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The Energy Transition And What It Means For European Power Prices And Producers: January 2021 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. At S&P Global Platts Analytics, Glenn Rickson, Head of European Power Analysis; Giuliano Bordignon, Senior Power Analyst; and Sabrina Kernbichler, Power Analyst, provided invaluable insights and data for this report. S&P Global Platts' data in this report is subject to the following disclaimer:

S&P Global Ratings has raised its base-case assumptions for power prices up to 5% in five of Europe's main markets over 2021-2023 from its June 2020 assumptions (see table 1). The reasons are a lower decline in power demand last year than we expected, more supportive commodity prices in 2022 and 2023, and accelerated anticipated closures of conventional generation plants (notably nuclear and coal) in the next three years.

Despite our expectation for only a partial recovery in power prices in 2021, the financial performance of our rated European power generators should find support from their almost fully hedged power position this year, contracted generally well above 2020 spot prices. The financial impact of much lower power prices than we expected in 2020 was generally manageable, thanks to price hedges and a more contracted generation mix.

We expect higher, more credit-supportive prices by 2022. A recovery in power prices in 2022 and 2023 at or above 2019 levels in almost all European main markets should underpin earnings for merchant power generators that provide baseload power, such as nuclear or hydro. Reasons for the power price recovery are a rebound in gas and carbon prices and because of the shift of Germany, Europe's largest and most central market, to net importer of energy from exporter of about 19 TWh today. The gap in energy supply is likely to be filled with solar and wind power over time, which should grow to form about 45% of the European energy mix in 2030, from about 25% in 2019, excluding hydro's 10% share.

Our base-case power price assumptions represent actual price hedges that the main rated generators in each market have contracted, together with our view of the market's forward power prices over the coming two years and S&P Global Platts Analytics' forecasts of daily spot market prices (see chart 1). These base-case assumptions therefore reflect realized prices for power generators rather than a future price curve.

Table 1

Power Prices In EMEA: S&P Global Ratings' Historical And Base-Case Projections
(€/MWh) 2018 historical 2019 historical 2020 historical 2021-2023 S&P Global Ratings' base-case assumption*
2021 2022 2023
Germany 44 37 30 45-46 45-50 47-53
France 50 39 32 44-46 46-48 48-53
U.K. 65 49 40 49-52 48-55 48-55
Italy 61 52 38 47-50 48-51 55-57
Spain 57 48 34 45-50 50-55 48-53
*These are assumptions used in S&P Global Ratings' base case and include a mix of hedges contracted by rated generators and forward prices. MWh--Megawatt hour. Source: S&P Global Ratings.

Chart 1


S&P Global Ratings' Baseload Power Price Forecast For EMEA

Given conventional nuclear and coal plant closures, we believe gas and carbon prices after 2023 will play a growing role in power prices, which we expect to remain relatively high. The increasing penetration of renewables will also play a big part. This is supported by EU leaders' commitment to the European Green Deal--a set of policies aimed at making Europe climate-neutral in 2050--and a €225 billion of recovery fund to be invested over the next three years for the energy transition. This demonstrates European governments' recognition that the energy transition will play a pivotal role in Europe's economic recovery. However, we believe the growth of renewables will entail more weather-related price volatility, as was the case in January 2021, with below-average wind production, combined with a cold wave, lifting daily prices to about 70€/MWh in the Nordics.

We anticipate subdued economic growth, combined with the push for energy efficiency and deindustrialization in some countries, will bring demand back to pre-COVID-19 levels only in 2023. What's more, EU policies target a 32.5% reduction in total energy use by 2030. However, the electrification of industry, heating, and transport could increase demand substantially after 2023.

Due to still relatively low power prices in 2021, the largest merchant-exposed baseload producers such as Electricite de France S.A., Fortum Oyj, Uniper SE, and Verbund AG may see only a modest earnings rebound in 2021. For example, we anticipate that Fortum's EBITDA will drop about €100 million in 2021, from €1.8 billion reported in 2019. For EDF, recovering prices will be mitigated by the effects of subdued production over 2021-2022 because of maintenance issues for its nuclear fleet.

The credit impact of the relatively low power prices we forecast for 2021 on most large European power generators we rate should be more limited because the sensitivity of their EBITDA to merchant power has decreased markedly and because of power price hedges. Most have sold part of their generation fleet and invested heavily in long-term contracted or subsidized renewable energy projects.

As vaccine rollouts in several countries continue, S&P Global Ratings believes there remains a high degree of uncertainty about the evolution of the coronavirus pandemic and its economic effects. Widespread immunization, which certain countries might achieve by midyear, will help pave the way for a return to more normal levels of social and economic activity. We use this assumption about vaccine timing in assessing the economic and credit implications associated with the pandemic (see our research As the situation evolves, we will update our assumptions and estimates accordingly.

Table 2

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Germany
(€/MWh, Real 2019) 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 30.5 1.4 (9.8)
2021 38.7 4.1 (2.7)
2022 45.0 4.2 (1.8)
2023 53.2 4.7 (0.7)
2024 50.8 4.1 (7.4)
2025 47.7 4.5 (14.2)
MWH--Megawatt hour. Source: S&P Global Platts.

Chart 2


Chart 3


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

Analyst: Bjoern Schurich

Greening of the Germany's energy sector is driving electricity supply-and-demand imbalances

The German energy landscape is undergoing a transformation 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 with 1990 levels--with 42.3% achieved in 2020. Renewable power now constitutes one-half of total net electricity generation (on average for the year 2020). However, this rapid increase in renewables will, even under optimistic expansion scenarios, be insufficient to offset the drastic near-term closures of traditional energy sources such as coal and nuclear power.

Polluting hard coal and lignite power plants, which still account for about 25% of net generation, have entered their phaseout programs, with a combined equally split 30GW capacity closure by the end of 2022 (see "The Path To Germany’s Coal Exit Has Diverging Credit Implications For Utilities," Nov. 16, 2020). In addition, Germany's nuclear exit strategy soon comes to an end: the remaining 8 GW capacity (14% of total net production) is scheduled to decline to zero by the end of 2022.

In the coming years, we anticipate the country's currently prevailing flattish domestic electricity demand, at about 600 TWh (540 TWh net) since 2000, to increase due to the electrification of additional sectors, such as heating, transport, and data centers, notwithstanding the mitigating effect of increasing energy efficiency and the "smartening" of electricity networks (including storage capacity).

We therefore expect Germany's power prices to approach France's in 2022, since France is set to become the main source of Germany's power imports. This compares to Germany's downward trending net exporter position of 18 TWh in 2020, 34 TWh in 2019, and 49 TWh in 2018. We anticipate upward power price pressure in the coming five years as a result of such a rapid decline in supply.

We then anticipate domestic electricity supply-and-demand imbalances in the German price zone to relax only from 2026. This assumes:

  • Further penetration of renewables, paired with a buildup 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 grid smartening.
How is the German power market affected by COVID-19?

For full-year 2020, power demand fell 4.7% from 2019 because of lower economic activity that was mitigated by higher household consumption. Yet, the country witnessed even more volatile and more negative power prices than in other European countries, as average baseload power prices sunk €7/MWh to 30.5€/MWh from 2019.

We view theses characteristics of the German power market as relevant to development during the pandemic:

  • More resilient demand: Industrial consumption accounts for about 45% of German electricity demand (or about 75% including commercial, service, and retail consumption). This number does not include Germany's many larger industrial consumers that generate electricity off-grid onsite (rather than procuring from the grid)--like Volkswagen in Wolfsburg.
  • A more inflexible power supply base: In response to a short-term decline in wholesale electricity prices, renewable energy generators backed by feed-in tariffs have no incentive to reduce supply--at least not before the decline lasts six consecutive hours--and thermal generators lack the flexibility or economic incentives to do so. In addition, Germany had no demand from neighboring countries to take oversupply. The imbalance was further fueled by an increase in renewables generation during the first quarter of 2020 on the back of newly commissioned plants, record-high wind power production, and atypically high solar power production.

For 2021, we expect downward pressure on power prices to become less pronounced as economic activity resumes after a COVID-19-related standstill and inflexible coal and nuclear plants are decommissioned. German electricity futures prices have already recovered to above €50/MWh for year 1 and 2 delivery (as of Jan. 25, 2021) from below €35 and €40, respectively, as of the end of first-quarter 2020.

On a positive note, Germany was able to achieve its CO2 reduction target in 2020, but only thanks to the impact of COVID-19 pandemic, with a 42.3% reduction compared with 1990 levels, up from 35.7% in 2019.

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

With the will to become the leader of the European energy transition, Germany has high ambitions for renewables but faces big hurdles.

The country aims to reach 65% of its electricity production from renewables by 2030 (from about 45% in 2020). In December 2020, the German government slightly raised its targets for solar PV to 100 GW by 2030 (versus 53 GW today), onshore wind to 71GW (55GW), offshore wind to 20GW and 40GW by 2040 (versus 7.7 GW today), and biomass to 8.4GW (about 8GW today). We anticipate these targets will be raised further in 2021 for a better alignment with the more ambitious EU 2030 emissions reduction targets.

However, in the interim, the expansion of onshore wind power is facing major hurdles because of the increasingly lengthy and difficult permitting process. After already falling short in 2018 by 400 MW of the 2,800 MW annual statutory target, onshore wind installations fell to 1.1 GW in 2019, then somewhat recovered to 2.7 GW in 2020—though still falling short of a tendered 2.9 GW in 2020. This compares with an annual average of 4.6 GW of onshore installations between 2014 and 2017. If the trend persists, German renewables targets will become increasingly difficult to achieve. Next to permitting, we observe that real estate market conditions have become a prime consideration for onshore wind power expansion. As such, the country will need to streamline permitting and reduce regulatory barriers. In contrast, PV tenders are regularly oversubscribed.

Notwithstanding the increasingly large penetration of renewables will exacerbate the volatility of power prices. Germany has experienced short periods of negative power prices in the past (hourly day-ahead prices have turned more negative year on year; they were negative for 211 hours in 2019 and 298 hours in 2020) due to very high generation from wind and solar, paired with reduced demand and continued feed-in from an inflexible baseload capacity. While we see average power prices rising, we do not exclude high volatility due to similar intraday or seasonal situations. Over the medium to long term, supply-demand imbalances and therefore power price volatility should lessen due to increased storage capabilities, "power to x" solutions--the conversion of surplus power into other forms of energy--and grid smartening.

This year will also see the first 20-year subsidy scheme come to an end, resulting in 6,000 plants (4.5 GW, of which 3.7 GW in onshore wind) falling out of the EEG subsidy support program. As per a late December 2020 legislative ruling, these assets will retain feed-in priority (merit-order positioning), and some will be eligible for a limited follow-up remuneration mechanism until 2022, but all will ultimately need to rely on some form of direct-marketing or on-site contracting solutions, in the absence of repowering investments. As such, long-term contracting via power purchase agreements (PPAs) will become more crucial. Correspondingly, we observe increasing market appetite for green energy for commercial and industrial offtakers, boosted by heavy industry's need to decarbonize via green gas--even before the development of a viable European (green) hydrogen market (see "Clean Hydrogen Investment Is Still A Leap Of Faith For European Utilities," Nov. 16, 2020).

Beyond power prices, how can generators remain profitable?

We believe Germany will likely introduce some form of capacity mechanism or similar flexibility incentives. Besides the tenders for off-market reserve capacity and the standard short-term balancing power reserve, the German power market today has no medium- or long-term capacity payments. However, to lessen the country's looming dependency on imports and better ensure supply security, we expect the market to see the introduction of incentives for more supply-side flexibility, for example, for highly efficient gas generation, combined heat and power (CHPs) generation, as well as storage solutions, such as batteries and power-to-x.

Beyond capacity payments, relatively low natural gas prices, together with rising CO2 emissions allowance prices, are making gas turbines increasingly more profitable than hard coal plants--and even lignite plants at times. Day-ahead 46% efficient hard coal plants' CDS averaged €2.33/MWh in 2020, versus €8.19/MWh for 55% efficient gas plants' CSS.

With renewable energy generation at a record high, lignite and hard coal generation dropped to 92 TWh and 43 TWh, respectively, in 2020, compared with 114 TWh and 57 TWh in 2019. We believe this prevailing trend should give hard coal plant operators an incentive to use voluntary auctions to decommission hard coal plants before 2027. After closure, companies could derive value from transforming the plants or the sites.

Table 3

Key Power Companies We Rate In Germany
Company Ratings German merchant/total German generation 2020 (TWh) 2021 hedge 2022 hedge

Verbund AG

A/Stable/-- N.A./N.A. N.A. N.A.

Uniper SE

BBB/Negative/-- N.A./N.A. 95% at €46/MWh 80% at €48/MWh


BBB/Stable/A-2 ~30/~30 84% at €44/MWh 52% at €45/MWh

EnBW Energie Baden-Wuerttemberg AG

A-/Stable/A-2 N.A./N.A. 90%-100% 50%-70%
N.A.--Not publicly available. MWh--Megawatt hour. TWh--Terawatt hour. Source: S&P Global Ratings.

Table 4

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For France
(€/MWh, Real 2019) 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 32.2 3.6 (8.1)
2021 38.9 3.9 (2.5)
2022 44.9 3.6 (2.0)
2023 51.8 2.8 (2.1)
2024 47.4 0.3 (10.8)
2025 43.2 (0.4) (18.7)
MWh--Megawatt hour. Source: S&P Global Platts.

Chart 4


Chart 5


France's Market Structure, Prices, And Renewables: 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 63 GW 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 (473 TWh of gross consumption in 2019). The country's energy law and the updated multiyear 2019-2028 energy plan that became law in February 2020 (Plan Pluriannuel de l'Energie or PPE) 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, following the closure of Fessenheim last year, 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. While we forecast that French wind and solar capacity will more than double by 2030 from 2018 levels of 15 GW and 9 GW, respectively, we also note that growth will be aligned with export needs to avoid overcapacity and strained prices.

The COVID-19 pandemic depressed both power consumption and supply in 2020

The COVID-19 pandemic and related social-distancing measures, combined with a warmer 2019-2020 winter, depressed electricity consumption by about 5.4% in 2020, at the lower end of our 5%-7% expectations. The pandemic reduced demand in France less than in the U.K., but about the same magnitude as in Spain and Italy, despite France's lower share of industrial demand, which took a big hit from the first lockdown. At the peak of the lockdown in April 2020, total demand dropped 18%, compared with 17% in Spain and 16% in Italy and the U.K.

We anticipate a recovery in 2021 to almost pre-COVID-19 levels and expect flat-to-declining demand from 2022 onward, with energy efficiency initiatives by all grid stakeholders more than offsetting additional demand from increased electrification of industry and e-mobility. We note that electrification of industry and housing in France is already higher than 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 EV will not radically change demand patterns in the next decade. We note that EV sales in France more than doubled in 2020 (111,000 units versus 43,000 in 2019) but still represent less than 7% of new car sales.

Unlike in neighboring markets, the pandemic affected availability of supply in France. During the second half of 2020, EDF raised its annual nuclear output target for its French fleet to 335 TWh (from 300 TWh initially in mid-April). This compares with 375-390 TWh historically and reflects the group's need to adjust its maintenance schedule to consider operational disruptions caused by the lockdown and the reduction in power demand.

EDF also forecast only a gradual recovery in its nuclear power output to 330-360 TWh for 2021-2022 because of the sequencing of reactor outages. Combined with a recovery in demand, we expect power prices to gradually rebound in France over 2021-2023, following a dip in 2020 (€32/MWh on average) on the back of a restored supply-demand balance, progressively rising to €46-€48/MWh in 2022 and €48-€53/MWh in 2023 from €44-€46/MWh in 2021.

From 2023, power prices will benefit from greater export potential

From 2023, we expect increased export potential for France because of tightening capacity in neighboring countries and new interconnection capacity. First, net exports will increase as new interconnections come online: 2 GW with the U.K. (IFA2 and ElecLink pushed to July 2022) and 1.2 GW with Italy (Piemont-Savoy). Originally, these interconnections were due in 2020, but the pandemic caused delays. 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 8 GW of nuclear capacity by end-2022, together with the withdrawal of about 5 GW of lignite capacity from the sector.

Upcoming reform of nuclear is a key unknown to power prices

The French government is currently seeking to reform its nuclear power sector, which currently suffers from structural issues.

As of now, 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.

We understand the French government is currently negotiating with the EU to implement a new mechanism, introducing a floor price for nuclear output, that would better reflect the total cost of nuclear. At this stage, there are no detailed information about the floor price, timing of the reform, and level of output under this mechanism. Yet we believe that increasing this floor price to a sustainable economic level is also politically sensitive because it raises affordability issues amid weak economic conditions. At the same time, we recognize that wholesale power prices have recovered and are now well above the ARENH price.

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

France's energy transition law sets out ambitious growth targets. It aims to increase the share of renewables to 23% of electricity production by 2020, 32% by 2030, and 40% in 2030. While solar seems on track to meet its targets by 2023 (20.6 GW of installed capacity, up from about 10 GW as of 2019), we believe onshore wind will increase more gradually because acceptability and permit issues are slowing progress. As for offshore wind, projects under developments by EDF, ENGIE, and Iberdrola are advancing. For instance, EDF has four projects for a total capacity of 2 GW (including 480 MW under construction) expected to be commissioned between 2023 and 2027 on the French market. Iberdrola is also targeting an installed capacity of about 500 MW at its Saint Brieuc offshore wind site (construction starting in 2021). As anticipated, COVID-19 only marginally delayed the commissioning of capacity for 2020, and we expect that overall, the effects will be neutral over 2020-2023.

As part of its 2020 economic stimulus package, the French government also unveiled an ambitious hydrogen plan aiming to deploy €7.2 billion of investments by 2030, of which €3.4 billion by 2023 to foster green hydrogen generation technologies. This includes €1.5 billion of capital to be deployed for adding 6.5 GW of electrolysis capacity. We anticipate these targets for developing green hydrogen, in and of themselves, will boost demand for renewables capacity additions on the domestic market.

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. However, in late 2020, a retroactive cut for solar feed-in tariffs was adopted by the French parliament (that the Senate still needs to review). If the law is adopted, the remuneration of projects commissioned between 2007-2008 as well as between 20211-2012 could be reduced on the remaining lifetime of the solar plant (with no reimbursement of aid received). We understand this would apply to about 800 contracts or a few hundred million euros a year. The magnitude of the cut is yet unknown, and the purpose is to allow for a "reasonable" return on capital on solar PV installations. While sending a negative signal to investors, we believe the envisaged perimeter remains contained. 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.

Table 5

Key Power Companies We Rate In France
Company name Rating Total production 2020 (TWh)* 2021 hedge 2022 hedge

Electricite de France S.A.

BBB+/Stable/A-2 384 N.A. N.A.

Engie SA

BBB+/Stable/A-2 20 80% at 46€/MWh N.A.
*S&P Global Ratings estimates. N.A.--Not publicly available. MWh--Megawatt hour. TWh--Terawatt hour. Source: S&P Global Ratings.

Table 6

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For U.K.
£/MWh (Real 2019) 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 39.6 2.2 (22.6)
2021 39.5 1.7 (15.1)
2022 43.1 0.9 (12.0)
2023 48.1 1.3 (7.5)
2024 43.9 0.3 (11.8)
2025 40.4 1.5 (15.2)
MWh--Megawatt hour. Source: S&P Global Platts.

Chart 6


Chart 7


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

Analyst: Benjamin Matan and Gustav Rydevik

The Green Industrial Revolution ambition

The move toward low carbon generation is already underway. Of the total 250 TWh of electricity generated in U.K. in 2020, roughly 35% came from renewable sources. Gas and coal generation continued to fall, accounting for about 40% of total generation, compared with 44% in 2019 and about 77% in 2008. We note that the increase in renewables penetration in 2020 also found support from favorable weather conditions and priority access to the grid even during periods of low demand, as was the case last year due to the pandemic and subsequent lockdowns. Indeed, in 2020 power demand dropped by 6% (268 TWh) from 2019, which was already down 2% versus 2018. We now anticipate a gradual recovery in demand over 2021-2023, backed by economic growth. Beyond this, we believe that electricity consumption could rise further as the energy transition progresses, and particularly as transport moves from oil-based fuels to electricity, once EVs become the most popular form of transport.

The U.K. government has, to date, dangled some carrots to encourage utilities to reduce their carbon emissions. On Dec. 14, 2020, the U.K. government published a white paper setting out the government's agenda for the energy sector and its role in tackling climate change. It builds on Prime Minister Boris Johnson's £12 billion 10-point plan for clean energy and sets out steps to cut 230 million tons of CO2 from industry, transport, and buildings by 2030. The government also raised its offshore wind target to 40 GW by 2030, from 30 GW previously (from 10.4 GW today), along with a support package to facilitate investment (for example, into ports) to spur growth in this technology. We expect this measure will benefit U.K. utilities with sizable expertise in and exposure to offshore wind generation, such as SSE PLC (BBB+/Stable) and Iberdrola (BBB+/Stable), through its U.K. subsidiary Scottish Power (BBB+/Stable).

We project that future face-value remuneration for new renewables projects will not reach past levels (strike prices for contracts for differences have fallen to below £40/MWh in 2019 from £114/MWh in 2015). Nevertheless, the measure will provide additional visibility to future cash flow and support metrics. These lower strike prices also reflect improvements in product design and manufacturing efficiency, which have lowered the cost of renewables, making them more competitive than traditional fuels such as gas. It is also interesting to note that given U.K. weather constraints, onshore and offshore wind have both found more favor than solar.

Future climate change and carbon policies after Brexit remain unclear

Following the U.K.'s departure from the EU, many issues are unclear about the U.K's future relationship with the EU, climate change policy, and its alignment with EU environment and climate change standards. In the Brexit deal of Dec. 24, 2020, the EU and U.K. committed to developing and implementing new and efficient trading arrangements by April 2022. The agreement also notably includes:

  • Reciprocal commitments not to reduce environmental or climate protection,
  • Commitments not to enforce laws that affect trade, and
  • Reciprocal commitments to cross-economy GHG emission reduction targets.

However, the agreement gives both parties the freedom to set their own climate and environmental policies.

The main drivers of electricity prices are gas, the carbon price floor, and exchange rates

The main drivers of electricity prices are gas, the carbon price floor, and exchange rates 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 power price volatility. Cold weather boosted electricity prices at the start of 2021, which will flatter generators' profitability, though modestly because most of them have large hedges.

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

Finally, fluctuations in exchange rates also play 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.

Table 7

Key Power Companies We Rate In The U.K.
Rating Total production for 2020 (S&P Global Ratings annualized estimates)(TWh) 2021 hedge 2022 hHedge


BBB+/Stable/A-2 28.4 78% at about £48/MWh N.A.


BB+/Stable 18.9 86% at about £48.2/MWh‡ 38% at about £48/MWh‡


B+/Stable 7.7 22% (weighted average of contracted capacity October 2020-December 2022; price N.A.)

Scottish Power†

BBB+/Stable/A-2 6.1 Power generation is fully contracted under CfD (Contract for Difference) and ROC (Renewable Obligation Certificate) remuneration schemes
*As of Sept. 30, 2020. §As of July 31, 2020. †As of Sept. 30, 2020. ‡Contracted % versus 2019 full-year output as of November 2020. N.A.--Not publicly available. MWh--Megawatt hour. TWh--Terawatt hour. Source: S&P Global Ratings.

Table 8

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Italy
€/MWh (Real 2019) 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 38.4 7.4 (1.9)
2021 43.8 7.4 2.4
2022 50.6 6.2 3.8
2023 56.9 4.5 3.1
2024 54.2 3.7 (4.0)
2025 50.6 3.6 (11.3)
MWh--Megawatt hour. Source: S&P Global Platts.

Chart 8


Chart 9


Italy's Market Structure, Prices, And Renewables: 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 big changes in the next few years as its fuel mix undergoes a transformation, with renewables capacity (wind and solar) doubling by 2030 and a rapid decline in coal power generation. However, we expect Italy's power prices to remain higher than in other European markets by Western European standards until 2025 due to structural undersupply. Although prices will remain relatively low--close to €40/MWh in 2021 compared with the 2019 level of more than €50/MWh due to low gas and carbon prices--we anticipate they will then gradually rebound toward €50/MWh over 2022-2025. This is notably because imports play an important role for the Italian power market, given the lack of domestic supply, with interconnector capacity expected to increase to 12.7 GW in 2025. Interconnection capacity on the northern borders should increase by 2.2 GW by 2025, including 1.2 GW with France (which should come online in November 2021) and 1.0 GW with Switzerland (expected by 2025). This new capacity and a steady Italian price premium should increase imports 50% in 2025 versus 2018, with imports covering about 20% of demand over 2021-2025. Increasing interconnection capacity will likely dampen Italian power prices and become more sensitive to lower prices in other countries, notably France.

Gas will remain the price-setter for the coming decade

This is partly due to Italy's large gas capacity (about 40% of total installed capacity and 48% of total production with 39 GW of installed capacity, and 145 TWh of production), which makes its power prices heavily dependent on 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 phaseout, which is set to end by 2025, with the largest closures expected to occur in 2021 and 2025, with about 3 GW of closures in each of those years (for a total installed capacity of 7.1 GW at year-end 2020). Coal plant closures mean that gas will remain the dominant energy source in Italy in the near future.

Despite ambitious green targets, 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 18.4 GW and 50.9 GW, respectively, by 2030, from 11 GW and 21 GW in 2018. As a result, renewables will represent about 25% of the mix by 2030, from 16% today. We don't think this increase will offset the impact of coal and nuclear plant closures in France and Germany or reduce 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 about 13 GW for large-scale plants--is limited.

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

Italy was one of the first large European economies to lock down, on March 9, 2020. At the end of March and in April, we saw power demand declining 22% from the five-year historical level. Power prices dropped at that time to a record low €20/MWh in May, before improving but still under historical averages, with the 2020 average coming in at a low of 38€/MWh. That said, the relative resilience of the southern regions limited the aggregate yearly decline in demand at 6% in 2020. For 2021, we expect a modest 4% demand increase, which explains our expectations of some recovery in power prices. Because of subdued economic growth and continued energy savings efforts, we believe that average demand will reach 2019 levels again only in 2025.

Table 9

Key Power Companies We Rate In Italy
Company name Rating Total production 2020 (TWh) 2021 hedge 2022 hedge

Enel SpA

BBB+/Stable/A-2 41.2 85% at 51.7€/MWh 26% at 51.7€/MWh


BBB/Stable/A-2 18.1* 32% at 50.2€/MWh N.A.

Edison SpA

BBB-/Stable/A-3 20.6* N.A. N.A.
*2019 level. N.A.--Not publicly available. MWh--Megawatt hour. TWh--Terawatt hour. Source: S&P Global Ratings.

Table 10

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Spain
(€/MWh, Real 2019) 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 34.0 4.1 (6.4)
2021 39.9 3.2 (1.5)
2022 45.7 2.6 (1.2)
2023 50.7 0.0 (3.1)
2024 44.9 (4.0) (13.3)
2025 41.2 (4.1) (20.7)
MWh--Megatwatt hour. Source: S&P Global Platts.

Chart 10


Chart 11


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

Analyst: Gerardo Leal

Renewables dominate the mix and about 60GW additional green capacity to come by 2030

With 60 GW installed capacity at year-end 2020, renewables now represent about 55% of the country's total capacity and 44% of total production (which reached 250 TWh, 4% less than in 2019). Thermal production (mostly gas) now accounts only for 30% and nuclear for 22%. We expect renewables penetration will continue, as conventional thermal capacity is retired and replaced by more renewable capacity (wind and solar). During 2020, Viesgo Generacion, Endesa, Naturgy and Iberdrola closed seven coal-fired power plants equivalent to 4.6 GW. We expect the rest of Spanish coal capacity to be phased out during the next two years as the economics for coal across Europe become less favorable.

In its national energy strategy, outlined in the PNIEC (Plan Nacional Integrado de Energía y Clima), Spain targets to generate 74% of its electricity with renewable sources by 2030, with an estimated €241 billion in related investments between 2021 and 2030. To reach this goal, the plan targets big changes to its energy mix toward 2030, with total capacity increasing to 161 GW from 110 GW today: PV and thermo-solar (to 46 GW from 13 GW), wind (to 50 GW from 27 GW today), and hydro (to 25 GW from 20 GW), while gas will remain broadly stable (27 GW of CCGT) and nuclear will decline to 3 GW from 7 GW today.

Spanish regulation continues to align incentives to accelerate the energy transition

Besides publishing the PNIEC in early 2020, the Spanish government has been laying the groundwork for accelerating the deployment of renewable energy in the country, after decelerating since the last auctions in 2017. During 2020, the Spanish government announced the mechanism for a new series of tenders that aim to increase wind and PV capacity by at least 8.5 GW and 10 GW by 2025. The winning bidders will be remunerated on a pay-as-bid basis, resulting in a fixed price over a period of 12 years for wind and solar projects. While much shorter than in past subsidy schemes and compared with other frameworks in Europe, we believe the mechanism still provides a fair degree of visibility on returns. The first auction, which offers 3 GW of capacity (at least 1 GW of wind and 1 GW of PV) will close on Jan. 26, 2021.

The initiatives approved last year also aim at facilitating the allocation of grid connection rights for new wind and solar capacity on a "first-come first-served basis." We believe this could alleviate one of the key hurdles to renewables growth in the country because uncertainties about timely access to connection points is jeopardizing a number of projects. Other initiatives include incentives for the efficient start of project execution, which we believe will reduce the project backlog. In addition, the new law will allow producers to deal directly with the grid operator and therefore lower intermediation costs. In our view, the result of this and the liberation of connection points from the phaseout of coal generation will be smoother integration of new renewable capacity to the grid.

To reduce the cost of energy transition for the consumer, the Spanish government aims to transfer part of the cost of renewables subsidies to the oil and gas sector from electricity operators. These costs represent about 16% of the household energy bill. While still in the consultation phase and likely to be gradually implemented over several years if passed, in our view the plan could further support the country's electrification ambitions.

Chart 12


Gas will remain the price-setting technology in Spain for the next several years

Spain's wholesale power price is determined starting from the most expensive technology (latest necessary to satisfy demand), with all bidders receiving the price of the latest entrant. This, coupled with Spain's relatively small interconnection capacity with France (3 GW) and still oversupplied capacity, is why gas is the price-setting technology in Spain, while more expensive coal plants remained almost unused in Spain last year. We believe that increasing penetration of renewables in the energy mix will further contribute for gas remaining the price-setting technology in the next few years, given their intermittency and gas favored position as back up generation. However, this could gradually change between 2023 and 2025, when we expect prices to decline in real terms, as an increasing amount of wind and solar capacity with low marginal cost gains in relevance in the overall generation mix. We expect this will also introduce more volatility in power prices.

The COVID-19 pandemic will continue depressing power demand over 2021

Spanish electricity demand declined 5.6% in 2020 from 2019 mainly because of the COVID-19-induced drop in economic activity, mainly in the services sector—that includes the hard-hit tourism sector. The two lockdowns reduced power demand an annual average 13% between April and June 2020 from the 2019 level, and again 12% during the second lockdown in November 2020. At the same time, average prices dropped about 29%-30%, because of a decline in demand, combined with relatively inflexible renewables output in a strong hydro year, and lower gas prices.

Record-low temperatures in January 2021 picked up prices and CCGT load factors, but we think that will be temporary. We expect subdued economic activity to continue to suppress power demand in 2021, with the pace of recovery depending on the rollout of vaccination campaigns. We do not expect a full recovery in power demand until after 2023. We nevertheless see power prices recovering in 2021 on the back of higher gas 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, with its flat generation profile, would be more exposed to the merchant environment, because new solar capacity would alter its load factor and captured price. In addition, under the current market conditions, we expect gas-fired plants to consolidate their increase in load factors in 2021.

Table 11

Key Power Companies We Rate In Spain
Company name Rating Total production in 2020 (TWh) 2021 hedge 2022 hedge

Iberdrola S.A.

BBB+/Stable/A-2 58.6* 100% 60%

Endesa S.A.

BBB+/Stable/A-2 73.9 96% at €74/MWh§ 43% at €71/MWh§

EDP - Energias de Portugal S.A.

BBB-/Stable/A-3 37.1* 100% at about €45/MWh N.A.

Naturgy Energy Group S.A.

BBB/Stable/A-2 25.7 N.A. N.A.
*As of 2019, including Portugal and Spain. §Retail price. N.A.--Not publicly available. MWh--Megawatt hour. TWh--Terawatt hour. Source: S&P Global Ratings.

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

Analysts: Per Karlsson and Daniel Annas

We see improving price developments for 2021 onwards, yet with above-average volatility.

We expect more volatile power prices in the Nord Pool European power exchange than normal in 2021 and 2022, but with a general upward trajectory. This comes after a dramatic fall in power prices during 2020, which averaged about 11€/MWh, with some negative prices during the year, reflecting a generally oversupplied market. Production increased 3.9% in 2020 to 402 TWh, exceeding demand by 23 TWh, which was down 2%. Rather than COVID-19 impacts, warmer weather mostly accounted for the lower demand, with the average winter temperature in 2020 about 3 to 5 degrees Celsius warmer than normal. Industrial production remained high throughout the year, with a limited impact on household consumption.

The uptick we forecast for 2021 is notably supported by our assumption of a gradual normalization of power demand on the back of more normal weather conditions, as well as less extreme hydrological conditions than in 2020. On average we assume prices around €25-€35/MWh during 2021-2022 and €30-€40/MWh on average during 2023. This is a slight upward revision from our previous estimates in June 2020.

We expect larger volatility in power prices. This is driven by weather sensitivity given more intermittent renewables capacity and generation. Renewable generation is more impacted by weather conditions, coupled with conventional generation closures:

  • The hydrologic balance was higher than normal in 2020, well above average as the system was flooded due to mild and wet weather. As hydro power remains the main source of power production, we expect hydrological conditions to continue to shape power prices in 2021, but to a less extent as water levels normalize.
  • The expansion of wind capacity continues rapidly in the region, notably in Sweden, where capacity increased by about 1.6 GW in 2020 to reach 10.6 GW, resulting in wind power generation of about 28 TWh, up almost 50% from 2019. In Norway, the production from wind increased almost 80% to 9.9 TWh during 2020. We expect more wind projects to be commissioned, mainly in Sweden and Denmark, and to a lesser extent in Norway and Finland.
  • In the meantime, Sweden shut about 1.6 GW of nuclear capacity from the Ringhals 1 and 2 plants operated by Vattenfall.

From 2023, we anticipate increasing price convergence with Continental Europe, as large interconnection capacity (totaling 2.8 GW), between Norway and Germany and Norway-U.K., will be commissioned over 2021-2022. We believe this should ease the supply-demand imbalance because Norway will then be able to export more of its excess capacity.

Chart 13


Chart 14


Despite the rapid increase in renewables, which has outperformed demand growth, we expect the hydro system to be one of the main contributors to the price mechanism in the Nordic power system, except for the coldest months when consumption increases massively, and because fossil and biofuel still remain the price-setter. Hydro generates by far the largest share of power and has very low operating costs. The system is still dependent on fossil fuel during normal winter months, which adds to price volatility. Due to large amounts of snow during 2020, the current hydrological balance remains high, and at the beginning of 2021 the storage capacity was about 80% compared with 60% normally.

We expect continued healthy hedge ratios for generators, but hedges signed during 2020 could hurt price realization in 2021

Generators in the region hedge their output to various degree to protect cash flow. We typically see the hedges as credit positive because they offer greater cash flow stability, and that will be increasingly important as prices become more volatile. We expect most generators to achieve higher effective prices in 2021, even though some hedges were signed in 2020 when prices were lower.

We expect Statkraft to achieve the highest realized prices this year because its hedge levels are a relative low 10%, and since spot prices improved rapidly in the first quarter, which should result in a large upswing in cash flow compared with 2020.

Table 12

Average Nordic Power Prices
€/MWh 2018 2019 2020E 2021F 2022F
Prices 44 39 11 25-35 30-40
E--estimate. F--forecast. MWh--Megawatt hour. Source: S&P Global Ratings.
Some areas have excessive supply, but others have shortages

Despite the oversupply of power in the Nordics, some areas witnessed significantly higher prices in 2020, typically as a result of insufficient transmission capacity to those areas. Therefore, system prices have been less relevant for some areas. One example is the southern part of Sweden and Finland, where prices were much higher than spot prices reported by Nord Pool. The Nordic TSOs (transmission system operators) have many interconnector projects in the pipeline to lessen such issues. Nevertheless, we expect these issues to remain over 2021-2022 because transmission capacity improvements will occur gradually in the coming years. Interconnector capacity is planned to expand about 94%, from 6.9 GW in 2020 to above 13 GW by the end of 2023. This should align prices in various areas across the Nordic countries. However, it could also increase prices that generators achieve--because Nord Pool power prices are generally lower than in neighboring countries--and therefore push up Nord pool prices. In addition, we expect generators with the most flexible systems, such as Statkraft, to benefit from this increase in prices.

Renewable energy policies have not changed since our last report

We understand that Nordic countries will remain focused on adding renewable energy sources and making the power system more environmentally friendly, predominantly with more wind generation. This has somewhat contributed to recent price volatility, because the increase in renewable prices has outperformed demand growth. However, we expect this to normalize within a few years because of high demand growth. Older and smaller or midsize onshore wind power parks are likely to be more exposed to volatile prices and may not break even under our price assumptions because they typically generate less power than newer and more efficient parks. This as the compensation from subsidy schemes has declined to less meaningful levels. We note that even larger windparks suffered in 2020, for example Statkraft reported a large impairment on its Fosen wind project of about €250 million in 2020, when it was completed.

Table 13

Key Power Companies We Rate In The Nordics
Company name Rating Total production in 2019 (TWh)* 2021 hedge (%) on Sept. 30, 2020 Expected effective prices, including hedges and power purchase agreements (€/MWh) 2022 hedge (%) on Sept. 30, 2020 Expected effective prices, including hedges and power purchase agreements (€/MWh)

Fortum Oyj

BBB/Negative/A-2 45.5 75% at €33/MWh 30-35 40% at €32/MWh 30-35

Orsted A/S

BBB+/Stable/A-2 7 N.A. N.A.§ N.A. N.A.§

Statkraft AS

A-/Stable/A-2 61 N.A. N.A. N.A. N.A.

Vattenfall AB

BBB+/Stable/A-2 112 63% at €29/MWh 27-32 36% at €30/MWh 27-35

Uniper SE

BBB/Negative N.A. 85% at €28/MWh 27-30 55% at €24/MWh 27-30
*Data for 2020 was not available. §Offshore wind capacity in Denmark is fully contracted. TWh--Terawatt hour. MWh--Megawatt hour. N.A.--Not publicly available. Source: S&P Global Ratings.

Related Research

This report does not constitute a rating action.

Primary Credit Analysts:Massimo Schiavo, Paris + 33 14 420 6718;
Pierre Georges, Paris + 33 14 420 6735;
Secondary Contacts:Bjoern Schurich, Frankfurt + 49 693 399 9237;
Claire Mauduit-Le Clercq, Paris + 33 14 420 7201;
Matan Benjamin, London + 44 20 7176 0106;
Gustav B Rydevik, London + 44 20 7176 1282;
Gerardo Leal, Frankfurt + 49 69 33 999 191;
Per Karlsson, Stockholm + 46 84 40 5927;
Daniel Annas, Stockholm +46 (8) 4405925;
Emeline Vinot, Paris + 33 014 075 2569;

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