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The Energy Transition And What It Means For European Power Prices And Producers: September 2021 Update

S&P Global Ratings has raised its base-case assumptions for power prices by up to 10% in five of Europe's main markets over 2021-2023 from its January 2021 assumptions (see table 1). The reasons for the change are more supportive commodity prices and accelerated anticipated closures of conventional generation plants (notably nuclear and coal) in the next three years as part of the stringent decarbonization energy policies across Europe. At the same time, the pace of commissioning of new renewables projects and interconnections will not be sufficient to offset the loss of conventional capacity. This will tighten the supply-demand balance over the next three years.

We now see power prices recovering to 2019 levels in 2021, as they benefit from the rise in commodity prices seen since the beginning of the year, which led us to revise our forecasts for Title Transfer Facility (TTF) in 2021 to $15 per million Btu (/mmBtu) from our previous expectation of $8/mmBtu (for more information, see "Short-Term Gas Price Assumptions Raised On Robust Demand And Producer Discipline," published Aug. 13, 2021, on RatingsDirect). For generators, 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 even higher, more credit-supportive prices by 2022. A recovery in power prices in 2022 and 2023, to well 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. We expect European TTF gas prices to remain volatile because of the continent's declining production, more uncertain volumes of inflow from Russia, volatile carbon prices, massive storage capacity, well-developed gas infrastructure, and location, making it a natural market of last resort for global liquefied natural gas (LNG) flows, which are fundamentally exposed to global gas industry developments.

More importantly, solar and wind power will only gradually fill the gap, which implies tightening supply at least in 2022-2023. We also see ongoing hurdles to deploy and connect these new projects, including complex permitting process and network bottlenecks both to connect these new sites to the grid and to effectively transmit this power to areas of high consumption. This is, for example, the case in the U.K. and in Germany, where new wind capacity coming from the northern part of each country might face challenges to be distributed in more densified and industrialized southern areas. This supports our assumption of sustainably high power prices.

After 2023, we believe lower gas prices and accelerated commissioning of renewables will likely lead to a slow decline in power prices--despite our expectations of sustainably high carbon prices. Indeed, Europe plans renewables to increase to about 48% of the European electricity mix in 2030, from about 20% in 2020, 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
Country 2018 historical 2019 historical 2020 historical 2019-2021 Platts baseload power forecast 2021-2023 S&P Global Ratings' base-case assumptions*
2021 2022 2023
Germany 44.0 37.0 30.5 36-41 48-49 55-60 58-63
France 50.0 39.0 32.2 37-42 45-47 50-55 50-55
U.K. 65.0 49.0 39.6 43-50 55-60 58-68 64-75
Italy 61.0 52.0 38.4 48-53 49-52 56-61 62-67
Spain 57.0 48.0 34.0 41-50 47-52 57-62 55-60
*These are assumptions used in S&P Global Ratings' base-case scenarios and include a mix of hedges contracted by rated generators and forward prices. MWh--Megawatt-hour. Source: S&P Global Ratings.

Chart 1

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S&P Global Ratings' Baseload Power Price Forecast For Europe And The U.K.

Given conventional nuclear and coal plant closures, we believe gas and carbon prices after 2023 will play a bigger 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' ambition to establish 2030 targets, recently unveiled with the "Fit For 55" package, putting Europe on a net zero trajectory for 2050. This demonstrates European governments' recognition that the energy transition will play a pivotal role in Europe's economic recovery, with €225 billion of recovery fund to be invested over the next three years to support renewable investment and accelerate the electrification of heating and transport. However, we believe the growth of renewables will entail more weather-related price volatility. This was the case in August 2021, with record-low hydro levels, combined with an unprecedented surge in European gas prices and carbon dioxide (CO2) prices close to €60 per ton, lifting power prices well above €100 per megawatt-hour (/MWh) in Spain. Strength in gas and power prices could trigger social and political resistance, as it is already the case in Spain, with the government proposing a CO2 clawback on nuclear and hydro generation and, more recently, enforcing with a royal decree the temporary elimination of the windfall profits associated with high gas prices (up until March 2022). Also, energy transition theme will be key in the political debate, especially in France and Germany, which will hold general elections over the next 12 months. In addition, we believe more political risks as upscaled European environmental objectives might not fit well with national interests, as we saw in France's inability so far to strike a deal on its nuclear reform.

We believe the Fit for 55 package from the European Commission provides three solid drivers for power prices:

  • The assumed increased electrification of the economy, which implies sustained increase in power demand, especially after 2023;
  • More renewables in the system to support electrification; and
  • The recognition of the carbon price as one of the key political tools to reach the ambitious decarbonization targets, which also implies sustainably higher carbon prices, far from the lows from over the past decade.

Given the expected rebound in power prices in 2021, the largest merchant-exposed baseload producers such as Electricite de France S.A., Fortum Oyj, Uniper SE, and Verbund AG will see a substantial earnings' rebound in 2021. This was already the case in first-half 2021 for Finnish power generator Fortum Oyj, whose EBITDA from European power generation increased about 15% year-on-year. For EDF, recovering prices will be mitigated by the effects of subdued production over 2021-2022 because of maintenance issues for its nuclear fleet. We believe additional earnings will generally finance further transformation on generation fleets to best adapt to the energy transition, including more investments in renewables.

We also believe developers of renewables will benefit from the higher prices, notably as they aim to accelerate the corporate PPA market in Europe. Indeed, this helps signing long-term transactions with counterparties at a more comfortable strike price, generally below current market prices but allowing for a good margin above cost bases. This is further supported by a much increased demand for green power from corporates over the past 12 months, as they aim to demonstrate their own decarbonization efforts to stakeholders.

The expected rebound of power prices for 2021 for most integrated European utilities we rate should be more limited because the sensitivity of their EBITDA to merchant power has decreased markedly and because of power price hedges. Many have sold part of their merchant generation fleet and invested heavily in long-term contracted or subsidized renewable energy projects.

Conversely, we believe some suppliers could suffer significantly and see significant pressure on earnings, notably for smaller players that are short in power; and even some defaults as they could cease trading operations. This is already happening in the U.K., where at least five small alternative power suppliers defaulted recently as their financial liquidity dried. This could eventually benefit larger incumbents, because customers will need to return to last-resort suppliers. While harder to predict, large trading operations could also be affected from the severe volatility of commodity and power prices--both positively and negatively.

Table 2

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Germany (€/MWh, Real Terms, 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 77.1 (6.5) 3.4
2022 80.6 4.4 5.5
2023 81.8 6.2 4.3
2024 72.6 5.1 (6.3)
2025 65.8 6.5 (16.8)
2026 58.3 5.6 (27.5)
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

Primary credit analyst: Bjoern Schurich

The greening of Germany's energy sector will result in a gradual domestic supply shortfall over the next three years

We anticipate upward power price pressure to remain in the coming five years because of even more pronounced supply-demand imbalances paired with a lack of sufficient network expansion at least until 2026, notwithstanding successive buildout of cross-zonal interconnector capacities. For the same reasons, we anticipate the increasing need for balancing power and congestion management to weigh on consumers' electricity prices (via network fees). We believe both factors underpin highly flexible gas-powered generation as key transition technology over the medium term, driving wholesale market prices as per the merit-order effect and security of supply measures by network operators.

We anticipate flat domestic electricity demand, at about 600 TWh (540 TWh net) since 2000, to continue through 2025. Thereafter, we anticipate some increase due to the electrification of sectors such as heating, transport, and data centers, notwithstanding the mitigating effect of looming increasing energy efficiency, increasing flexibility (such as peaker plants, storage solutions, smart meters, and demand response), and increasing expansion of domestic and intercountry transport capabilities. With the introduction of non-Emissions Trading System (ETS) carbon prices for heat and transport in Germany, we expect electrification to accelerate and greater-than-expected electricity demand increase from heat pumps and EVs that should, in turn, trigger upward revision on renewable energy expansion targets no later than 2024.

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 30 GW capacity closure by the end of 2022 (for more information, see "The Path To Germany’s Coal Exit Has Diverging Credit Implications For Utilities," published Nov. 16, 2020). For the country's mandated coal phaseout timeline through 2038, we expect an accelerated development on the EU's ETS prices, rendering clean dark spreads (CDS) unattractive for commercial coal plant operations, keeping plants in an off-market grid reserve as determined by the German regulator. In addition, Germany's nuclear exit strategy will soon end: The remaining 8 GW capacity (14% of total net production) is scheduled to decline to zero by the end of 2022.

Renewable power now constitutes more than one-third of total net electricity generation (on average for 2020). However, the rapid increase in renewables will, even under optimistic expansion scenarios, not offset the drastic near-term closures of traditional energy sources such as coal and nuclear power, paired with much incentive for the accelerated electrification of other sectors. The recent increase in Germany's interconnector capacity serves as a meaningful mitigant, given sufficient domestic network transport capacities, which we anticipate will not be the case before 2026. Germany is in a net exporter position of 18 TWh in 2020, 34 TWh in 2019, and 49 TWh in 2018.

Beyond 2026, we anticipate domestic electricity supply-and-demand imbalances in the German price zone to relax, assuming:

  • Further penetration of renewables, paired with a buildup of intermittency mitigation technologies such as storage and power-to-gas capabilities;
  • The expansion of cross-zonal transport capabilities in conjunction with sufficient domestic transport capacities, enabling increasing international trade and cross-zonal grid balancing; and
  • Increased flexibility from the demand side, supply side and grid smartening (such as smart bundling and steering of prosumers) for which we expect for markets to create financial incentives. This should include retail customer flexibility applicable to home appliances, storage, heat pumps, and EVs.
The energy transition (and its cost) is at the heart of German political action

Derived from the EU greenhouse gas (GHG) emissions targets, the German energy landscape is undergoing a transformation to meet the country's ambitious goal of reducing GHG emissions. Specifically, CO2 targets as per the country's first national climate law set in 2019 were revised in 2021 to 65% by 2030, 88% by 2040, and climate-neutrality by 2050 compared with 1990 levels of all sectors including industry and transport. For 2020, Germany achieved its set goal of 40% (42.3%, up from 35.7% in 2019) due to exceptional COVID-19-driven lower demand. After setting up clear timetables for the nuclear, coal and lignite exits, we believe the upcoming country's federal elections (Sept. 26) could result in further acceleration of the energy transition to reach carbon neutrality, according to political parties' energy manifestos. All advocate accelerating growth of renewables and expanding hydrogen ambitions.

The cost of this transition is high and has so far been mostly borne by households. But this is changing now. High wholesale power prices and increasing surcharges, specifically for network expansion and renewable generation, increase pressure on politicians to mitigate the impact on household and commercial customers' electricity bills (wholesale power prices contribute about 30%), which are among the highest globally, at above 30cents per kilowatt-hour. As for now, the German government is capping the green power levy (the largest surcharge on power bills) at €65/MWh for 2021 and at €60/MWh for 2022, contributing about €11 billion from the federal COVID-19 measures budget. To retain public support for the energy transition, the government plans to abolish the renewable energy (EEG) levy altogether, replaced by proceeds from the country's additional national emissions trading system for heating and transport with a CO2 price of €25 per metric ton starting in 2021 and increasing to €55 per metric ton by 2025. Commercial consumers, specifically against recent developments of increased climate targets, even more so will be incentivized to procure long-term contracted green electricity (such as with PPAs) to remain competitive.

Renewables: From high ambitions to technical and local hurdles?

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 71 GW (55 GW), offshore wind to 20 GW by 2040 (7.7 GW), and biomass to 8.4 GW (8 GW). The law allows for ongoing adjustments to annual targets to accommodate the 65% target.

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 recovered somewhat to 2.7 GW in 2020--though falling short of a tendered 2.9 GW in 2020. This compares with an annual average of 4.6 GW of onshore installations from 2014-2017. If the trend persists, German renewables targets will become increasingly difficult to achieve. Next to permitting, real estate market conditions have become a prime consideration for onshore wind power expansion. Therefore, the country will need to streamline permitting and reduce regulatory barriers. In contrast, PV tenders are regularly oversubscribed.

The increasing penetration of renewables will exacerbate the volatility of power prices. Germany has experienced short periods of negative power prices before (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. 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 are 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. Long-term contracting via PPAs will become more crucial for producers and off-takers alike. Correspondingly, we observe increasing market appetite for green energy for commercial and industrial off-takers, 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," published Nov. 16, 2020).

High power prices are driven by gas prices and ultimately gas import limitations

We anticipate power prices will remain high over the next six months. This is mainly from high gas prices and recovering economic activity. In August 2021, German wholesale power price (day-ahead volume weighted average of €82.70/MWh) surged 137% year on year, the highest August prices since 2008.

Current lower renewable generation levels are set to increase compared with conventional generation, which supports electricity prices against rising commodity prices. At the same time, we observe fuel switch to lignite and coal due to tight gas markets, despite record high EU carbon allowance prices (German gas generation was down to 2.37 GW Aug. 22 from 5.9 GW the day before) on high gas prices. Natural gas markets witnessed a strong rebound, supported by recovering economic activity plus weather-related events such as first-quarter cold spells, followed by colder-than-average temperatures, while increased demand was not matched by increase in gas flows from Russia or global LNG. What's more, since the end of July, natural gas flows from Russia to Europe have decreased. As a result, Germany's gas storage levels (currently at about 60% of available capacity compared with 33% under its five-year average) are marking all-time lows in second-half of 2021 after all-time highs in 2020. We believe Europe's natural gas storage deficit won't change before December, even if the continent were to benefit from a record-high LNG import and Russian Nord Stream (NS2) volumes. That said, Asian LNG is signaling competing demand at higher prices and a recent court ruling in Germany postulates for NS2 to be governed under German regulation by the Federal Network Agency (Bundesnetzagentur), which could push back the commencement of commercial gas flows from Russia to beyond 2021.

We expect gas prices to remain high as Europe enters the winter heating season, which could support the fuel switch to coal/lignite. After this, the potential commercial start of NS2, and lifting of LNG market competitive pressure from Asia, India, or Mexico, the imbalance could relax in 2022 and beyond (see "Short-Term Gas Price Assumptions Raised On Robust Demand And Producer Discipline," published Aug 13, 2021). Against tailwinds to EU carbon prices, this should support fuel-switch to natural gas from coal, which we believe will become the sustainable driver for European power prices as per the merit-order effect.

Beyond power prices, how can generators remain profitable?

We believe Germany will likely introduce flexibility means via incentives or capacity agreements. 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, CHP generation, and storage solutions such as batteries and power-to-x. Furthermore, we expect the introduction of financial incentives for industrial, commercial, and retail demand side (including prosumers) flexibility. Decarbonization needs should boost business demand for customer solutions segments.

With renewable energy generation continuously expanding, lignite and hard coal generation dropped to 92 TWh and 43 TWh, respectively, in 2020, compared with 114 TWh and 57 TWh, respectively, in 2019. We believe this should give hard coal plant operators incentive to use voluntary auctions to decommission hard coal plants before 2027, notwithstanding the fuel switch to coal and lignite.

After closure, companies could derive value from transforming the plants or sites. Given the real estate scarcity in Europe, specifically Germany, we anticipate opportunities in repurposing of coal and other brownfield sites for industrial--and security of supply--solutions, including renewable generation and other power assets. Converting these sites to greener usage, such as efficient gas plants, waste incineration, commercial scale storage solutions, data centers, biomass, or other renewable generation, faces low permit hurdles and likely limited public opposition.

Table 3

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

E.ON SE

BBB/Stable/A-2 ~30/~30 96% at €45/MWh 74% at €47/MWh

EnBW Energie Baden-Wuerttemberg AG

A-/Stable/A-2 N.A./N.A. 90%-100% 50%-70%

Uniper SE

BBB/Stable/-- N.A./N.A. 100% at ~€46/MWh 90% at €49/MWh

Verbund AG

A/Stable/-- N.A./N.A. N.A. N.A.
MWh--Megawatt hour. TWh--Terawatt-hour. N.A.--Not available. Source: S&P Global Ratings.

Table 4

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For France (€/MWh, Real Terms, 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 79.4 (4.3) 5.8
2022 80.6 4.4 5.5
2023 80.9 5.3 3.4
2024 70.5 3.0 (8.4)
2025 61.6 2.4 (21.0)
2026 55.7 3.1 (30.1)
MWh--Megawatt hour. Source: S&P Global Platts

Chart 4

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Chart 5

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

Primary credit 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 (444 TWh of gross consumption in 2020). The country's energy law and the updated 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, following the closure of the Fessenheim plant last year, nuclear reactor closures will start in 2027 at 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, that capacity growth will be paced in conjunction with export needs to avoid overcapacity and strained prices.

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

The pandemic and related social-distancing measures, combined with a warmer 2019-2020 winter, decreased electricity consumption by about 5.4% in 2020, at the lower end of our 5%-7% forecast. The pandemic had a relatively lower impact on demand in France compared with the U.K., but about the same magnitude in percentage terms than Spain and Italy, despite France's lower share of industrial demand, which was severely affected by the first lockdown. At the peak of the lockdown in April 2020, total demand dropped by 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 electrification of industry and e-mobility trends. Electrification of the industry and housing in France is already high compared with that of 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 EVs will not radically change demand patterns in the next decade. EV sales in France more than doubled in 2020 (111,000 units from 43,000 in 2019) but still represent less than 7% of new car sales.

Contrary to neighboring markets, the pandemic heavily affected availability of supply in France. In second-half 2020, EDF revised upward its annual nuclear output target for its French fleet ultimately to 335 TWh (from the initial guidance of 300 TWh in mid-April). This compares with 375-390 TWh historically and reflects EDF's need to adjust its maintenance schedule considering operational disruptions caused by the lockdown and the reduced power demand.

While production for 2020 was significantly down, EDF also guided that the sequencing of the reactor outages will only result in a progressive recovery of its nuclear power output. It recently increased its guidance to 345-365 TWh for 2021 but retained the lower range indication of 330-360 TWh for 2022, given the high number of 10-year lifetime extension inspections already scheduled. Combined with demand recovery, we expect power prices to gradually recover in France over 2021-2023, following a dip in 2020 (€32/MWh on average) on a restored balance between supply and demand progressively rising to €50-€55/MWh in 2022 and 2023 from €45-€47/MWh in 2021.

Beyond 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. French net exports will increase with new interconnections coming online: 2.0 GW with the U.K. (IFA2 and ElecLink) pushed to July 2022 and 1.2 GW with Italy (Piedmont-Savoy). Originally, these interconnections were due in 2020, but were delayed due to the 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 8 GW of nuclear capacity by end-2022, together with the withdrawal of about 5 GW of lignite capacity from the sector.

Reform of nuclear is a key unknown to power prices, although it has been postponed to after the presidential elections

The French government has been seeking over the past 12 months to reform its nuclear power sector, which suffers from structural issues.

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 tariffs (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 150 TWh under an option embedded in energy law. Therefore, ARENH plays a key role in retail electricity prices.

We understand the French government is still in talks with the EU to set up a new mechanism, introducing a high floor price for nuclear output, which would better reflect the total cost of nuclear. However, negotiations have been difficult. In our view, the timing of the reform remains uncertain, and it is unlikely that any agreement of principle can be reached before the presidential elections in April 2022.

High wholesale power prices raises affordability issues and risk of political intervention

The high wholesale power price market, if it remains at this level through 2021, could lead to a sharp increase in consumers' electricity bills (estimated at about 10%). The CRE adjusts the regulated tariff for households (Blue Tariff) every year for the electricity supply components of all power suppliers. While not as advanced as in Spain, where the government has submitted a claw-back mechanism project to stakeholders, the French government is also studying options to alleviate pressure on electricity bills, within the sensitive political context of presidential elections. One option would be to activate the cap of regulated ARENH tariffs for alternative suppliers of 150 TWh (from 100 TWh currently). Another option could be a tax benefit on energy savings (stemming from the lower public subsidies on renewables) redistributed to consumers. The pricing environment increases negative risk of political intervention to respond to affordability constraints.

Renewables play their own role in the energy mix and determining prices

France's energy transition law sets out ambitious growth targets. It aims to increase the share of renewables to 32% of electricity production by 2030 and 40% in 2040 from 23% in 2020. Solar production faces delays and it looks more challenging that it will meet its targets by 2023 (20.6 GW of installed capacity, up from about 10.0 GW as of 2019 and 11.5 GW at first-quarter-end 2021). We believe the increase will be even more gradual for onshore wind due to acceptability and permit issues slowing progress. Offshore wind projects under developments by EDF, ENGIE, and Iberdola are progressing. For instance, EDF has four projects with capacity of 2 GW (including 480 MW under construction), with commissioning expected from 2023-2027. 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 effect will be neutral over 2020-2023.

As part of its 2020 economic stimulus package, the French government unveiled an ambitious hydrogen plan aiming to deploy €7.2 billion of investments by 2030, including €3.4 billion by 2023 to foster generation technologies for green hydrogen. This includes €1.5 billion of capital to be deployed for building up electrolysis capacity of 6.5 GW. We anticipate these targets for developing green hydrogen will fuel further demand for renewables capacity additions in 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. From Oct. 1, 2021, the approved law regarding the retroactive cut for solar feed-in tariffs will come into force. The remuneration of projects commissioned from 2006-2010 will fall about 50% on the remaining lifetime of the solar plant (there should be no reimbursement of aid received). We understand this would apply to more than 700 contracts, representing a total cost of €400 million-€500 million per year, with cumulated savings for the French government over the next 10 years. The purpose is to allow for "reasonable" returns on capital on solar and photovoltaic installations as opposed to currently excessive returns. Savings from the cuts would also help support the expected tender of more than 10 GW of subsidized solar contracts over the next five years. 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, through 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-2 384.0 N.A. N.A.

ENGIE SA

BBB+/Stable/A-2 20.0 93% at 47€/MWh 64% at 49€/MWh
MWh--Megawatt-hour. TWh--Terawatt-hour. N.A.--Not available. Source: S&P Global Ratings.

Table 6

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For The U.K. (£/MWh, Real 2019)
£/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 86.6 8.3 9.2
2022 74.8 3.6 (3.0)
2023 72.6 2.6 (5.6)
2024 62.7 0.7 (14.8)
2025 55.6 1.4 (23.1)
2026 48.9 1.7 (30.8)
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, Prices, And Renewables: The View From S&P Global Ratings

Primary credit analysts: Julien Bernu and Gustav Rydevik

The U.K. has now more ambitious climate goals

This year, the government pledged to reduce carbon emissions by 78% by 2035 (compared with 1990 levels), which represents a major revamp of its energy policy and generation mix. This includes closing thermal plants and a rapid increase in carbon-free generation. By the end of 2023, we see a decline in coal capacity to roughly 2.0 GW (from 5.3 GW at end-2020) because from October 2022, Uniper's 2 GW Ratcliffe plant will be the only remaining coal plant in the U.K. During this time, we expect to see a sharp increase in solar and wind capacity, to about 44 GW in December 2023 from 36 GW in December 2020. The country also aims to remain the global leader in offshore wind. We expect wind generation to grow by more than 80% from 2020-2026 to about 42 GW of capacity from roughly 23 GW. Offshore projects will lead in the new developments, with the U.K. government targeting 40.0 GW of installed capacity by 2030, compared with 10.5 GW today. The U.K.'s fourth Contracts-for-Difference renewable energy auction in late 2021 aims for 12 GW of capacity. This round will include solar, onshore wind, floating wind, wave, and offshore wind; biomass conversion from coal will be excluded. The inclusion of floating wind, onshore wind and solar aims to increase the number of renewable project in the country.

The U.K.'s decarbonization strategy also relies on new nuclear capacity. Hinkley Point C is expected to come online by the end of 2026, providing an additional 3.2 GW of capacity; and the government is evaluating the construction of Sizewell C, for another 3.2 GW but would be completed only after 2030. However, with delays to new plants, capacity will decrease to only 2.5 GW by end-2025 from around 9.0 GW at end-2020.

At the same time, we anticipate gas-fired generation to continue playing a key role over the decade, given its still-high share of the production mix (about 40% in 2020) and its flexibility to manage intermittency of renewables. Gas-fired plants can be profitable by running at peak hours only, when prices are very high, and are supported by the capacity market that the U.K. implemented since 2014.

The transition means heavier near-term reliance on imports

With the decline in both coal and nuclear in the near term, the U.K. is likely to rely much more on net imports over the next four to five years, until new renewable and nuclear capacity satisfies the shutdowns. This year, an interconnector with France was added, and an interconnector with Norway is due to come online later this year for a combined additional 2.4 GW. We see net imports peaking as early as 2021, then gradually falling through 2025, at which point significant exports are expected during winter months due to the large increase in wind capacity. We also see the current capacity shortfall as creating additional tension on the network, and therefore prices. Indeed, the additional capacity from offshore wind and interconnection with Norway still need to be transported from north to south, meaning congestion and inertia management risks because the network still needs significant upgrade to manage the significant and intermittent flows.

The U.K. carbon market is now active

In the Brexit deal, the EU and U.K. committed to developing and implementing new and efficient trading arrangements by April 2022. The first step toward this came when the UK ETS replaced the country's participation in the EU ETS on Jan. 1, 2021. As of May 19, there are biweekly UK ETS auctions help; the same date also marked the commencement of trading of U.K. allowance futures. So far, the new UK ETS is pricing carbon allowances at a small discount to EU ETS, but we expect a reduction in the Carbon Price Support tax from 2023 to narrow the premium in total carbon costs for generators compared with its EU neighbors.

The surge in power prices is likely to continue over the next two years

Despite a third national lockdown and significant restrictions in the U.K. during most of the first half of the year, power demand has been robust, with demand rising by 14% for second-quarter 2021 compared with the same period the year before. In line with continental European markets, the increase has also led to exceptionally steep power price increases, with average day-ahead prices for second-quarter 2021 surpassing those of the same quarter in 2020 by 200%. On Sept. 13, the U.K. even recorded an all-time high day-ahead base of £540/MWh. This is not representative of the average spot prices this year (closer to £80/MWh), but the increase remains quite steep, compared with an average price of £40-£45/MWh over 2018-2020. This increase can be explained by several factors: an exceptional tightness on commodity and carbon markets, more capacity shutdowns, and below-average wind speeds leading to offshore wind output below expected levels. Over the next two years, we anticipate that the supply-demand balance will continue to be tight given baseload capacity shutdowns, which will support high prices, close to 2021 levels. We anticipate pressure will gradually ease as new renewables capacity is commissioned.

Affordability issues will remain a key political topic

Undoubtedly, the steep rise in household energy bills will remain top of the political agenda in the near term, not least in a context of inflationary pressure for goods and services amid a gradual economic recovery in the country. This also comes amid further questions regarding the financial impact of Prime Minister Boris Johnson's pledge to decarbonize the economy by 2050 for households and notably the replacement of gas boilers by more expensive electric heat pumps in a country heavily dominated by gas central heating households. In July, the U.K. government announced proposals for a new legislation that will create the option to extend the energy price cap beyond end-2023, the current limit. The proposals also incorporate the trial of automatic switching for standard variable tariff customers to foster greater competition. This will illustrate and potentially worsen the challenging operating conditions retail suppliers face.

Suppliers' exits will continue to fuel consolidation in the U.K. energy supply sector

The steep increase in energy costs also poses some further operational risks for smaller operators, who might not have hedged themselves well enough against rising wholesale costs, given more limited hedging abilities. Given that some of those smaller players often sell fuel below cost in an attempt to build customer books, this strategy further limits their ability to absorb rising wholesale energy costs leading to pass-through to household energy bills. Some market participants raised their prices this summer, which reduces the competitiveness of their offers vis-à-vis large and medium suppliers.

Undoubtedly, this situation will only accelerate a pattern observed since 2018, with a constant reduction in active energy suppliers: The numbers of players almost halved in the past four years (as of March 2021, there were 49 active suppliers, compared with 70 as of March 2018). This is because we project liquidity pressure to be particularly high in the sector for fourth-quarter 2021. Exceptionally high wholesale prices are only adding to more challenging debt collections given the end of some governmental supportive measures, but more importantly, to the expected large outflows linked to the payments of annual renewables obligation certificates (deadline for late payments set for September and October); a mispayment on the latter having historically been a good leading indicator of a supplier's potential future market exit. To date, Ofgem confirmed that seven suppliers left the market in 2021 (including four additional suppliers since the start of September), affecting about 2 million people.

Table 7

Key Power Companies We Rate In The U.K.
Rating  Total production 2020 (TWh) 2021 hedge  2022 hedge 

SSE*

BBB+/Stable/A-2  26.8 ~84% at about £49/MWh  ~58% at about £49/MWh 

Drax

BB+/Stable /-- 15.2 ~97% at about £51.7/MWh ~55% at about £52.4/MWh

InterGen (U.K.-based only)

B+/Stable /-- 9.0 ~5% ~5%

Scottish Power U.K. PLC

BBB+/Stable/A-2  6.8 N.A. N.A.
*Hedge position applies for U.K. wind and hydro generation assets only (for 8-10 TWh over the period) and for fiscal years ending March of the subsequent year. There is no publicly available information regarding thermal generation, which accounted for about 64% of total output in 2020. MWh--Megawatt-hour. TWh--Terawatt-hour. N.A.--Not available. Source: S&P Global Ratings.

Table 8

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Italy (€/MWh, Real Terms, 2019)
€/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 91.3 8.3 17.4
2022 85.6 8.1 10.5
2023 84.5 7.6 7.1
2024 75.9 7.1 (3.0)
2025 67.5 6.9 (15.1)
2026 60.8 6.8 (25.0)
MWh--Megawatt-hour. Source: S&P Global Platts

Chart 8

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Chart 9

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

Primary credit analyst: Massimo Schiavo

Power prices will remain higher than other European countries' due to the predominance of thermal power and increasing dependence on imports

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 coal power rapidly declining. Italy will benefit the most from the €750 billion EU recovery fund. However, we expect Italy's power prices to remain higher than those in other European markets by western European standards until 2025 due to structural undersupply. We expect a strong rebound in achieved power prices to about €50/MWh in 2021 (close to the 2019 level of €52/MWh) from the historical low of €38/MWh in 2020 driven by the increase in gas and carbon prices, with our expectations that prices will increase to more than €60/MWh over 2022-2025. This is 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. We expect this to benefit Italian integrated utilities we rate, notably Enel SpA, A2A SpA, and Edison SpA.

Interconnection capacity on the northern border should increase by 2.2 GW by 2025, including 1.2 GW with France (which should come online in autumn 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 from 2018 levels, with imports covering about 20% of demand from 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 2028. We expect the largest closures in 2021 and 2025, with about 3 GW of closures in each of those years (for installed capacity of 7.1 GW at year-end 2020). By 2026, the only remaining coal units will be the must-run plants in Sardinia where there are two coal plants, a 534 MW coal plant operated by EP and a 432 MW plant operated by Enel, both of which have been classified as essential by the Italian government. At least one of the two will be needed until the completion of the Tyrrhenian link with the mainland. 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 given slow permitting

We forecast that Italian wind and solar capacity will more than double to 19.9 GW and 34.3 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 expect the increase to come mostly from solar and onshore wind with permitting (notably competing with agricultural land) that could slow the rollover at the national level. The increase in renewables will not offset the impact of coal plants closures in Italy or the upside in demand from the electrification of transport, and, to a lesser extent, heating. This will lead to higher imports from neighboring countries, notably France and Switzerland. 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.

We expect a full recovery of power demand only by 2025

In 2020, due to the two waves of COVID-19-related lockdowns, power demand contracted by 6%. For 2021, we expect a modest 4.6% 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. This is later than the European average, with Italy benefiting less from demand electrification.

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 92% at 51.9€/MWh 99% at 60.7€/MWh

Edison SpA

BBB/Stable/A-2 18.1 N.A. N.A.

A2A SpA

BBB/Stable/A-2 16.8 65% at 52.5/MWh 28% at 59.4/MWh
MWh--Megawatt-hour. TWh--Terawatt-hour. N.A.--Not available. 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 85.0 (8.3) 11.2
2022 82.4 3.9 7.3
2023 79.1 1.2 1.6
2024 67.0 (2.7) (11.8)
2025 55.2 (6.3) (27.3)
2026 47.4 (7.5) (38.4)
MWh--Megawatt-hour. Source: S&P Global Platts

Chart 10

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Chart 11

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

Primary credit analyst: Gerardo Leal

Higher prices mean increased political intervention risks, which is already materializing

Spain's regulated tariffs are directly linked to daily power market prices, making them highly sensitive to price hikes, notably compared with other European pricing structures, which are instead based on longer periods. As a result, the recent surge in prices to more than €100/MWh has put immediate pressure on household energy bills--and raised the risk of political response. It started materializing just before summer and came in the form of proposed higher taxation of excess profits for power generators.

We now assume a windfall tax associated to high CO2 prices from 2022 onward, reducing profitability for nuclear and hydropower plants operators. Additional measures announced Sept. 14 by the Spanish government, with immediate effect, on the temporary elimination of the windfall profits associated with high gas prices could add even more pressure on power generators' earnings.

On June 2, 2021, the Spanish Ministry of Ecological Transition and Demographic Challenge published a law aiming to introduce a clawback tax on windfall profits from non-emitted carbon emissions captured in power prices from nuclear, hydro capacity, and wind assets installed before 2003. The initiative aims to mitigate the effect of increasing CO2 prices on consumers' bills (particularly in the regulated market. It highlights the increasing government intervention in the power market and its focus on affordability. To ease the pressure on final customers, the government also temporarily lowered the value-added tax on electricity bills to 10% from 21%.

The CNMC and State Council have approved the proposed CO2 windfall tax law, although the potential financial impact has been reduced during this process. We understand that the total impact for the sector is now estimated at about €625 million per year, from about €1.05 billion in the first draft. After an allegation period lasting until Sept. 17, 2021, the initiative will head to parliament for urgent approval, which we expect could occur before year-end. Once approved, this law would mostly affect Iberdrola SA, Endesa SA, Naturgy Energy Group SA, and EDP - Energias de Portugal SA.

Although still subject to changes and approval, we assume some form of CO2 windfall tax from 2022 onward. We expect the initiative will reduce EBITDA for Iberdrola, Endesa, Naturgy, and EDP from 2022 onward, although in different magnitude depending on each operator's existing pre-2003 nuclear, wind, and hydro capacity (see table 11).

Table 11

Rated Entities--Preliminary Carbon Dioxide Windfall Tax Impact
--Affected capacity-- --Financial impact--
Issuer Hydro (GW) Nuclear (GW) Wind (GW) Yearly EBITDA impact (mil. €) As % of total EBITDA
Iberdrola 9.7 3.2 1.8 250-270 2.4
Endesa 3.3 3.2 0.2 240-250 6.0
Naturgy 2.0 0.6 0.0 50-60 1.4
EDP 0.4 0.2 0.2 10-20 0.4
GW--Gigawatt. Souce: S&P Globlal Ratings

In addition, on Sept. 14, the Spanish government enforced through a Royal decree the temporary elimination of the windfall profits associated to high gas prices. The elimination is effective from Sept. 16, with a 30-day period for the Spanish parliament to approve it. If parliament does not approve it, it will be withdrawn.

The government sets a floor at €20/MWh for the gas price and aims to recover 90% of the windfall profits if gas prices are above the set threshold. According to the government, the financial proceeds from all the sector could amount to €2.6 billion in the coming six months. The total sector impact from the CO2 windfall tax (whose impact on companies is shown on table 11) and of the gas windfall tax could total €3.2 billion. However, the government suspended the 7% tax on power generation in third-quarter 2021, partly mitigating the potential negative impact.

Gas will remain the price-setting technology until at least 2025

Spain's wholesale power price is determined starting from the most expensive technology (the 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 are set to be fully phased out as renewable capacity increases. We believe that increasing penetration of renewables in the energy mix will further contribute to gas remaining the price-setting technology in the next few years, given their intermittency and gas' favored position as backup generation. However, this could gradually change from 2023-2025, 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. Also, the greater penetration of renewables will reshape hourly prices and increase volatility. We expect the downside pressures will contribute to squeeze profitability for combined-cycle gas turbine (CCGT) plants, particularly beyond 2023, highlighting the need for capacity market agreements to remain profitable.

This fluctuation could provide new remuneration opportunities to backup facilities (gas, hydro, and batteries). In fact, pump-storage facilities have benefited from releasing capacity on peak hours this year, when prices have reached record highs. On the other hand, 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.

Spain continues pushing for renewable capacity expansion aiming to achieve its energy targets by 2030

With 62 GW installed capacity as of September 2021, renewables (including hydro) now represent about 55% of the country's total capacity and about 50% of total year-to-date production (173 TWh as of Sept. 2, 2021, according to power transmission system operator). Thermal production (mostly gas) now accounts only for 28% and nuclear for 22%. We expect renewables penetration will continue, as conventional thermal capacity is retired and replaced by more wind and solar capacity. We expect Spain's coal capacity to be almost fully decommissioned beyond 2021, mostly due to poor business conditions for coal amid increasing CO2 prices, with the only exception being EDP's Aboño 2 535 MW coal power plant.

In its national energy strategy, outlined in the 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 from 2021-2030. To reach this goal, the plan targets big changes to Spain's 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). Gas will remain broadly stable (27 GW of CCGT) and nuclear will decline to 3 GW from 7 GW today.

We believe that the recently unveiled Fit For 55 package could boost renewable development in Spain even further, since the more ambitious European goals come in parallel with an increasing need of renewable capacity, targeted at 40% of the mix by 2030 from 32% before. Also, the EU commission will enact a social climate fund, by which €72 billion will go to European countries with a higher share of vulnerable households, with the aim of mitigating the Fit For 55 package's regressive effects. Spain is one of the key beneficiary countries and would receive about €7.6 billion, or about 10.5% of the fund's total, which will be dedicated to promoting cleaner energy solutions in the country, including the integration of energy from renewable sources.

As part of this momentum, the Spanish government continues laying the groundwork for accelerating the deployment of renewable energy in the country. In 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 10.0 GW by 2025. The first auction was successfully closed in January 2021, allocating 67% to PV capacity and about 33% to wind onshore, with average price of €25/MWh and lowest accepted bids at €14.9/MWh and €20/MWh for PV and onshore wind, respectively. On Aug. 16, 2021, the Spanish Ministry announced a second tender for 3.3 GW, 600MW of which the government expects to be operational by end of 2022.

The winning bidders will be remunerated on a pay-as-bid basis, resulting in a fixed price over 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.

Growth in renewables repositions Spanish power market in Europe

The acceleration in renewable capacity deployment will have two material consequences in the Spanish market. On one hand, it will facilitate the country turning into a net exporter from 2023 onward. On the other hand, we believe an increasingly longer Spanish generation fleet with increasing power price volatility will make Spain one of the most PPA-driven markets in Europe.

Achieving favorable PPA contracts will remain one of the key competitive factors for existing and new operators as the market expands, with accumulated know-how turning an increasingly relevant advantage. Given current prices, we believe there are significant near-term opportunities for capacity coming online under PPA contracts. Some utilities aim to benefit from this by accelerating its renewable pipeline or trying to buy projects in advanced development stages. However, the increasing appetite for renewable capacity will contribute to reduce Spain's baseload power prices to one of the lowest in Europe toward the second half of this decade, pushing down PPA contract prices eventually.

Table 12

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 59.9 100% 0.8

Endesa S.A.

BBB+/Stable/A-2 73.9 100% at €71/MWh§ 74% at €74/MWh§

EDP - Energias de Portugal S.A.

BBB/Stable/A-2 35.4* 100% at about €45/MWh 100% at €57/MWh

Naturgy Energy Group S.A.

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

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

Primary credit analysts: Per Karlsson and Daniel Annas

From record lows in 2020, power prices in the Nordic region have rebounded stronger and much quicker than expected to start 2021. Nord Pool System spot prices are currently up about 10x but have averaged close to €50/MWh year-to-date, compared with €11/MWh for 2020, albeit with large differences between countries and price zones. Power producers that have not hedged a material part of their production are therefore likely to report a material upswing in earnings this year. The dramatic change in hydrological balance, from a surplus to a deficit; lower wind speeds; better export capability to continental Europe, which sees higher power prices due to greater fuel-based production costs; and increasing CO2 emissions are the key factors in the upswing. We observe that prices have been abnormally high over the summer months, somewhat unusual in a region that consume most electrical power in the colder winter months. In recent weeks, hydro reservoir levels shifted to below normal because of less precipitation than usual. This indicates that the prices could be materially higher over the coming winter period, if the trend continues. Prices in September have so far averaged a record high €84/MWh, albeit likely affected by a weaker hydrological balance; lower nuclear power production, as Ringhals 3 and 4 in Sweden and Loviisa 1 and 2 in Finland are not at full capacity; and very high emission prices. Price differences between different regions continue to be high, which signals a lack of transportation capability and a generally tight power system in the area. In line with our expectation, however, power prices in the region have turned more volatile. The share of weather-dependent production varies significantly from day to day. We expect this trend to continue in the Nord Pool European power exchange, as more weather driven production comes on stream, mainly wind power.

We expect volatility to become the new norm as the system becomes more weather-dependent, and because export capacity has increased, and will continue to do so through the next few years. Although we have a positive view of medium-to-long term prices, volatility is set to remain high. We therefore think good execution on hedging strategy will become increasingly crucial to reduce volatility and secure cash flow.

We see material changes for the Nordic power, which slowly but steadily will affect the power balance and prices:

  • The capacity increase in Finland. Although TVO's Olkiluoto 3 (OL3) is still not operating, owing to the recent three-month delay making the plant more than 12 years delayed overall, its likely to start production in 2022. The generation capacity of 1,600 MW should substantially reduce the current import need of power in Finland, implying less or no need to import power from Sweden and Norway. As we understand it, OL3 at full capacity should produce approximately 10% of Finland's total consumption.
  • Further export cables under construction, likely leading to power prices approaching European levels. In first-quarter 2021, the NordLink cable between Norway and Germany entered operations, and before year-end 2021, the North Sea Link between Norway and U.K. is set to start operations. All in all, interconnection capacity will increase the Nordic export capacity to over 13.0 GW by end-2023 from 6.9 GW at end-2020. The main connections are the NordLink that increases connections with Germany (with 1,400 MW of capacity that started in May 2021), the North Sea Link between Norway and the U.K., and Viking Link between Denmark and the U.K. (1,400 MW, entering service at end-2023). Further connections are possible over the medium term, but more uncertain. The German-Nordic spread remained high at around €18/MWh in 2021. The NordLink cable has yet not been used at full capacity, because there appears to be some technical limitations on the ability for the increased capacity.
  • Healthy medium-term demand. There are several large industrial projects under construction, mostly in northern part of the region, and consumption growth is therefore set to increase more rapidly than historical levels. Although power production today is somewhat concentrated in the northern part of the region, without further additions of capacity, this could further squeeze the balance in the system. This includes data centers, battery production, and heat pumps; but also energy-intensive sectors such as fossil free steel production, which are under pressure to decarbonize their industrial process by using more electricity and green hydrogen. The penetration of EVs is higher than other regions--in Norway, 50% of all cars sold have an electrical power line. Although demand growth is difficult to predict, it will likely outperform the historical average over the next decade. Various industry experts expect as the growth can be 100 TWh or more through 2030, which implies a heavy growth rate as total demand now stands at about 400 TWh.
  • Uncertainty about repository for nuclear waste in Sweden, which could affect nuclear production. Politicians have not decided the final repository of nuclear waste in the country. Although not our base-case scenario, the power producers running the plants has already warned they might be forced to close production around 2024 absent a final decision. At about 17% of production in the region, this could reshape the power market.

With a strong rebound in power prices to start the year, we revised upward our forecast for 2021 and 2022, to €50-€55/MWh from €25-€35/MWh. This is a major revision but was triggered by a much more rapid change of hydrological conditions, which is a main factor for prices in the region; low nuclear production; and increased fossil fuel and CO2 prices, which led to rapidly increasing power prices in September 2021. Hydro reservoir levels in the system were even lower than normal, at below 70%, which is materially less than a year ago when the levels were around 90%. Hydro power remains the main source of power production, so we expect hydrological conditions to continue to shape power prices in 2021. On average, we assume prices of €45-55/MWh in 2022 and €30-€40/MWh in 2023. This is a material upward revision from our previous estimates in January 2021, but signals the increased system volatility; in addition, prices for fossil-based production continue to affect prices in the region.

Chart 12

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Despite the rapid increase in renewables, which has outperformed demand growth, we expect the hydro system to continue 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, when fossil and biofuel remain the price-setter. Hydro generates by far the largest share of power in the region and has very low operating costs. The system is still dependent on fossil fuels during normal winter months, which adds to price volatility.

We expect Statkraft to achieve the highest realized prices this year, and profit levels to lift materially compared with a year earlier. This is because its hedge levels, including long-term industrial contracts, are relatively low at 35%, which should result in a large upswing in cash flow. While the strategy with relative low hedging levels appears risky, 85% of Statkraft's productions come from hydro production which means that production costs are very low.

Table 13

S&P Global Ratings' Price Assumptions For The Nordic Region
€/MWh 2018a 2019a 2020a 2021f 2022f 2023f
Prices 44.0 39.0 11.0 50-55 40-50 30-40
MWh--Megawatt-hour. a--Actual. f--Forecast. Source: S&P Global Ratings

Chart 13

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Table 14

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

Vattenfall AB

BBB+/Stable/A-2 112.8 69% at €28/MWh 35-40 73% at €28/MWh 35-40

Statkraft AS

A-/Stable/A-2 65.4 N.A. N.A. N.A. N.A.

Fortum Oyj

BBB/Stable/A-2 59.2 75% at €33/MWh 30-35 60% at €31/MWh 35-40

Orsted A/S

BBB+/Stable/A-2 7.0 N.A. N.A.§ N.A. N.A.§

Uniper SE

BBB/Stable/A-2 N.A. 90% at €26/MWh 25-30 85% at €24/MWh 22-27
*Exluding Uniper §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;
Massimo.Schiavo@spglobal.com
Pierre Georges, Paris + 33 14 420 6735;
pierre.georges@spglobal.com
Secondary Contacts:Bjoern Schurich, Frankfurt + 49 693 399 9237;
bjoern.schurich@spglobal.com
Claire Mauduit-Le Clercq, Paris + 33 14 420 7201;
claire.mauduit@spglobal.com
Gustav B Rydevik, London + 44 20 7176 1282;
gustav.rydevik@spglobal.com
Julien Bernu, London + 442071767137;
Julien.Bernu@spglobal.com
Gerardo Leal, Frankfurt + 49 69 33 999 191;
gerardo.leal@spglobal.com
Per Karlsson, Stockholm + 46 84 40 5927;
per.karlsson@spglobal.com
Daniel Annas, Stockholm +46 (8) 4405925;
daniel.annas@spglobal.com
Emeline Vinot, Paris + 33 014 075 2569;
emeline.vinot@spglobal.com

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