The EU ETS is a key pillar of European climate policy since its implementation in 2005. The system works by putting a limit on overall emissions from covered installations (power sector and energy intensive industry), which is reduced each year. Within this limit, companies can buy and sell emission allowances as needed.

In November 2017, the European Parliament and Council of the European Union reached a provisional agreement to revise the EU ETS for the period 2021-2030 (“Phase IV”). This revision is aimed at putting the EU on track to achieving a significant part of its commitment under the Paris Agreement to reduce greenhouse gas emissions by at least 40% by 2030.

The key reforms agreed by the Parliament and Council included measures to enhance the EU ETS resilience and speed up emissions reductions along with additional safeguards to protect the EU industry against the risk of carbon leakage.

Formal agreement and endorsement by both co-legislators is expected for early 2018. Most analysts expect that these reforms will tighten the market surplus, pointed out as one of the main reasons for a depressed carbon price over the last years.


In November 2016, the European Commission (EC) presented a new package of measures with the goal of providing a stable legislative framework to facilitate the clean energy transition. This regulatory package aims to create a more competitive and sustainable EU energy sector, while compatible with the Paris Agreement commitments.

The package consists of eight legislative proposals, including a new “Renewable Energy Directive”, the “New Market Design Initiative” and the “Energy Union Governance Regulation” and, together with four non-legislative documents and nine other reports and initiatives.

In 2017, considerable progress was made in different fields that would impact the future of renewables in Europe.

Concerning the Renewables Directive and the Governance regulation, the European Parliament, who advocates for a more ambitious package of reforms, voted in January 2018 for a for a 35% EU-wide renewable energy target for 2030, increasing the overall ambition of renewables deployment in Europe when comparing with the 27% proposed by the European Commission that reflects the conclusions of the Council of the European Union of October 2014 “2030 Climate and Energy Policy Framework. Although the final target remains to be agreed, it will likely be binding only at EU-level. However, on the positive side, Member States (MS) will be required to submit “National Plans” in which they would need to set self-defined renewable energy targets. At this regard, the Energy Council also agreed to set three indicative intermediate benchmarks in the next decade.

Some other recent positive developments have been welcomed by the renewable industry. On the one side, EU MS agreed to (i) give three years’ visibility on the volume and budget of public support schemes for renewables and (ii) to avoid any retroactive measure affecting renewable support. The Energy Council also agreed to allow technology-specific auctions. Finally, MS will be required to remove barriers to Corporate Power Purchase Agreements.

Renewables are also key to the Electricity Market Design Initiative, with the Energy Council agreeing that renewables should have full and equal access to balancing and ancillary markets, while maintaining priority of dispatch for existing renewables’ facilities (new facilities would be subject to a system of curtailment and compensation). The European Parliament will vote its amendment during the first quarter of 2018. Trilogue negotiations between the institutions (EC, Council and Parliament) in view of final agreements are expected to occur all year round.


This chapter describes the most relevant recent regulatory developments in the European-Brazilian countries where EDPR is present (for additional information, please refer to Note 01 of EDPR Consolidated Annual Accounts).


Since 2016, in line with the European regulation, all the new renewable capacity in Spain is allocated through auctions. The regulatory scheme is designed to provide a similar remuneration scheme to the one that applies to previous installations (ruled by RD 413/2014). Following this framework, tender participants are requested to bid discounts to the standard value of the “initial investment” parameter which determines the “investment premium”, that would eventually be awarded.

In 2017, two auctions were held. The first one was in May and unlike previous auctions, it was technology neutral as different renewable technologies were allowed to compete. Nearly all the capacity was awarded to wind projects (2,979 MW out of 3,000 MW) and the remaining capacity was awarded to solar photovoltaic (PV) installations and “other technologies” representing 1 MW and 20 MW, respectively. The auction was very competitive and oversubscribed with all the wining participants bidding the maximum discount. Following the outcome of this tender, the Spanish government decided to launch an additional tender for a maximum of 3 GW, which was held in July and opened to wind and solar PV exclusively. The royal decree ruling the tender (RD 650/2017) included the possibility to increase the allocated capacity to all capacity bidding the same discount, provided it would not create an over cost to the system. Following this clause, all the capacity that offered the maximum allowed discount was awarded. Overall, 5,037 MW were awarded with solar PV power generators being the biggest winners with 3,909 MW compared to 1,120 MW from wind.

In November, the European Commission (through the Directorate-General for Competition) endorsed the Spanish support scheme for renewables, the RD 413/2014, which regulates the generation of electricity from renewable energy, cogeneration and waste. As such, the EU Commission confirmed that the Spanish support scheme for renewables is in line with the 2014 European State Aid Guidelines.


In August of 2017, the Portuguese government approved the Order 7087/2017 tightening the authorization process for new repowering and additional capacity, introducing in particular, the obligation for the Directorate-General for Geology and Energy to consult the electricity regulator that will have to assess its impact to the electricity system. The amendments to the decree ruling the repowering authorization process are still pending to be published.


A new contract-for-difference (CfD) scheme was released in December 2016, although existing projects still benefiting from the former feed-in tariff scheme. The new scheme obtained clearance from the European Commission, who confirmed that it was in line with the European “Guidelines on State aid for environmental protection and energy 2014- 2020”. According to this new scheme, wind farms having requested a PPA in 2016 would receive a 15-year CfD, being the strike price and the terms of the tariff very similar to the previous feed-in tariff. From 2017 onwards, wind farms of more than 6 wind turbines (and more than 3 MW per turbine) need to participate in competitive tenders in order to obtain a 20-year CfD, the first tender was held in November 2017. The calendar of auctions until 2020 has been announced by the regulator and up to 3 GW of wind are expected to be tendered in this period, with two tenders of 500 MW each year. On the other hand, wind farms with a maximum of 6 wind turbines (and a maximum of 3 MW per turbine) do not need to participate in tenders. Wind farms of these characteristics having requested a PPA in 2017 are entitled for a 20-year CfD with a strike price ranging between €72/MWh and €74/MWh, depending on rotor size.

In December 2016, France launched a call for the third offshore wind tender, expected to be held in 2018, for a 400- 600 MW project in the coast of Dunkirk.


On November 2017, the Strategia Energetica Nazionale (National Energy Strategy), known by the acronym SEN, was presented after several months of public consultation. The SEN announced the complete phase-out of coal power generation by 2025 (five years ahead in comparison with the previous announcement), highlighting the renewables’ role and calling for renewable energy to reach a 28% of energy consumption in 2030 from 17.5% in 2015. This strategy also stated that electricity from renewable sources should account for 55% in 2030, considerably above the 33.5% figure in 2015. Regarding the large-scale renewables’ support, competitive auctions for fixed tariffs seems to remain in place through 2020 and long-term PPAs taking over after that.


In August 2017 a new methodology to calculate the substitution fee was approved. According to the new formula, the substitution fee will be calculated every year as 125% of the previous year average market price of the Green Certificate (“GC”), capped at 300 PLN. This new methodology implies a reduction of the substitution fee, previously set at 300 PLN, in particular due to current low prices of GCs.

Also in August, a new ordinance setting the new GC quotas for 2018 and 2019, was approved with the new quotas being defined at 17.5% for 2018 and 18.5% for 2019. In December the European Commission (through the Directorate- General for Competition) endorsed the Polish support scheme for renewables (2015/16 RES Act).


In March 2017, the Government Emergency Ordinance 24/2017 (the so-called “EGO 24/2017”) amending Law 220/2008 was published. The main features of this ordinance are: (i) extension of the GC scheme until 2031 and of the GC validity until March 2032; (ii) approval of a new methodology for the GC quota calculation; (iii) removal of the indexation of the GC parameters (GC floor would remain fixed at €29.4 and GC cap would not only lose indexation but also be reduced to €35); (iv) extension of the GC recovery for wind energy from 2018 to 2025 (included) and extension of the GC postponement for solar PV until the end of 2024 and recovery from 2025 to 2030 (included) and (v) creation of an anonymous centralized platform to trade GC (from September 2017 GCs could only be traded there) and also of an anonymous market to sell energy together with GCs.


In September, the Department for Business, Energy & Industrial Strategy (DBEIS) and National Grid, published the results of the second CfD allocation round. In this round, a total of 3.3 GW of capacity awarded across eleven projects, including three wind offshore projects. EDPR’s Moray East offshore project was awarded a 15-year CfD for the delivery of 950 MW wind generation at £57.50/MWh (2012 tariff-based), to be delivered starting in 2022-2023.

In October, DBEIS announced that an amount of £557 million would be available for Pot 2 CfD auctions for less established technologies, with the next auction taking place in spring 2019.


Two reverse auctions where wind projects could participate were held in December 2017. In the first reverse auction, 891 MW of projects secured contracts: 791 MW were solar PV projects and only 64 MW were wind. The second auction had 3.8 GW of projects awarded, including 1.4 GW of new wind power to start operations in January 2023 at an average R$98.62/MWh, a record low price for this technology in the country. EDPR secured 219 MW, for two wind projects for a 20-year period at an initial price of R$99 and R$97/MWh (indexed to the Brazilian inflation).


Historically, the typical framework for wind and solar developments in the US has been decentralized, with no national feed-in tariff, resulting in a combination of three key top line drivers:

  •  PTCs: Production Tax Credits are the dominant wind incentives in the US and represent an extra source of revenue per unit of electricity generated ($24/MWh in 2017), over the first 10 years of the asset’s life.
  •  ITCs: Investment Tax Credits equals to 30% of the initial capex and are the primary solar incentives.
  •  PPAs: Long-term, bilateral Power Purchase Agreements by which a renewable developer can sell its output to another company at a fixed price, usually adjusted for an agreed escalator.

In addition, many states have passed legislation, mainly in the form of Renewable Portfolio Standards (RPS), that require utilities to purchase a certain percentage of their energy supply from renewable sources, setting penalties to those that do not accomplish. Typically, states use Renewable Energy Credits (RECs) as the compliance mechanism. Utilities or other subject entities are required to procure enough RECs to meet their obligations under the RPS. Utilities can choose to invest directly in renewable generation assets and generate a REC for each unit of renewable energy produced or, alternatively, can purchase RECs produced by other renewable generators either through long-term bilateral contracts or in the secondary market. As a result, many utilities set up auction systems to seek long-term power purchase agreements with renewable energy generators by which they procure renewable energy and RECs.

The relevant recent regulatory developments in North America are below described (for additional information, please refer to Note 01 of EDPR Consolidated Annual Accounts).


On December 2015, the US Congress approved the “Consolidated Appropriations Act, 2016” that included an extension of the PTC for wind (including the possibility of a 30% ITC instead of PTC) and an extension of the ITC for solar. As part of the extensions, Congress also introduced a phase out of the credits. Wind projects that start construction in 2020 or later will not be eligible for the PTC or ITC and solar projects placed in service after 2023 will qualify for just 10% ITC. On May 2016, the US Internal Revenue Service (IRS) issued guidance that wind farms have 4 years from their start of construction to be placed in service and qualify for the PTC. As a result, projects that start construction prior to year- end 2019 and are placed in service prior to year-end 2023 will be eligible for the PTC. The IRS ruling also includes a provision that allows developers to secure the PTC if 5% of a project’s capital components by dollar value are safe harbored in a given year and construction is completed within 4 years. Thus, if a developer safe harbors 5% of project Capex in 2016 for a given project, the project will qualify for the 100% PTC if construction is completed by year-end 2020. The graphic below depicts the phase-out calendar:

Regarding RPS, some states have upgraded their targets in 2015-2017; California and New York both upgraded their RPS standards to target 50% renewables by 2030, Oregon upgraded their RPS to 50% by 2040, Vermont enacted an RPS of 75% by 2032, Michigan upgraded their RPS to 15% by 2021, the District of Columbia increased and extended its RPS to 50% by 2032, Maryland increased and accelerated its RPS to 25% by 2020 and Rhode Island increased and extended its RPS to 38.5% by 2035. Illinois supplemented its existing RPS standard by passing an energy bill to require utilities to source at least 4 TWh of new wind and 4 TWh of new solar by 2030. Massachusetts also supplemented its existing RPS by creating requirements for offshore wind and solar procurement. RPS obligations as a percent of state retail consumption (as of July 2017) are shown in the table below. Some states have separate goals for different types of utilities such as investor-owned utilities (IOUs), cooperatives (co-ops) or municipal power companies (munis). Other states like Iowa and Texas, have set targets for installed capacity, rather than for a percentage of sales.

Another regulatory factor that could affect demand for renewable energy is national legislation or rule-making regarding carbon emissions. On August 2015, the Environmental Protection Agency (EPA) announced the Clean Power Plan (CPP), a rule to cut carbon pollution from existing power plants. On February 2016, the Supreme Court stayed implementation of the CPP pending judicial review and on October 2017, the EPA, led by Scott Pruitt, announced that it would sign a proposed rule to repeal the CPP. On December 2017, Scott Pruitt announced that the EPA will introduce a replacement rule for the CPP. It is otherwise unclear how the EPA will proceed. On a state level, some states already participate in carbon reduction programs. For example, California is a member of a carbon allowance market along with Quebec and Ontario. Meanwhile, some states in the eastern US (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont) are members of the Regional Greenhouse Gas Initiative which seeks to reduce carbon emissions from the power sector.

In 2017, one of the most notable new legislation was the “Tax Cuts and Jobs Act of 2017” which, among many other changes, reduced the maximum corporate tax rate from 35% to 21% and introduced the Base Erosion Anti-Abuse Tax (“BEAT”). The final impacts of these changes are still uncertain on the renewable energy market. For example, the decreased corporate tax rate is projected to boost after-tax earnings from new renewable projects, but it could also reduce the market demand for the tax credits produced by new renewable energy assets. The “BEAT” provision is a tax intended to prevent companies from engaging in “earnings stripping”, a method by which large, foreign-controlled companies loan funds to their U.S. subsidiaries and then deduct the interest payments, thus reducing their U.S. tax liability. The final version of the tax reform bill stated that companies could offset up to 80% of their “BEAT” liability through the PTC/ITC value.

Another notable federal-level development spanning 2017 into 2018 was the petition for an eventual announcement of a tariff on imported crystalline silicon photovoltaic (CSPV) modules. In late 2017, after considering a petition by Suniva and SolarWorld Americas, the U.S. International Trade Commission announced a set of recommendations for tariffs to President Trump. In January 2018, President Trump announced a 30% tariff beginning in 2018 and decreasing by 5% per year, exempting the first 2.5 GW of imports in each year. As a result, the cost of some modules might increase.


Growth in the US is motivated by several forces, including primarily the planned coal capacity retirements, RPS compliance in several states and demand from commercial and industrial entities.


New Canadian renewable supply is expected to be largely determined by provincial procurements. While some provinces already produce much of their electricity through renewable sources (largely due to hydro power), Alberta, Saskatchewan and Ontario have taken steps to increase renewable energy production. Alberta, where EDPR was awarded a long-term Renewable Energy Support Agreement for 248 MW of wind onshore in the 2017 auction, is pursuing a Renewable Energy Program in order to develop 5 GW of renewable electricity generation capacity by 2030. SaskPower, the principal electric utility of Saskatchewan, has a target of 50% renewable generation capacity by 2030. Ontario has conducted multiple Large Renewable Procurements in 2014-2016.


Mexico is redesigning its energy sector beginning with the constitutional amendment in 2013 and ending with implementation of the wholesale electricity market, long-term supply auctions, and financial transmission rights. Mexico implementation by end of 2018. The reforms bring about the end of state-owned vertically-integrated monopolies and has conducted three long-term supply auctions in order to procure new renewable electricity.