Spain Ends Subsidies on Renewables

Training Wheels Come Off As Industry Matures

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Posted: Wednesday, February 14, 2018 8:00 am

Remuneration for new renewables is changing dramatically in Spain with the end to subsidies and the exposure of the sector to market pricing.

It used to be that the huge investment required to develop renewable power plants was not financially feasible if the remuneration was limited to standard power prices, which created the rationales for subsidies. Today, the drop in production costs across the supply chain and growing production scale have some governments thinking that renewables are now competitive without subsidies. As a result, they are now structuring auctions with a reduction of the subsidies.

Spain has taken this approach one step further and has awarded 8.7 GW of new renewables in 2016 and 2017 that may not receive any government subsidies. Yet, after the auction, bankers and advisers are scratching their heads about the best approach to finance what is seen as a new era of renewables.

Regulatory Missteps Still Weigh On the Sector

Renewable energy has been the No. 1 subject of debate in the Spanish energy market for 20 years now. Spain's bet on clean energy through a generous endorsement program led to a massive investment in renewable power on a much wider scale than the government had expected. As a result, renewable subsidies drove increasingly high regulated costs that could not be matched by the corresponding increase in fees paid by energy consumers.

The consequence was a large and growing "tariff deficit" that crushed the sustainability of the electricity system. From 2008 until 2012, the government made a series of retroactive changes to the renewable remunerations. Since these measures were not sufficient to contain the electricity tariff deficit, in July 2013 a full revision of the remuneration was announced.

For Spanish renewables, in particular, the feed-in-tariff system was replaced with a standardized regulated asset-based (RAB) system. Under this scheme, each plant has recognized asset value that is remunerated by the government to ensure a "reasonable rate of return" is achieved. The reasonable rate of return is the 10-year government bond yield plus a spread, reviewed every six years. The spread is currently 300 basis points for the first regulatory period, implying a 7.5 percent financial remuneration. Operating assumptions are defined by the government and based on the standard asset (assets with the same type of technology and year of construction).

The retroactive feed-in tariff cuts had significant effect on the profitability of renewables, especially for solar photovoltaic (PV) facilities and ultimately on investor appetite.

Finally, at the end of 2015, Spain's power sector posted its first electricity tariff surplus in 14 years.

Calculating Future Subsidies Proves Difficult

There were no additional auctions of renewables from 2012 until January 2016. That month saw the first auction out of the three that have taken place over the last two years. The three auctions were inverse auctions where developers bid at a discount over the recognized Regulated Asset Base (RAB). Based on the RAB resulting from the discount, the newly built renewable assets would then have the right to be remunerated up to the reasonable rate of return (RRR) within the next 25 years. This mechanism would be the result of the government providing subsidies only if the power prices (the pool prices) and operation assumptions are not enough for the assets to reach the RRR. In the three auctions, all of the bids were awarded at the maximum discount rate allowed (see table 1).

In January 2016, the government awarded 0.5 GW to wind projects based on a RAB discount of 100 percent. This will result in no additional subsidies to these projects under any power price scenarios. In addition, 0.2 GW was awarded to biomass.

In May 2017, the government launched the second auction, this time to procure 3 GW. With wind being the cheapest option for new power generation, wind projects picked up nearly all of the auctioned capacity. After the success of the second auction, Spain launched another auction for more renewable energy in July 2017, initially for 3 GW with the option for the government to increase it up to 5 GW. At the third auction, the spread between solar and wind projects over the maximum reduction on the RAB was increased to maintain competitiveness among technologies. The government finally awarded 5 GW, mostly to photovoltaic projects. In these last two auctions, the projects were awarded at a maximum discount rate of between 60 and 80 percent, reducing the likelihood for these assets to ever receive any subsidies.

A Dynamic Floor Price Only Applicable Under Certain Scenarios

The calculation on the second and third auctions is not so simple. The discount on the RAB was 63.4 percent on the second auction, and on the third auction 87.1 percent for wind projects and 69.9 percent for photovoltaic projects. Our understanding is that after applying those discounts to the RAB, there will be a theoretical and dynamic pool price floor guaranteed by the government to ensure the assets receive the RRR. Based on today's RRR we estimate the pool price floor slightly below €40/MWh for the second auction and €28-€32/MWh for the third auction, depending on the project. This is far from the €42/MWh of forward price contracts, which is also our base for 2018 and 2019.

We believe it is key to understand that the mechanism described above guarantees a RRR over the discounted RAB and not a specific level of remuneration. For example, this means that, if the pool prices allow power plants to achieve RRR in a shorter period of time, the theoretical remuneration implicit on the RAB would expire and leave the debt fully exposed to merchant risk and without any right to receive subsidies from the government. In addition, other variables, which are defined by the government for the RAB calculation, could affect the dynamic pool price floor including recognized operating expenses or the number of hours of production. Hence, any implicit pool floor will change on an ongoing basis, and will be specific to the asset.

In our experience, developers in other countries such as the U.S. have mitigated the exposure to pool prices by entering into long-term power purchase agreements (PPAs) with strong counterparties. We consider it likely that a PPA market (or similar mechanisms) will develop in Spain in the long term. The Spanish renewables market could also develop alternatives such as derivatives, hedging the differences between a negotiated price and the pool price. For example, photovoltaic company Talasol (subsidiary of Ellomay Capital Ltd.) in January 2018 signed a power financial hedge for 3,500-3,700 GWh, locking in prices for the next 10 years.

Who Will Be Able to Succeed?

The radical shift from secured and stable governmental remuneration to daily power prices massively increases market exposure. This adds more complexity for projects financed through project finance structures, given their long-term debt tenors and generally high leverage. We see clear signs of volatility and unpredictability in the evolution of the pool price in Spain over the past four years (see chart 2).

This kind of financing relies mainly on fully amortizing long-term debt out to usually about 20 years for renewables, depending on the technology. If the market decides to debt finance this new type of asset – renewables with generation to be sold at pool prices – reliable long-term power price forecasts will be fundamental. Long-term power prices have proven challenging to forecast over the long term due to their dependency to multiple elements: macroeconomic variables, energy consumption, production capacity, interconnection between markets, trends in population, energy mix and public policies – including the government's approach to nuclear and carbon.

This trend in renewables with low or no subsidy and the potential financing challenges are not specific to Spain. We have seen other examples in the latest bids for offshore projects: In Germany, the April 2017 results of the 1.55 GW auction showed bids at zero, meaning no subsidies, by EnBW and Ørsted. In the U.K., the U.K. contracts for difference auction on Sept. 11, 2017, saw a drop in offered tariff prices of 50 percent on average since the last competitive auction in 2015. In the Netherlands the bids are to be awarded free of subsidies. However, Spain is the first European country that may test this financing on a bigger scale.

The new Spanish power plants will need to be in operation before January 2020. Failure to achieve the deadline would entitle the government to trigger the guarantees provided on the auction, which we understand could be around €496 million jointly for the three auctions. This is specially challenging for sponsors of awarded projects that do not yet have the land ready to begin construction (for example permits, resource measurements equipment, ownership titles), as we understand some bidders did not even own the land when the projects were awarded. Overall, we think bidders will need both a strong balance sheet and experience to meet the deadline.

The Corporate Rush to Go Green

The recent renewables auction in Spain saw as protagonists Gas Natural SDG SA, with 667 MW awarded in the second auction and 250 MW in the third, and Endesa S.A., with 540 MW awarded in the second auction and 339 MW in the third. Contrary to our expectations, world-leading renewable players such as Iberdrola S.A. and EDP -Energias de Portugal S.A., did not take part or had a marginal role (see table 2). In our view, this may indicate a more aggressive investment strategy into renewable assets for those integrated energy companies whose generation portfolio is less "green" than peers and for which other industrial considerations drove the investment decisions.

• Gas Natural, among European integrated utilities, stands out given the relatively low contribution of renewable assets to its current generation portfolio (see chart 3). Specifically, in 2016 the company had 12.7 GW of generation capacity in Spain, with 7 GW coming from combined cycle power plants, 2 GW from hydro, 0.6 from nuclear, and only 1.1 GW from pure renewable assets.

• Endesa is part of the larger Enel SpA group. Endesa in 2016 had 22.7 GW of net installed capacity, with 4.7 GW coming from hydro assets, 7.6 GW from conventional thermal, 3.3 GW from nuclear, 5.4 GW from combined cycle gas turbines, and only 1.7 GW from renewables and cogeneration.

• Cobra, the industrial and engineering subsidiary of ACS, was awarded 1.5 GW of photovoltaics in the third auction. In line with ACS' strategy to adopt a light business model, we expect Cobra's position on this project to consist of continuing the same asset recycling strategy as shown so far.

The Beginning of a New Era?

We see the shift from a subsidy-based remuneration model to one more exposed to market dynamics as a sign of an industry entering a more mature phase, where costs of production decrease as technology matures and gains scale. This is true both in wind (offshore and onshore) as well as in solar. We believe the stronger confidence and experience in the technology leads to increased risk appetite from investors. Combined with budgetary constraints that could start limiting governmental subsidies for green generation across Europe, this may be the sign of a new era for European renewables. Although managing market risk exposure today appears as if it is a major shift for the asset class, more conventional generation technologies have managed and financed this risk before. Ultimately, the challenge will be finding the right balance between risk and return for all stakeholders.

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