increases the tax payable on existing turbines almost four times (although the amendment on the tax is open to double interpretations). According to windeurope, the wind industry in Poland generates 600 million zloty in tax revenue each year. The building restrictions can severely affect the salvage value of current installations that don’t verify the new requirements since repowering at the end of the lifetime of the farm with the intent of replacing older parts with more efficient ones that increase the operational performance of the turbines would not be allowed.

From 2009 to 2016, Poland’s cumulative wind installed capacity increased by more than seven-fold. In 2015, the country ranked second in the EU with 1266 MW of new installed wind capacity and in 2016 it ranked fourth with over 600 MW installed. In our opinion, we expect profitability and returns of the existing EDPR farms in Poland to remain fairly stable and without major disruptions, but we don’t expect any new installations given the new regulations. To meet the NREAP targets, Poland should have a cumulative onshore wind installed capacity of 5600 MW by 2020, which the country already achieved in 2016. If on one hand this is a testament to Poland’s past commitment to the development of wind, on the other, and coupled with the changes in legislation, it could mean a reduction of

incentives to support new installations. Therefore, our estimates don’t contemplate, in the short-run, any new installations in Poland.

Italy

In the Italian market, assets in operation before 2013 are under a pool price plus premium scheme for 15 years, with the premium calculated as 78% of the difference between €180/MWh and the previous year average market price. Assets after 2013 must go through competitive auctions to be awarded 20-year

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contracts with a defined price; effectively the electricity is sold in the market, but producers are paid the difference between the awarded price and the market by the Gestore dei Servizi Energetici (GSE) if the market price is below the

established in the auction.

On June 2016, Italy retired its GC trading regime and moved to a tariff based remuneration scheme linked to the market price. Producers that hold GCs exchange them according to the premium calculation.

On the December 2016 tender, GSE awarded 800 MW of onshore wind farms that attracted more than 2 GW proposals. EDPR won a 20-year PPA for 6 onshore wind farms for a total of 127 MW with a price set at €66/MWh, roughly 40% below the reference price. According to our estimates, this represents a 54% premium versus the 2016 pool price and 29% versus the pool price in 2017, still likely to decrease by year end to 19% as pool prices increase. This deal reiterates EDPR’s ability to guarantee long term PPAs (EDPR’s share on this auction was almost 16%) in Italy with an interesting premium over the market price.

Every year since 2010 except 2016, Italy has been above the yearly estimated necessary wind capacity to achieve the European targets. We don’t consider 2016 to be a setback given the country’s track record. Since Italy still needs to install around 3GW until 2020, we believe this could lead to new installations by EDPR in the country.

Belgium

Belgium is the European country with less revenues and installed capacity. The country’s target of energy from renewable sources in gross final consumption of energy in 2020 is 13%. In 2015, the share was 15% according to the European Commission.

Wind assets are remunerated according to a market price plus a GC proportional to the green electricity produced and the rate of CO2 avoided which can be sold in the GC market or to the Wallonia Energy Authority for a minimum price of €64/GC and a maximum of €100/GC. Each region has its own GC system with different quotas, fines and thresholds for granting GCs, but EDPR’s installations are exclusively in Wallonia. The renewable quota in Wallonia was fixed at 30.4% in 2016 and is expected to increase to 37.9% in 2020. Additionally, there is an option to negotiate long-term PPAs.

In our opinion Belgium has one of the healthiest GCs market of all European countries where EDPR operates. One major factor contributing for this is that there is a GC system for different types of renewable energy technologies.

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Graph 22: Investment in renewables in Brazil

Graph 23: Renewable energy mix by source 2016

Graph 24: GDP Growth

Moreover, the Wallonian authorities have been able to maintain a stable and well-functioning support scheme. The fact that Belgium is, according to our estimates, already surpassed the wind onshore capacity needed by 2020 shows the strong commitment of the country with renewable energies, especially wind. Hence, in our opinion, there is room for EDPR to increase its asset base in Belgium.

Brazil

Regarding Brazil, the capacity installed under the PROINFA program was awarded long-term PPAs but the first stage of the program closed down in December 2011 and the second stage is uncertain. Other wind assets are remunerated according to 20-year PPAs awarded in competitive auctions with prices indexed to Brazilian inflation.

The country has a natural gift of abundant renewable energy resources, which allows for load factors consistently above 30% for wind assets. Brazil went through a very severe recession recently that caused a decrease in electricity demand and led the government to cancel some renewable energy auctions, but the country is showing some signs of improvement as shown by the IMF raising the GDP growth forecast for 2017 from 0.3% to 0.7%.

Brazil has shown the ability to capture investment in renewable energy. From 2007 to 2010 around $39.5 billion were invested in renewable energy in the country, and between 2011 and 2014 it was $28.8 billion. Despite the economic recent economic recession that has limited the government’s ability to support renewable energy, investment trends remained relatively strong. The year of 2013 was especially tough with less than $4 billion invested, the lowest value since 2006 and a decrease of more than 45% versus 2012, but it has quickly rebounded to $7.6 billion in 2014. Meanwhile, wind onshore installations kept a strong performance with a 38% increase in cumulative installed capacity in 2013, 73% in 2014, 46% in 2015 and 23% in 2016.

Wind energy is now an established source of energy in the country. In 2006, onshore wind represented less than 1% of the renewable energy mix (in terms of cumulative installed capacity). This percentage has risen to 1.5% in 2011 and by 2016 it reached 8.8%. Onshore wind recorded a CAGR 2006-2016 of 46%, well above all other renewable energy sources such as bioenergy with 14%, medium hydropower with 12% and large hydropower with 3%.

As matter of fact, its competitiveness allowed wind to be removed from the renewable energy auction and now competes in auctions with hydro and technologies based on fossil fuels.

Source: IRENA

Source: IRENA based on Ministry Of Mines And Energy, GWEC, thewindpower.net

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We would not be surprised if Brazil turns out to be an important market in the future in terms of installations for EDPR, but we still need to see signs of improvement of the political and economic situations before we commit to estimating new installations beyond those announced by the company.

Mexico

Recently Mexico has been cementing the de-regulation of its energy sector which opens up a lot of opportunities for renewable energy companies. It also

established a Law for the Use of Renewable Energies and Financing of the Energy Transition with the goal of generating 35% of electricity from renewable sources by 2024. The regulation scheme is based on Bilateral Electricity Supply Agreements for 25 years under self-supply regime which allows for the

establishment of a fixed price given the uncertainty of how the de-regulated market will work.

The evolution of the electricity market is not quite clear yet, as the only

development in recent times was a 6 to 15 months extension of the self-supply regime originally available only through December 2016, therefore we assume no future pipeline for Mexico at the moment.

Levelized Cost of Electricity (LCOE)

The LCOE is the main measure for comparing the competitiveness of different technologies as it evaluates the discounted value of a theoretical project for each type of generation.

The cost of wind has been steadily decreasing over the years mostly as a result of lower CAPEX requirements, lower O&M costs and higher load factors due to more efficient turbines.

In some regions the cost of a wind system to enter into operation in 2019 is already competitive without subsidies or incentives versus other technologies, most importantly versus natural gas combined cycle plants. For plants to be built in 2022 it is expected that the unsubsidized cost of wind will be reduced by more than 6%, although combined cycle gas plants costs are expected to be reduced by more than 15% making it the cheapest technology.

Graphs 25 and 26 display the effect of the incentives on wind and solar installations. Since these values are based on U.S. soil installations, these renewable energy technologies are eligible to receive tax credits. These incentives were very important in the beginning to boost the development of renewables in the U.S. and, according to EIA, tax credits for a wind farm entering Graph 25: LCOE ($/MWh) 2019 CoD Plant Graph 26: LCOE ($/MWh) 2022 CoD Plant Source: EIA Source: EIA

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in operation in 2019 reduce the cost by 34% versus an unsubsidized wind farm. For 2022, this difference is expected to shrink to 21% as a result of the lower value of the tax credits. However, as far as we know, for EDPR the difference may surpass the 21% because of the safe harbour clause.

Yet, it is important to be aware of the limitations of LCOE when comparing different technologies, since different factors have different impacts on each type of plant. For instance, wind and solar pv have relatively low O&M costs so capital expenditures and load factors are expected to have the most impact on LCOE; on the contrary, for gas plants the variable cost component of the materials required is much more important and have a much more significant effect on LCOE. Different technologies also operate at different times, with gas running typically for peak load while wind doesn’t necessarily follow a duty cycle.

Furthermore, the actual investment decisions to build a plant or which technology to build are affected by many other factors not considered by LCOE such as the location itself and the energy mix of that region. Also, dispatchable technologies such as gas tend to have more value to the electricity system than wind due to its intermittent nature.

Hence, although it is very difficult in practice to properly compare gas and wind technologies, based on the historical trends we still believe in further reductions of wind costs as it tends towards being cost competitive with gas fired

technology.

Regarding LCOE, it is estimated that it could decrease by 26% by 2025, which in line with the long-run rate learning rate for onshore wind of a 12% cost reduction for every doubling of cumulative installed capacity estimated by IRENA. The most important drivers are the capacity factor, the total installed costs (mostly towers, turbines and wind farm development) and the turbine reliability and best practice O&M, which are expected to represent 49%, 34% and 17% of the total projected reduction in onshore wind LCOE, respectively.

Wind Turbines

Over the past decades Turbine Manufacturers have pushed for very significant technological improvements. Nameplate Capacity, rotor diameter and hub height are three of the most important drivers for Load Factors and have shown

tremendous progress.

Nameplate Capacity, which is the full rated capacity output of a wind turbine, increased around 25% in 2015 versus 2006 levels. The average rotor diameter is even more impressive with a 29% increase, while hub height has remained steadier with an increase of only 8%.

Graph 27: Onshore wind LCOE potential reduction by source

Graph 28: Turbine nameplate capacity, hub height and rotor diameter

Graph 29: Trends in turbine nameplate

Source: IRENA, MakeConsulting

Source: U.S. Department Of Energy

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Graph 30: Trends in rotor diameter

Graph 31: Trends in hub height

Graph 32: Turbine

manufacturers global market shares 2016

From 2004 to 2014 we’ve seen a significant increase in the penetration of 1.5 to 2 MW turbines. From 2011 onwards, installations of multi MW turbines (2 MW and above) start to pick up pace and in 2015 accounted almost 60%, despite weaker performance in 2012 and 2013.

In more recent years rotor diameter progress has by far outpaced the other two factors and has not yet shown signs of slowing down. In 2000 and 2001, around 85% of turbines had a rotor diameter of less than 70 meters. It took 2 years to push this percentage to below 50% mostly driven by increases in 70 to 80 meters rotor diameters and another 6 years (2004-2009) to reach below 10%.

Meanwhile, it only took 3 years for turbines with 70 to 80 meters rotor diameters to be totally displaced first by 80 to 90 meters class and then mainly by 100 to 110 meters. In 2014 and 2015, we’ve seen a clearer trend in the increase of the penetration of rotor diameters above 110 meters with around 5% and 20% of installed turbines featuring these dimensions, respectively.

Hub height has been stable in recent years. The market is widely dominated by 80 to 90 meters towers since 2006. In 2014 and 2015, 90 to 100 meters towers start penetrating the market. Regarding installation towers taller than 110 meters, after a promising trend in 2011 and 2012 they seem to have faded in detriment of 80 to 90 meters towers.

These trends of faster growth in rotor diameter and hub height than in nameplate capacity (but mostly driven by the recent rotor diameter performance) led to a decrease in the ratio of capacity to area swept by the rotor blades which has driven capacity factors upwards for wind turbines operating at similar wind speeds7_{. Data from the IEA points towards an improvement in load factors of}

15pp from 2003 to 2013 for wind turbines at moderate wind speeds (8 m/s and 50 meters height).

At a manufacturing level there are economies of scale that can drive costs downwards. There may be opportunities for M&A, such as the Siemens Gamesa merger in 2016, which would consolidate a sector in which individual turbine manufacturers are small relative to the global market. In 2016, the top 10

manufacturers accounted for 75% of the market with Vestas representing around 16% and only 3 of the manufacturers installed a total capacity of over 6 GW. In most recent years we have seen a decrease in average selling price of turbines as a result of competition between turbine manufacturers but also pressure put onto them by renewable energy developers due to gradually lower support schemes. According to Bloomberg New Energy Finance the price of wind turbines to be delivered in the U.S. in the second half of 2017 dropped to $0.83

7_{World Energy Council: World Energy Resources – Wind 2016 Report}

Source: U.S. Department Of Energy

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Graph 33: Wind turbine price index

million per MW which is below the global average price of $0.99 million. The sharper decrease in price in the U.S. is mostly due to the rush of renewable energy developers to qualify as many projects as possible for 100% PTCs regime, which led to a price competition between turbine manufacturers. From 2008 to 2017 it is estimated a -10% CAGR for the U.S. and -5% for global wind turbine prices.

Risks Analysis

In the following section we outline the risks that we consider to be the most relevant for EDPR.

Market Prices

Even though in the short-run EDPR is protected from abrupt decreases in market prices through the several renewable energy incentive schemes, in the medium to long run we expect this exposure to market dynamics to increase. The extent will depend mostly in the company’s ability to sign PPAs.

Regulatory Risk

Throughout the report he had the opportunity to highlight some dynamics in certain countries regarding changes in regulations. EDPR is exposed to the risk of having previously agreed contracts changed as a unilateral decision. Whether these changes are justified by reducing the burden on end-consumers and perceived as fair or straight violation of previously signed agreements by states is beyond control of the company and should this risk materialize, even though processes of litigation may arise, the state’s decision will most likely hold in some countries.

Competition

We have reached an age in the maturity of wind energy where it directly competes with other energy sources such as hydro, nuclear or coal. It doesn’t suffice to be more efficient than other renewable energy companies anymore since, in some countries, the company must face competition of more “tradition” technologies and we believe this trend will be extended to the majority of the regions in the future.

Counterparty Risk

We reckon that EDPR’s ability to sign PPAs is overall positive for all reasons previously mentioned but it still exposes the company to default risk by the other party. The fact that PPAs are agreed for a very long period locks the company to

Source: EIA

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the risk that at some point the counterparty will not be able to meet its payment obligations for reasons completely outside the control of EDPR.

Operational Risk

In our opinion the operational risk is worth pointing out especially given the company’s strategy to internalize high value-added activities. If the company doesn’t internalize any processes, it is exposed to independent service providers and original equipment manufacturers (OEM); in the case of highly specialized parts, if the OEM goes bankrupt getting the necessary material for maintenance may prove very difficult. If the company insources activities, it is exposed to theoretically not having the same expertise in dealing with components made by other companies which may also impact operational performance.

Another risk inherent to the business of EDPR is related to the production of energy, since wind is volatile. This means that the company is exposed to generating less electricity due to weather conditions. It is also inherent to the business that it sells its energy from wind assets at a lower price since wind blows stronger during the night when demand is lower, while the contrary happens for solar assets.

Suppliers And Commodity Prices

The company is exposed to the risk of a sudden increase in the materials necessary for manufacturing wind turbines such as steel, aluminium or copper, which could undermine the profitability of projects through a sharp increase in CAPEX requirements. According to our estimates, a 1000bps decrease in CAPEX would lead to a 10% to 12% increase in our Fair Value.

Exchange Rate Risk

As the company expands to other countries, namely emerging economies, even though in the short-run it has contracts defined in dollars or indexed to inflation, in the long-run we expect these to be exposed to local currency which opens up a possibility for some exchange rate risk.

Financing Risk

EDPR finances itself mainly through the parent EDP and by signing tax equity partnerships. Since EDP fully consolidates EDPR, the leverage of the subsidiary matters for the parent; this means that EDPR may be limited on the leverage it can take, especially in the case of an increase in interest rates.

Moreover, the recent developments of tax equity in the U.S. may affect the company’s ability to pursue a self-funding model.