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The Energy Transition And What It Means For European Power Prices And Producers: Midyear 2020 Update


The Energy Transition And What It Means For European Power Prices And Producers: Midyear 2020 Update

(Editor's Note: Here, in this semiannual report, S&P Global Ratings provides its credit insights for Europe's key utilities and power markets--Germany, France, the U.K., Italy, Spain, and the Nordics--supported by the market and price forecasts of S&P Global Platts Analytics, a part of S&P Global Platts, which is a separate, individual division of S&P Global, as is S&P Global Ratings.)

Weaker economic activity amid the COVID-19 pandemic means that S&P Global Ratings' base-case assumptions for power prices in some of Europe's main markets in 2020-2021 are now up to 20% lower than our previous assumptions in November 2019. This is despite a drastic cut in French nuclear power production rates over the coming three years.

The financial impact of the lower prices on our rated European power generators is generally manageable in 2020, thanks to price hedges. However, generators' hedging positions are less secure for 2021, with only about 30%-50% of total power generation contracted on average. This leaves 50%-70% that still needs to be hedged in an environment of lower prices. While generators still have time to decide on the best approach, the poorer economic prospects and subdued commodity prices do not suggest a strong rebound in power prices in the second half of 2020. We therefore may see greater pressure on the 2021 earnings of merchant power generators that provide baseload power, such as nuclear, coal-fired, or hydro power.

While we expect prices in 2020-2021 to be lower than our previous forecasts, we expect higher, more credit-supportive prices by 2022. This is because of a recovery in gas and carbon prices, and because Germany will become a net importer of energy, as opposed to an exporter of about 40 terawatt hours (TWh) today. The gap in energy supply is likely to be filled with solar and wind power, which should grow to form about 45% of the European energy mix in 2030, from about 25% in 2019, excluding hydro's 10% share.

Table 1 details our base-case assumptions for power prices in five major European markets in 2020-2022. These prices reflect the actual price hedges that the main rated generators in each market have contracted, together with our view of the market forward power prices over the coming two years and Platt's forecasts of daily spot market prices (see chart 1). These base-case assumptions therefore aim to reflect the realized prices for power generators rather than anticipating a future price curve.

Table 1

Power Prices--Historical And Expected Evolution In EMEA
€/MWh 2018 historical 2019 historical 2020-2022 S&P Global Ratings' base-case assumption*
2020 2021 2022
Germany 44 37 41-46 42-44 43-47
France 50 39 45 42-44 44-46
U.K. 65 49 55-60 50-55 50-55
Italy 61 52 57-60 43-46 48-50
Spain 57 48 48-55 43-48 40-45
MWh--Megawatt hour. *These are assumptions used in S&P Global Ratings' base case and include a mix of hedges contracted by rated generators and forward prices. Source: S&P Global Ratings and S&P Global Platts. Data that S&P Global Platts uses include independent and verifiable data collected from actual market participants. Any user of the data should not rely on any information and/or assessment therein in making any investment, trading, risk management, or other decision.

Chart 1

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We believe that renewables will come to play a greater part in power price formation over the next decade. This is supported by EU leaders' recent commitment to the European Green Deal--a set of policies aimed at making Europe climate-neutral in 2050. The COVID-19 pandemic does not seem to have altered leaders' commitment to the deal, which we think could even be accelerated to help European economies rebound. However, we believe that the growth of renewables will entail more weather-related volatility in prices, as was the case early this year, when above-average wind and hydro production reduced power prices.

The push for energy efficiency and deindustrialization in some countries is generally flattening demand. In addition, after three consecutive years of record-mild winters, we also see a risk that power demand could shrink on a sustainable basis compared to the previous decade. What's more, EU policies target a 32.5% reduction in total energy usage by 2030. However, the electrification of industry, heating, and transport could increase demand substantially five years from now.

Merchant-exposed baseload producers such as Statkraft AS, Electricite de France S.A., Fortum Oyj, Uniper SE, and Verbund AG may therefore see their profits decline in 2021 and 2022. For example, Fortum will see about a €100 million drop in EBITDA in 2021, compared with reported EBITDA of €1.8 billion in 2019. We expect that the contribution from Statkraft's flexible European production--mainly Norwegian hydro power, which generated Norwegian krone (NOK) 13.2 billion in EBITDA last year--will deteriorate to NOK11 billion-NOK12 billion in 2020 and NOK8.5 billion-NOK9.5 billion in 2021. For EDF, lower power prices will come on top of much lower production over 2020-2022, as it faces maintenance issues on its nuclear fleet.

The credit impact of the lower power prices we forecast on most of the large European power generators we rate should be more limited, because the sensitivity of their EBITDA to merchant power has decreased markedly. Most have sold part of their generation fleet and have invested heavily in long-term contracted or subsidized renewable energy projects.

Table 2

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Germany
€/MWh (real 2018) Baseload power Clean spark spread Clean dark spread
2017 34.1 (3.3) 3.0
2018 44.5 (7.6) 1.5
2019 38.3 0.8 (6.4)
2020 26.5 3.4 (8.1)
2021 30.5 1.0 (6.4)
2022 38.0 0.4 (6.4)
2023 45.6 (0.2) (5.4)
2024 42.0 (0.1) (12.1)
MWh--Megawatt hour. Source: S&P Global Platts.

Chart 2

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Chart 3

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Germany's Market Structure, Prices, And Renewables: The View From S&P Global Ratings

Analyst: Bjoern Schurich

The energy mix is changing continuously

The German power industry is undergoing a dramatic change to meet the country's ambitious goal of reducing greenhouse gas (GHG) emissions, specifically CO2, by 40% by 2020, 55% by 2030, and 95% by 2050, compared to 1990 levels. The country introduced its Renewable Energy Sources Act ("Erneuerbare Energie Gesetz" or EEG) in 2003, which initiated the change in its energy mix. As a result, renewable power contributed more than 46% of total net electricity generation in 2019, up from 8.5% in 2003, of which about 25% was wind, 9% photovoltaic (PV), 9% biomass, and 4% hydropower. Yet the country still relies on hard coal for about one-third of its total generation (about 23GW of installed net capacity in 2019) and lignite power plants (21GW in 2019). Germany plans to reduce those contributions to a combined 30GW by the end of 2022, and hard coal and lignite to 8GW and 9GW, respectively, by the end of 2030. We believe the pace of this partial phase-out will also depend on the cost position compared to gas. Gas plants represent about 10% of total net generation and we see their load factors increasing in the coming years, replacing coal and lignite.

After a fundamental shift in public perception following the Fukushima nuclear accident in March 2011, the German government changed its policy on the role of nuclear power as a bridge technology on its way to a green energy future. As a result, eight of 17 nuclear reactors were immediately shut down, reducing nuclear power's installed net capacity to 12GW from 20GW. The remaining capacity is scheduled to decline to zero by the end of 2022 from 8.1GW in 2019 (4% of total net capacity; 14% of total net production).

Gross power consumption has remained flattish at about 600TWh (540TWh net) in Germany since 2000. The electrification of additional sectors, such as heating, transport, and data centers points to a rising trend. However, increasing energy efficiency and the "smartening" of electricity networks, including electric vehicles and other storage capacities, have the potential to mitigate the trend.

Imports, gas, and CO2 drive prices

We expect power prices to increase faster in Germany than in neighboring countries until 2025 on average. We see the faster pace of reduction in conventional power capacity in Germany than in neighboring countries as the key driver of inflation. In addition, gas prices, paired with the evolution of CO2 prices, will become more prominent in determining German power prices in the medium term. Furthermore, we expect Germany to become a net power importer, which will help its domestic power prices catch up with those of its European neighbors.

Power prices will rise thanks to a falling base load and higher-priced imports in the short-to-medium term

We expect Germany's power prices to approach France's in 2023, given that France is set to become the main source of Germany's power imports. Europe's power markets are increasingly interlinked under EU single market rules and are still driven by exports from the biggest electricity market in the EU, Germany. (The foreign trade export surplus is about 31TWh, down from 48TWh in 2018.) However, in 2022, we expect Germany to hardly cover its peak demand of a likely 82GW with reliable base load capacity. With an increasing share of cross-border electricity interconnection capacity, imports could become a more prominent driver of EU market integration and therefore power price alignment.

We expect domestic electricity supply and demand imbalances in the German price zone to relax and therefore price tensions to ease after 2025. This is given the progress we expect on:

  • Further penetration of renewables, paired with a build-up of storage and power-to-gas capabilities;
  • Expansion of cross-zonal transport capabilities, enabling increasing international trade; and
  • Increased flexibility from the demand side and from grid smartening.
What role do renewables play in the energy mix and in determining prices?

Germany is set to continue to achieve a minimum of 65% of its renewables expansion goal by 2030, from above 40% in 2019. The interplay of an increasing degree of volatile renewable energy generation, combined with an inflexible base load within the energy mix, has led to power prices becoming more volatile, as well as negative. However, the expansion of onshore wind power--which Germany intends to drive the bulk of the energy transition--is facing major hurdles on the back of an ever-longer process to obtain a permit. After already being 400 megawatts (MW) short of the 2,800 MW annual statutory target in 2018, 2019 onshore wind installations fell to 1.1GW. This compares to an annual average of 4.6GW in onshore installations between 2014 and 2017. If the trend persists, more wind turbines could be taken off the grid than added, making German renewables targets impossible to reach. Next to the permit process, we observe that real estate market conditions have become a prime consideration for onshore wind power expansion.

To counter the fallback, in October 2019, the German government increased Germany's PV expansion ambition to 98GW by 2030 and announced that it would lift the 52GW total capacity limit. The cap was finally dropped in May 2020, after which subsidy payments were due to stop.

The significant penetration of renewables will exacerbate the volatility of power prices. Germany has experienced short periods of negative power prices in the past, due to very high generation from wind and solar, paired with reduced demand and continued feed-in from an inflexible base load capacity. While we see average power prices rising, we do not exclude high volatility due to similar intraday or seasonal situations. In the medium-to-long term, increased storage capabilities, "power to x" solutions--the conversion of surplus power into other forms of energy--and grid smartening should mitigate supply and demand imbalances and therefore power price volatility.

Beyond power prices, how can generators remain profitable?

We believe it is likely that Germany will introduce some form of capacity market, where gas turbines and storage solutions, such as batteries and power-to-x, should play a crucial role. Besides the 2GW of additional off-market reserve capacity that the regulator recently tendered for the period from Oct. 1, 2020, to Sept. 30, 2022, there are no medium- or long-term capacity payments contracted for the German power market as of now.

However, to mitigate the country's looming dependency on imports and to be able to ensure sufficient security of supply, the German government has the option of following the coal commission's recommendation to introduce a risk-oriented monitoring of supply security, partly by facilitating the expansion of gas-fired generation. As such, we expect incentives to be introduced for highly efficient combined cycle gas turbines (CCGTs), as well as for gas-fired combined heat and power (CHPs) generators.

Beyond capacity payments, relatively low natural gas prices, together with CO2 emissions allowance prices trending upward, are making gas turbines increasingly more profitable, pushing hard coal and even lignite plants out of the energy mix at times. This trend has gained traction, especially this year, despite an increasing amount of renewable energy entering the mix, COVID-19-related demand shock, and even a further drop in gas prices. The recent decline in coal and CO2 emissions allowance prices have not meaningfully mitigated the impact of falling gas prices on dark spreads.

With renewable energy generation at an all-time high, lignite and hard coal generation dropped to 4.04TWh and 1.25TWh, respectively, in April 2020, compared to about 9.0TWh and 3.5TWh in April 2019. This prevailing trend should incentivize hard coal plant operators to make use of voluntary auctions to decommission hard coal plants before 2027, so long as the plants do not have to remain online to ensure the security of supply, as the German regulator and the four national transmission system operators (TSOs) are considering. After 2026, we expect the German government to mandate closures with no compensation payments, starting with plants that are the least efficient and produce the most GHG emissions. For German lignite plant closures, the operators have already agreed under bi-lateral arrangements with the government on the decommission schedule and compensation, which will likely be more favorable than the current economic outlook would suggest.

Following the closure of coal plants, operators could benefit from re-equipping them to become gas-fired CHP plants or even thermal storage units. As Germany is looking into ways to develop a hydrogen economy, we expect that refitting coal plants to become gas plants capable of burning hydrogen will become a viable option. We understand that hydrogen can already be used in all grid-connected appliances for up to 15% of the energy mix. In the absence of viable refit options, former coal plant sites could still prove valuable real estate, potentially with limited permit hurdles and public opposition to their conversion into sites for data centers, commercial-scale storage, waste incineration, biomass, or other renewable generation.

In any case, Germany's role as a large-scale net power importer without the help of flexible feed-in sources and a flexible demand side in the long term is hardly sustainable. This is because conventional power capacity is falling nearly everywhere in Europe and more unreliable capacity is being built up to achieve Europe's CO2 neutrality goal by 2050.

More renewable technologies are going merchant

In 2021, the first 20-year subsidy schemes come to an end, resulting in 6,000 plants becoming merchant power generators. As such, long-term contracting via power purchase agreements (PPAs) will become crucial for the generation of stable cash flow. We expect rising wholesale power prices in the short term to support the development of such agreements. Furthermore, after the end of the EEG subsidy schemes, renewable energy generators are entitled to sell green certificates in the form of "guarantees of origin." In the long run, storage or power-to-gas technology will become prime considerations, together with renewable energy plants, in boosting profitability. As such, coal-fired power plants can be converted into heat-storage facilities fueled by renewable energy.

How was the German power market affected by COVID-19?

The COVID-19 pandemic caused the largest shockwaves to global power demand since World War II, whereas the impact on power prices has varied according to each country's respective market characteristics.

Although German power demand has proven much more resilient than in other European countries, the impact on power prices has been quite pronounced due to the inflexibility of power generation and demand. In Germany, industrial consumption accounts for about 45% of German electricity demand, and adding commercial, service, and retail consumption increases the number to about 75%. During the lockdown of March 23 to April 19 and thereafter, German electricity demand dropped by only 7%-8% below the projected numbers--which take into account seasonal, weather, and public holiday effects--triggered by a reduction in industrial output of about 10%-12%. In comparison, in Spain and Italy, electricity demand dropped by up to 25%, corresponding to about a 35%-40% reduction in industrial output at its peak. Of relevance to the German situation is the fact that many larger-scale industrial consumers do not procure electricity from the grid, but use onsite generation--for example, Volkswagen in Wolfsburg--and as such, do not add to the numbers. Furthermore, the backdrop in domestic power consumption is partly mitigated by an increase in retail consumption during the pandemic.

Recently, renewable energy generators backed by feed-in tariffs had no incentive to reduce supply, a reduction in thermal generation on a large scale was neither possible nor profitable, and Germany, as a net electricity exporter, had no demand from neighboring countries. The imbalance was further fueled by a material increase in renewable generation during the first quarter of 2020--52% of 148TWh of total domestic electricity consumption, versus 44% of 151TWh in the first quarter of 2019. This was on the back of newly commissioned plants, record-high wind power production, and atypically high solar power production, increasing the share of renewables in the energy mix even further to above 60% in April 2020.

As a result, Germany has witnessed even more volatile and more negative power prices than other European countries. Notwithstanding this, we expect the driving forces on power prices to become less pronounced in the short term, as economic activity resumes after a COVID-19-related standstill, inflexible coal and nuclear plants are decommissioned, and the first generation of renewable energy technologies near the end of 20-year feed-in-tariff schemes. Our base case is for a reduction in power demand of about 3%-4% for full-year 2020 versus 2019, in the absence of a second wave of the pandemic.

Key Players We Rate In Germany
Company name Rating Total German merchant production in 2019 (TWh) 2020 hedge 2021 hedge

Verbund AG

A/Stable/-- Not publicly available Not publicly available Not publicly available

Uniper SE

BBB/Negative/-- About 2.5 100% at €46/MWh 55% at €49/MWh

E.ON SE

BBB/Stable/A-2 30.1 86% at €46/MWh 65% at €46/MWh

EnBW Energie Baden-Württemberg AG

A-/Stable/A-2 Not publicly available 100% 90-100%
TWh--Terawatt hour. MWh--Megawatt hour.

Table 3

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For France
€/MWh (real 2018) Baseload power Clean spark spread Clean dark spread
2017 44.9 7.4 13.8
2018 50.3 (2.2) 7.3
2019 40.0 2.3 (4.8)
2020 31.5 8.1 (3.1)
2021 32.3 2.4 (4.6)
2022 39.0 1.0 (5.4)
2023 45.1 (1.3) (6.0)
2024 40.0 (2.5) (14.1)
MWh--Megawatt hour. Source: S&P Global Platts.

Chart 4

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Chart 5

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France's Market Structure: The View From S&P Global Ratings

Analyst: Claire Mauduit-Le Clercq

The energy mix is dominated by nuclear and hydro, despite growth in wind and solar

France's energy mix has been dominated by nuclear power since the 1970s push for atomic energy (total capacity of 63GW from 58 reactors). Along with the contribution from hydropower, this means that about 90% of French production stems from low CO2 sources (about 75% nuclear and 15% hydro), which largely cover domestic demand (473TWh of gross consumption in 2019). The country's energy law and the updated multi-year energy plan ("Plan Pluriannuel de l'Energie" or PPE) over 2019-2028 that became law in February 2020 set a roadmap for ambitious growth in renewables and a reduction in nuclear power in the energy mix to 50% by 2035 from about 75% today. However, nuclear reactor closures will only start in 2027 at a pace of one a year, with the flexibility to close two additional plants in 2025 and 2026, depending on the energy policies of neighboring countries. We believe this leaves little scope for the fulfillment of renewable energy goals over the coming decade.

The COVID-19 pandemic is likely to depress power consumption and disrupt supply beyond 2020

The COVID-19 pandemic and the related social-distancing measures, combined with a warmer winter, are likely to depress electricity consumption by about 5%-7% in 2020. On a relative basis, we assess the pandemic as potentially having less of an effect on demand in France than in Italy and Spain, notably because of France's lower share of industrial demand, which was severely affected by the lockdown. At the peak of the COVID-19-related lockdown in April 2020, industrial demand in France dropped by slightly more than 25%, versus about 30% and 40% for Italy and Spain, respectively.

From 2021, we expect flattish-to-declining demand, driven by the push for energy efficiency. This should remain the pattern until 2030, as the fruits of energy-efficiency initiatives by all grid stakeholders more than offset any additional demand that should arise from the growing electrification of industry and e-mobility trends. We believe that the electrification of industry and housing in France is already high compared with its European peers. Electric heating penetration, for instance, is about 30% according to French environment and energy management agency ADEME. We also forecast that additional demand from electric vehicles will not radically change demand patterns in the next decade

The pandemic is disrupting nuclear supply, partly offsetting the drop in power prices

On April 16, 2020, EDF cut its 2020 nuclear output target for its French fleet to 300TWh from 375-390TWh before the COVID-19 pandemic, and adjusted its maintenance schedule to reflect operational disruptions caused by the lockdown and the reduction in power demand. EDF also indicated that it will take some reactors offline to be able to secure supply at the peak of winter. While production for 2020 is likely to be significantly reduced, EDF also guided that the sequencing of the reactor outages will only result in a progressive recovery of its nuclear power output to 330-360TWh for 2021-2022. This has contributed to a tightening power market in France, with the one-year-forward level increasing by €4 per megawatt hour (/MWh) versus our previous price revision. As such, we expect power prices to gradually recover in France over 2021-2023, following a dip in 2020 on the back of a restored balance between supply and demand: €30/MWh in 2020, rising to €43/MWh by 2021 and €45/MWh in 2022.

Power prices should rebound thanks to greater export potential

We forecast a recovery in nuclear output over the next three years, as per EDF's revised maintenance schedule and in line with the country's PPE roadmap that does not foresee any closures of reactors before 2027. Nevertheless, the potential growth in energy from renewable sources remains a key unknown supply parameter, with strong government ambitions for the development of renewable energy. We forecast that French wind and solar capacity will more than double by 2030 from 2018 levels of 15GW and 9GW, respectively. We still believe that capacity growth will be paced in conjunction with export needs to avoid overcapacity and strained prices.

We expect increased export potential for France because of tightening capacity in neighboring countries and new interconnection capacity. French net exports will increase in the first instance, with new interconnections coming online: 2GW with the U.K. (IFA2 and ElecLink) and 1.2GW with Italy (Piemont-Savoy). Originally, these interconnections were due in 2020, but the latest guidance by RTE Reseau de Transport d Electricite (A/Stable/A-1) is that they will be delayed due to the COVID-19 pandemic. A short-term tightening in capacity in neighboring countries, particularly Belgium, Germany, and Italy, is likely to provide additional export markets for France's generation output. A key factor is Germany's plan to shut down about 8GW of nuclear capacity by end-2022, together with the withdrawal of about 5GW of lignite capacity from the sector.

Prices are dictated by the nuclear tariff mechanism

EDF's French production is partly exposed to regulated access to the incumbent nuclear electricity (ARENH) mechanism. This is not only relevant for determining the ARENH output sold to competitors, but also for setting the regulated customer tariff (about 30% of domestic consumption). ARENH is a price mechanism that entitles suppliers to purchase electricity from EDF at a regulated price, in volumes determined by the French energy regulator CRE, with a cap of 100 TWh, potentially increasing to 150TWh under an option embedded in energy law. As such, ARENH plays a key role in retail electricity prices.

The French government launched a public consultation earlier this year--closing mid-March 2020--on proposed new regulation for the existing nuclear fleet. This introduces a price corridor for a large part--about 80%--of the nuclear output, with the ultimate aim to cover the total costs of French nuclear production. The price corridor would provide ex-ante protection in the event of a decline in power prices below the floor price. This would constitute a significant change in market design, departing from the ARENH pricing mechanism ending in 2025. The floor price is yet undefined, while CRE is due to deliver its report on the French nuclear fleet's cash costs to the French government soon. Yet we believe that increasing this floor price to a sustainable economic level is also politically sensitive as it raises affordability issues in the context of a looming recession. In addition, wholesale power prices are currently below the ARENH price and are a potential hurdle to significantly increasing the floor price above €42/MWh.

How do renewables play a role in the energy mix and in determining prices?

France's energy transition law sets out ambitious growth targets. The law aims to increase the share of renewables to reach 23% of electricity production by 2020, 32% by 2030, and 40% in 2030. While solar seems on track to meet its targets by 2023 (20.6GW of installed capacity, up from about 10GW as of 2019), we believe the increase will be more gradual for onshore wind due to acceptability and permit issues slowing progress. We expect COVID-19 to delay the commissioning of some marginal capacity for 2020, but overall, the effects will be neutral over 2020-2023.

We expect predictable prices under the current regulation and support scheme, with the gradual replacement of 20-year feed-in premiums (contracts for difference) that the French state's compensation mechanism guarantees. In France, the taxpayer bears the costs arising from the suppliers' obligations to pay for electricity from renewable sources exported to the grid, otherwise known as the CSPE (Contribution au Service Public de l'Electricité) mechanism.

Key Players We Rate In France
Company name Rating Total French production in 2019 (TWh) 2020 hedge 2021 hedge

Electricite de France S.A.

A-/Watch Neg/A-2 429 100% at €46/MWh* Not publicly available

ENGIE SA

BBB+/Stable/A-2 21 80% at €44/Mwh§ 54% at €47/MWh§
MWh--Megawatt hour. TWh--Terawatt hour. *Average price captured through hedging on forward contracts before the beginning of the delivery year as of Dec. 31, 2019. §Outright hedges on Engie as of Dec. 31, 2019, for French hydro and Belgian nuclear production (about 58TWh per year at average hydro conditions).

Table 4

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For The U.K.
£/MWh (real 2018) Baseload power Clean spark spread Clean dark spread
2017 45.8 6.6 (2.7)
2018 57.4 4.4 (1.6)
2019 43.0 3.3 (17.6)
2020 28.6 14.7 (18.8)
2021 31.8 0.2 (17.6)
2022 36.9 (1.0) (13.3)
2023 41.7 (1.3) (8.5)
2024 37.1 (1.3) (13.1)
MWh--Megawatt hour. Source: S&P Global Platts.

Chart 6

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Chart 7

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The U.K.'s Market Structure: The View From S&P Global Ratings

Analyst: Matan Benjamin

The energy transition is gathering momentum

Climate change and environmental targets have been high on the political agenda in the U.K. over the past few years. Consequently, last year, the U.K. government committed to net-zero carbon emissions by 2050. The move toward low carbon generation is already under way. Of the total 323TWh of electricity generated in the U.K. in 2019, more than one-third (36.9%) came from renewable sources. Gas and coal generation continued to fall, accounting for about 43% of total generation, compared to 45% in 2018 and about 77% in 2008.

Renewable energy is becoming more competitive

The U.K. has a long track record of supporting renewables through government policies and subsidies such as the "Renewable Obligation Certificate" and the contract for difference. Plus, improvements in product design and manufacturing efficiency have led to a material decline in the cost of renewables, making them more competitive than traditional fuels such as gas. Given weather constraints, both onshore and offshore wind has been largely favored over solar. Most recently, during the lockdown, the rate of electricity generation from renewables increased thanks to supportive weather conditions and because they benefit from priority access to the grid even in periods of low demand.

Climate change policies following Brexit and the COVID-19 pandemic are uncertain

Following the U.K.'s departure from the EU at the beginning of 2020, there is still material uncertainty on the U.K.'s future relationship with the EU, the U.K.'s future policy on climate change, and how closely aligned the U.K. will remain with EU standards on the environment and climate change. Furthermore, we note growing uncertainty regarding the government's capacity to maintain similar levels of support and investment in climate change initiatives as it focuses on stabilizing and then rebuilding the economy following the pandemic. However, an indication of the U.K.'s future policy can found in the 2020 budget, in which the government committed to several new climate change measures and investments, including investments in green transport, funds to develop at least two carbon-capture storage facilities, and a green heat network. We also consider that the government could use its spending power for new investments in infrastructure projects, which in turn, would help to reduce unemployment and enhance growth.

Electricity consumption in the U.K. is declining

Total consumption of electricity in the U.K. was 294TWh in 2019, representing about a 2% decline compared with 2018. The decline in consumption is associated with changes in weather conditions and increased energy-efficiency measures. The U.K. has been a net importer of electricity since 2010, and in 2019, imports accounted for 6.4% of total electricity supply. Given the impact of the COVID-19 pandemic, we expect a 5%-7% decline in electricity consumption in 2020. However, we believe that electricity consumption could rise as the energy transition progresses, and particularly as transport moves from oil-based fuels to electricity once electric vehicles become the most popular form of transport.

The main driver of electricity prices is still the cost of gas

This is because gas has historically been marginal in the U.K. market, generally setting the wholesale price of electricity. U.K. gas prices reflect global market conditions and are generally on a par with European prices. The high correlation with gas prices leads to relatively high volatility in power prices.

U.K. power prices are further supported by the carbon price floor

The U.K. has taken steps to provide a stronger price signal to the market by implementing a carbon price floor in 2013. As part of the budget for 2020, the carbon price support--a carbon tax paid by power plants--will remain frozen at £18 per ton. This has notably accelerated the closure of less efficient coal plants. Fluctuation in exchange rates also plays an important role in setting power prices. Specifically, if the pound weakens against the euro, power prices are likely to increase, all other things being equal.

How was the U.K. power market affected by COVID-19?

The U.K. entered lockdown on March 23, 2020. At the end of March, and in April and May, power demand was about 15%-20% lower than the initial forecast by the National Grid, the electricity system operator (ESO), with a material decline in demand from industrial and commercial users. As a result, the ESO has had to implement balancing actions to manage the system, incurring about £500 million of additional costs (a 25% increase), which it should recover from all generators during the third quarter of 2020. Following requests from several generators, the ESO is proposing to spread the additional costs associated with the COVID-19 pandemic over 2021-2022 to help generators and suppliers manage the additional costs while demand returns to normal levels. This should prevent a sudden spike in tariffs at time when consumers are suffering from the economic repercussions of the pandemic.

The U.K. started easing the lockdown measures from May 13, with a gradual ramp-up in industrial activity. Should the lockdown period remain limited to about two months of 2020, we expect U.K. power demand to decline by about 5%-7% in 2020 compared with 2019, with a normalization in 2021.

Hedging offers some protection from short-term weakness

Considering the low gas price, sluggish demand, and weaker macroeconomic conditions, we expect power prices in the U.K. to remain subdued in the short term. At the same time, companies benefit from some protection in the short term because about 80% of their production is hedged at a price of about £45-£50. However, given lower forward prices, companies are exposed to weaker market conditions as they move to secure their hedging positions in 2021.

Key Players We Rate In The U.K.
Company Rating Total production in the U.K. in 2019 (TWh) 2020 hedge 2021 hedge

SSE PLC

BBB+/Stable/A-2 30.8 100% at about £47/MWh Not publicly available

Drax Group Holdings Ltd.

BB+/Stable 17.3 100% at £53.9/MWh About 90% at around £50/MWh

InterGen N.V.

B+/Stable 13.6 45.9% (average for 2020 and 2021; price not publicly available) 45.9% (average for 2020 and 2021; price not publicly available)

Scottish Power Ltd.

BBB+/Stable/A-2 4.6 Not publicly available Not publicly available
TWh--Terawatt hour. MWh--Megawatt hour.

Table 5

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Italy
€/MWh (real 2018) Baseload power Clean spark spread Clean dark spread
2017 52.7 10.7 21.6
2018 60.7 4.9 17.7
2019 52.8 10.3 8.7
2020 36.0 10.0 1.4
2021 42.1 9.3 5.2
2022 49.1 7.7 4.6
2023 54.9 5.3 3.9
2024 50.8 4.9 (3.4)
MWh--Megawatt hour. Source: S&P Global Platts.

Chart 8

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Chart 9

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Italy's Market Structure: The View From S&P Global Ratings

Analyst: Massimo Schiavo

Italy's power prices will remain higher than other European countries' due to the predominance of thermal power and the lack of domestic supply

The Italian power market will see significant changes in the next few years as its fuel mix undergoes a transformation, with more renewables and a decline in coal. However, we expect Italy's power prices to remain higher than in other European markets by Western European standards until 2025. Although prices will decline to close to €40/MWh in 2020-2021 from their 2019 level of more than €50/MWh due to low gas and carbon prices, they will then gradually rebound toward €50/MWh over 2022-2025. Imports play an important role for the Italian power market, given the lack of domestic supply, and we expect about 7.5GW of imports over 2020-2025. Capacity on the northern borders should increase by 2.2GW by 2022, including 1.2GW with France and 1.0GW with Switzerland. This new capacity and a steady Italian price premium should increase imports by 50% in 2025 versus 2018 levels.

Gas will remain the price-setter

This is partly due to Italy's large gas capacity, which makes its power prices heavily dependent on virtual trading point ("punto di scambio virtuale" or PSV) gas prices. These prices are also consistently higher than those of other European hubs. Another element of the dependence on PSV gas prices is Italy's coal phase-out, which is set to end by 2025, translating into a likely reduction of 2GW in coal capacity by 2024 and 6GW the following year. Coal plant closures mean that gas will remain the dominant energy source in Italy in the near future.

Renewable energy will remain a small part of the total energy mix

We forecast that Italian wind and solar capacity will more than double by 18.4GW and 50.9GW, respectively, by 2030, from 2018 levels of 11GW and 21GW. We don't think this increase will offset the impact of coal and nuclear plant closures in France and Germany or affect upside in demand from the electrification of transport, and, to a lesser extent, heating. Italy has been historically strong in hydro production, but the potential for growth in hydro capacity--currently around 12GW for large-scale plants and 22GW in total--is limited. We expect solar and wind to remain a small part of the total energy mix.

How was the Italian power market affected by COVID-19?

Italy was one of the first large European economies to start lockdown, on March 9, 2020. At the end of March and in April, we saw power demand declining by 22% compared to the five-year historical level. Italy eased its lockdown measures from May 3, with a gradual ramp-up in industrial activity. Should the lockdown period remain limited to two months of 2020, we expect Italian power demand to decline by about 8% in 2020 compared with 2019, with a normalization in 2021.

Rated Italian Power Producers Have Short-Term Hedges By European Standards
Company name Rating Total production 2019 (TWh) 2020 hedge 2021 hedge

Enel SpA

BBB+/ Stable/A-2 46.9 100% at €57.1/MWh 50% at €51.6/MWh

A2A SpA

BBB/Stable/A-2 18.1 67% at €59.3/MWh 17% at €52.4/MWh

Edison SpA

BBB-/Stable/A-3 20.6 Not publicly available Not publicly available
TWh--Terawatt hour. MWh--Megawatt hour.

Table 6

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Spain
€/MWh (real 2018) Baseload power Clean spark spread Clean dark spread
2017 52.2 N/A 21.2
2018 57.3 N/A 14.3
2019 49.6 7.8 4.9
2020 31.8 6.8 (2.7)
2021 37.2 5.6 0.3
2022 43.8 4.0 (0.7)
2023 48.8 0.7 (2.3)
2024 42.4 (1.8) (11.7)
MWh--Megawatt hour. N/A--Not applicable. Source: S&P Global Platts.

Chart 10

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Chart 11

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Spain's Market Structure: The View From S&P Global Ratings

Analyst: Gonzalo Cantabrana Fernandez

The Spanish market has historically been dominated by thermal power

The Spanish energy mix is dominated by thermal generation (about 50% of total production, mostly gas). Nuclear and wind each represent about 20%, with hydro providing 7%-15% depending on weather conditions. In February 2020, the Spanish government approved the National Integrated Energy and Climate Plan 2021-2030, which sets out the country's energy transition. The plan sets a target energy mix that changes substantially toward 2030, with 161GW of total energy, based on: 50GW of wind, 39GW PV, 27GW CCGTs, 16GW hydro, 9.5GW hydro pumping, 7GW thermo-solar, 3GW nuclear, and the rest from diverse sources.

The COVID-19 pandemic is likely to reduce power consumption in 2020

A national lockdown was imposed in Spain on March 14, 2020, and should be gradually lifted throughout May, June, and potentially July. The lockdown and its negative impact on the economy will likely reduce electricity consumption on an annual basis. We expect consumption to decline by 6%-8% in 2020. However, it is too early to provide an accurate forecast, as the final number will depend significantly on the speed of the return to normality. The potential repercussions for consumption in 2021 will also depend on the shape of the recovery, although as of today, we do not expect a full recovery over the next two years.

Lower gas prices, coupled with lower consumption, crushed spot prices in the first half of 2020

Gas prices and the cost of the CO2 allowances paid by thermal generators fell significantly at the beginning of the year, driving down power prices across Europe. Spain is no exception, as gas is the most expensive unit in the daily energy mix and sets the power price, coupled with strong hydro production in the year to date. The spot prices in Spain have fallen from €45-€50/MWh in 2019 to €20/MWh in April and May 2020, although we expect a recovery toward €30-€40/MWh by year-end 2020.

Nuclear power plants reacted to the current prices by lowering operating rates toward 70%. Spanish nuclear generation is particularly vulnerable to low prices, as taxes and levies account for approximately €22/MWh, according to Foro Nuclear's president Ignacio Araluce. Spain has two plants offline for maintenance--Almaraz 1 and Asco 1. Hydro stocks have grown thanks to a good rainy season, and are at 65%-70% of capacity, which is above average for the past five or ten years.

In terms of the supply chain, although Gamesa and Vestas suspended the production of wind turbines in Spain, we understand that renewables producers are due to receive PV panels from Chinese suppliers with no delivery issues. The deployment of new renewable energy technologies has slowed so far in 2020 compared to the same period in 2019. This was to be expected, as the 8.7GW of renewable energy technology auctioned in 2016 and 2017 had to be connected to the grid by the end of 2019. In the absence of further auctions or support mechanisms, the development of renewable energy technology is based on PPAs that provide cash flow stability to merchant production. The market appetite under such support mechanisms was evident from the 102GW of wind and solar energy generated under access permits in 2019, as per reports by Red Electrica Corporacion S.A. at year-end. The government envisages new auctions taking place under the Energy and Climate Plan it recently approved, potentially as early as 2020.

Absent new auctions, current prices could bring the financing of new renewables temporarily to a standstill. In addition, in our view, funders will be more aware of the implicit volatility in merchant production that is fully exposed to power prices. Therefore we foresee slower growth in new renewables if the government does not develop support mechanisms under the National Integrated Energy and Climate Plan, PNIEC.

Increasing renewables capacity drives prices

Spain and Portugal are the only markets where we already anticipated a drop in energy prices in real terms between 2023 and 2025. The main driver is our expectation of growth of 15GW of wind and solar installed capacity by 2025. Renewables will be prioritized over other energy sources and have a low marginal cost.

We expect thermal generation to remain the price-setter and continue to dominate the energy mix (historically 40%-50% of generation), but to potentially decline gradually with the increased penetration of renewables over the long term. We expect coal-fired generation to be replaced by gas-fired generation because of increasing environmental constraints. The substitution of coal for gas-fired generation has notably been triggered by falling gas prices, an increase in the cost of carbon, and the elimination of the so-called "green cent" tax on gas used by CCGT turbines and cogeneration units.

Spanish interconnection with France (and hence the rest of the continent) is limited, with currently only 3GW of interconnections out of 98.6GW of installed capacity in the peninsula. This notably explains the difference in power prices between the Spanish and French markets. Interconnection with Portugal, however, is substantial, as demonstrated by the correlation in prices. We expect Spain to remain a net importer for France, although the direction of the flows could become more seasonal with the soaring production from renewables. EDF's cut in production for 2020 may benefit Spanish production, although the limited interconnection will limit the upside.

How do renewables play a role in the energy mix and in determining prices?

Both Spain and Portugal have favorable natural conditions for renewables, allowing for higher utilization rates and thereby making renewables more competitive than in other European markets. The share of renewables is already high following a huge development drive in the 2000s on the back of favorable subsidy schemes. This massive growth led to prohibitive costs for the energy system, and so the government changed the terms of the scheme in 2013, adding grandfathering conditions. This was financially detrimental to operators and resulted in the absence of any new investments for some years. The relaunch of auctions in 2017 led to zero-subsidy projects, reflecting the competitive cost of renewables compared with other energy sources and the sponsors' new appetite for merchant risk, since merchant production is fully exposed to power prices.

Beyond power prices, how can generators remain profitable?

The increased penetration of renewables will reshape hourly prices and increase volatility. This will affect merchant power generation and could provide new remuneration opportunities to back-up facilities (gas, hydro, and batteries). Solar energy, which has a flat generation profile, would be more exposed to the merchant environment, as its load factor and captured price could be significantly altered by new solar capacity. In addition, under the current market conditions, we would expect gas-fired plants to consolidate their increase in load factors in 2019.

Key Players We Rate In Spain
Company name Rating Total production in 2019 (TWh) 2020 hedge 2021 hedge

Iberdrola S.A.

BBB+/Stable/A-2 58.6 100% 70%

Endesa S.A.

BBB+/Stable/A-2 61.4 100% at €73.5/MWh* 80% at €74.5/MWh*

EDP - Energias de Portugal S.A.

BBB-/Stable/A-3 37.1 100% at €55/MWh 60% at €50/MWh

Naturgy Energy Group S.A.

BBB/Stable/A-2 25.8 Less than 70% Not publicly available
*Retail price. TWh--Terawatt hour. MWh--Megawatt hour.

Nordics' Market Structure: The View From S&P Global Ratings

Analysts: Per Karlsson and Daniel Annas

Power prices are at a record low thanks to extremely high hydrological supply and a mild and windy winter

The fall in European power exchange "Nord Pool" power prices has been dramatic. In the first quarter of 2020, power prices were down by around 70% from average 2019 levels of €39/MWh. This is mainly a direct consequence of high precipitation, supported by a warm and windy winter. The temperature in the Nordics has been above normal. For example, in Sweden, January 2020 was 2-3 degrees warmer than usual, followed by an even milder February that was 4-6 degrees above average. Spot prices now stand at about €5-€10/MWh, but in some periods this year, we have even seen negative prices. Consequently, we now expect power prices in the region to remain depressed, at €10-€15/MWh during 2020-2022, and at €17.5-€22.5/MWh on average during 2021.

Chart 12

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Our expectations predominantly reflect the hydrologic balance, which is likely to affect prices well beyond 2020. We expect the low power prices to persist for a long period, as we expect that hydro will remain close to maximum capacity, as precipitation and water levels are high. The hydro system should therefore continue to be the price-setter of power prices in the Nordic power system, as it is by far the main source of power production. Due to large amounts of snow, the current hydrological balance equates to about 87TWh of electricity production, which is well above the average of 44TWh, and the highest level ever measured according to The Norwegian Water Resources and Energy Directorate.

In addition, we expect the COVID-19 pandemic to lead to reduced demand of 5%-10% in 2020, and also to reduce 2021 demand. While we see that lower demand will contribute negatively both to generators' earnings and the power balance, we expect the lower prices to be the largest factor in the decline we expect in generators' credit ratios. Although we take account of the low spot prices, we expect most generators to achieve higher effective prices in 2020, as they have all hedged the lion's share of their production, albeit to varying degrees.

We expect Uniper to achieve the highest realized prices this year as it has hedged 95% of its production (see table 7). Statkraft's hedged ratio is substantially lower, as its production from hydro has a lower average cost profile.

Table 7

Expected Average Nordic Power Prices
€/MWh 2018 2019 2020 2021
Prices 44 39 10-15 17.5-22.5
MWh--Megawatt hour.
Renewable energy creates price volatility and oversupply in the power system

In the first four months in 2020, total power production in the Nordics increased by 4.4% to about 153TWh compared to 147TWh in 2019, and exceeded demand by about 11TWh. The excess was exported. Wind production in the region continues to increase, although its share of total production still is relatively low at about 10%. We expect wind projects in progress to continue and gradually make prices more volatile in the coming years.

Increased production is mainly driven by increased generation from hydro, as a result of unusually high precipitation, and despite Sweden's closure of its nuclear power plant Ringhals 2 in December 2019. In addition, Ringhals 1 is to be closed by the end of 2020, although it is now under maintenance and at 0% capacity. The historical fall in power prices came at the same time as the dismantling of the nuclear power system, and despite some exceptions, did not lead to any price increases. Ringhals 3 is also under maintenance until July 3, 2020, with 0% capacity. Ringhals 1, 2, and 3 together have a capacity of about 2.8GW.

How was the Nordic power market affected by COVID-19?

Nordic demand dropped by about 3.1% in the first four months of 2020 compared to same period last year, which also contributed to the lower power prices. But there are clear differences between the Nordic countries. We saw the strongest downturn in Sweden, as demand there is to a large extent driven by industry. Norway has been much less affected, with demand only shrinking by about 0.5% in the first four months in 2020, as the country does not have such a large heavy industry sector. We expect COVID-19 to reduce demand by 5%-10% in the Nordics in 2020, and also reduce 2021 demand.

Some areas have excessive supply, but others have shortages

Despite the oversupply in the Nordics, some areas have witnessed significantly higher prices as a result of insufficient connections to those areas. One example is the southernmost part of Sweden. The Nordic TSOs have many interconnector projects in the pipeline to mitigate these issues, but the effects will only materialize gradually over the coming years. In addition, we expect interconnector capacity to increase capacity materially by about 94%, from 6.9GW in 2020 to above 13GW by end of 2023. This should flatten prices in various areas across the Nordic countries, but it could also increase the prices that the generators with the most flexible systems achieve, such as Statkraft. This is because Nord Pool power prices are generally lower than in neighboring countries.

Renewable energy policies have not changed since our last report in November 2019

We do not expect to see any significant changes in policies in terms of the European green deal in the Nordics. We understand that the Nordic countries will remain focused on adding renewable energy sources and making the power system more environmentally friendly, despite the ongoing pandemic. That said, we believe that newly built and ongoing projects--mostly small-to-midsize onshore wind power projects--could struggle with profitability due to lower prices, together with very low subsidies. We have already seen this with Statkraft, which reported an impairment on its Fosen wind project of about €250 million in the first quarter of 2020. Statkraft has, via industrial contracts, fixed prices for about 30% of its output during 2020, and 18% during 2021.

Key Players We Rate In The Nordics
Company name Rating Total production in 2019 (TWh) 2020 hedge (%) Expected effective prices, including hedges and power purchase agreements (%) 2021 hedge (%) Expected effective prices, including hedges and power purchase agreements (%)

Fortum Oyj

BBB/Negative/A-2 45.5 85% at €33/MWh 27-32 50% at €34/MWh 26-31

Orsted A/S

BBB+/Stable/A-2 7.0 N/A N/A* N/A N/A*

Statkraft AS

A-/Stable/A-2 61.0 7 18-22 2 20-25

Vattenfall AB

BBB+/Stable/A-2 112.0 65% at €33/MWh 22-27 47% at €32/MWh 22-27

Uniper SE

BBB/Negative 95% at €28/MWh 26-28 28% at €28/MWh 20-25
*For Orsted, offshore wind capacity in Denmark is fully contracted. TWh--Terawatt hour. MWh--Megawatt hour.

This report does not constitute a rating action.

Primary Credit Analysts:Massimo Schiavo, Paris + 33 14 420 6718;
Massimo.Schiavo@spglobal.com
Pierre Georges, Paris (33) 1-4420-6735;
pierre.georges@spglobal.com
Karl Nietvelt, Paris (33) 1-4420-6751;
karl.nietvelt@spglobal.com
Secondary Contacts:Bjoern Schurich, Frankfurt (49) 69-33-999-237;
bjoern.schurich@spglobal.com
Per Karlsson, Stockholm (46) 8-440-5927;
per.karlsson@spglobal.com
Claire Mauduit-Le Clercq, Paris + 33 14 420 7201;
claire.mauduit@spglobal.com
Gonzalo Cantabrana Fernandez, Madrid (34) 91 389 6955;
gonzalo.cantabrana@spglobal.com
Matan Benjamin, London (44) 20-7176-0106;
matan.benjamin@spglobal.com
Daniel Annas, Stockholm +46 (8) 4405925;
daniel.annas@spglobal.com

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