S&P Global Ratings has raised its base-case assumptions for power prices by more than 10% in five of Europe's main markets over 2022-2023 from its September 2021 assumptions (see table 1). The main reason for this change is higher anticipated commodity and notably gas prices for at least the next 12-18 months. We hence revised our forecasts for Title Transfer Facility (TTF) in 2022 to $20 per million Btu (/mmBtu) from our previous expectation of $12/mmBtu (see "S&P Global Ratings Revises Oil And Natural Gas Price Assumptions For 2022-2024," published Jan. 20, 2022, on RatingsDirect). We expect European TTF gas prices will remain volatile, because of the Continent's declining production, more uncertain volumes of gas 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 flows, which are fundamentally exposed to global gas industry developments.

This high global commodity price environment comes with an acceleration of anticipated closures of conventional generation plants (notably nuclear and coal) in the next three years as stringent decarbonization energy policies are implemented across Europe. At the same time, we believe the pace of commissioning new renewables projects and interconnections will be insufficient to offset the loss of conventional capacity. We believe solar and wind power will only gradually fill the gap, implying a tighter supply-demand balance over the next three years and greater use of gas in the meantime. As a result, we expect that the energy transition will not be smooth over this period, with a still-high dependency on volatile global gas prices.

Beyond 2022, we expect power prices will remain relatively high, supported by demand-supply imbalances. Yet by 2023, we believe lower gas prices will likely lead to a slow decline in power prices--despite our expectations of sustainably high carbon prices. That said, power prices well above 2019 levels for the next three years should underpin earnings for merchant power generators, notably those who provide carbon-free baseload power, such as nuclear or hydro.

We expect power prices will normalize only post-2025, when more significant renewable capacity will be commissioned. At that time, renewables will represent a more substantial portion of the European power production mix (about 45% in the U.K., Germany, and Spain, and about 20% in France and Italy compared with about 30% and 15% today, respectively) and therefore have a higher weight in power price formation. By 2030, Europe plans to increase renewables to about 48% of the mix from about 20% in 2020, excluding hydro's 10% share.

Despite the jump in renewables capacity expected in the next decade, we see a high likelihood that EU countries will fail to achieve their 2030 renewable installation targets. Hurdles to deploying and connecting these new projects include complex permitting processes and network bottlenecks--both in terms of connecting new sites to the grid and effectively transmitting power to areas of high consumption. This, for example, is the case in the U.K. and Germany where new wind capacity from the northern part of each country might face challenges being distributed in the more densely populated and industrialized southern regions. We also believe rapidly deploying capital and projects at such a large scale remains challenging, especially for the supply chain, which will have to keep pace. Supply chain expansion will depend on further developing industrial output, securing imports, and managing transportation, since many components and raw materials are currently sourced from China, with few alternatives. Another constraint we see is land availability (notably for onshore technologies) and the increasing focus on natural capital preservation, which was a key theme at the UN Climate Change Conference (COP26) at the end of 2021. This may add another layer of complexity for renewable project developers. Given the long list of unresolved hurdles, we believe achieving total installed capacity targets may be delayed beyond 2030.

The anticipated growth of renewables in the energy mix and the technologies used to achieve decarbonization add uncertainty to the power price evolution toward the second half of the decade. This is due in particular to:

• Cannibalization risk, which is the risk of wholesale power prices falling from times of high output from intermittent renewable generation (e.g., if solar generation, which is concentrated only during daylight hours, takes too large a share of the mix);
• Increased dependence on weather conditions and, as a consequence, the need for significant backup facilities or efficient storage solutions, which could throw into question the overall system cost and optimal energy mix; and
• The still-uncertain evolution of demand, in terms of growth and volumes, notably through the potential rise of electrified usages, such as the adoption of heat pumps, which may significantly change power demand curves.

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 And The U.K.: S&P Global Ratings' Historical And Base-Case Projections In MWh
	Historical				S&P Global Ratings' base-case assumption*
Country	2018	2019	2020	2021	2022	2023
Germany	44.0	37.0	30.5	97.0	55-60	63-68
France	50.0	39.0	32.2	109.0	55-60	62-67
United Kingdom	65.0	49.0	39.6	138.0	75-85	70-80
Italy	61.0	52.0	38.4	125.0	60-65	75-80
Spain	57.0	48.0	34.0	112.0	60-65	65-70
*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-hours. Source: S&P Global Ratings.

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

As mentioned above, power prices are likely to remain high and volatile, due to the increased dependence on gas prices and more structural tightness in the supply-demand balance. Yet elevated gas and power prices could present social and political challenges. This was already the case in Spain, where the government proposed a carbon clawback on nuclear and hydro generation, which has yet to be voted on in parliament. More recently, we have seen government measures to offset the impact of rising power prices on end consumers also in Italy and France. We believe European markets are generally more socially and politically sensitive to high bills than the U.S. (see "European Electric Utilities Face Higher Social Risks Than Their U.S. Peers," published Oct. 13, 2021).

For most integrated European utilities we rate, the relatively high power prices we expect over 2022 should only have a limited impact on earnings. This is because the sensitivity of their EBITDA to merchant power has decreased markedly and because of power price hedging policies, which for many is close to 100% for 2022. In addition, most utilities have moved away in recent years from merchant power by expanding in long-term contracted renewables. As a result, we anticipate more earnings upside in 2023 for power generators, since they benefit from better strike prices on their future hedges. We see that hedging positions are generally below 50% of volumes for 2023. We note that such upside could be somewhat mitigated by the planned (or unplanned) closures of some of their baseload capacity, as mentioned above, as well as political interference, including the introduction of some special energy taxes.

That said, the largest merchant-exposed baseload producers, including Statkraft AS, Fortum Oyj, Uniper SE, and Verbund AG, will most likely see supportive earnings over the next two years. This was already the case in first nine months of 2021 for Finnish power generator Fortum Oyj, whose EBITDA from European power generation increased about 25% year on year. In France, benefits from recovering prices will be mitigated for Electricite de France S.A. by the effects of subdued production over 2022-2023 because of maintenance issues for its nuclear fleet (see "Electricité de France Placed On CreditWatch Negative On Nuclear Outages And Adverse Political Decisions," published Jan. 17, 2022). That said, we believe additional earnings will generally not be used to reduce debt but rather to finance further transformation of generation fleets to adapt to the energy transition, including higher investments in renewables.

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

Conversely, we believe some suppliers could suffer significantly and see substantial pressure on earnings. This is most likely to affect smaller players that are short in power (that is, those that generate less than they sell and have to purchase it to meet power demand) and may even result in some defaults. This is already happening in the U.K., where more almost 30 small-to-midsized, alternative power suppliers defaulted in the past six months. In late November, Bulb Energy, the U.K.'s largest retailer after the "big six" with 1.7 million customers, was placed under special administration. This could eventually benefit larger incumbents, because customers will need to return to last-resort suppliers (see "U.K. Energy Reforms Unlikely To Prevent Imminent Supplier Failures But Will Boost Resilience Over Time," published Nov. 2, 2021). While harder to predict, large trading operations could also be affected by 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 2020)	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	96.8	(12.8)	18.6
2022	155.4	(8.5)	47.2
2023	94.3	8.0	5.8
2024	85.7	6.0	(4.5)
2025	78.7	7.2	(13.6)
2026	69.5	7.8	(27.2)
2027	61.5	6.4	(34.7)
MWh--Megawatt hour. Source: S&P Global Platts.

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

The path to net zero will strengthen the link between German power prices and natural gas markets

We anticipate elevated pressure on power prices will remain in the coming four years because of increased supply-demand imbalances paired with a lack of sufficient network expansion at least until 2026, notwithstanding the successive buildout of cross-zonal interconnector capacities. We expect the latter will not unfold its full potential for power imports before 2026 at which time German transmission system operators will be obligated by EU law to make at least 70% of each interconnector capacity available for trade. We anticipate the increasing need for balancing power and congestion management will weigh on consumers' electricity prices (via network fees), next to elevated wholesale power prices.

Given these factors, we believe highly flexible gas-powered generation will be a key transition technology at least for the next decade. We consider gas will become an even more pronounced driver of wholesale market electricity prices as per the merit-order effect and critical for security of supply. An accelerated German coal generation exit by 2030--as envisaged by the recently elected government instead of 2038--should provide further support for gas generation. Last year already showcased the national electricity network's increasing dependence on flexible generation to compensate for the intermittency of renewable generation. This is especially true during the "Dunkelflaute," a period of time in which little to no energy can be generated with the use of wind and solar power. We understand renewable generation in Germany was about 4%-5% lower in 2021 than 2020, due to historically poor wind conditions. Typically, this coincidences with cold temperatures, a time when natural gas prices rise due to increased demand from heating, which exacerbates pressure on power prices. Furthermore, we believe geopolitical tensions and structural shifts will provide upward pressure to gas prices, since we don't believe the supply-demand gap will be meaningfully mitigated anytime soon (see "Price Tremors Threaten Europe's Gas Bridge," published Oct. 5, 2021). The long-term upward trend in EU carbon allowance prices provides additional tailwinds to power prices as long as fossil-fueled generation remains a steady component of the power mix. In general, we expect increased commodity price volatility at higher price levels will persist at least until 2025 (see "Energy Are High Prices Here To Stay?," published Dec. 1, 2021).

Germany to become a net importer, as renewables fall short of replacing conventional generation and electrification needs rise

We anticipate domestic electricity demand will remain flat or rise slightly through 2025 compared to about 580 terawatt-hours (TWh; net) in 2000. Thereafter, we anticipate more pronounced increases toward 650 TWh–700 TWh by 2030, due to increased electrification of other sectors, such as heating, transport, and data centers, notwithstanding the mitigating effect of increasing energy efficiency, increasing energy flexibility (thanks to peaker plants, storage solutions, smart solutions such as flexible EV and heat pumps, and demand response), and the increasing expansion of domestic and cross-country network capacities.

At the same time, polluting hard coal and lignite power plants, which combined still account for about one-fourth of net generation, have entered their phaseout programs. By the end of 2022, they should have 30 GW of capacity (equally split) remaining compared with about 40 GW (also equally split) at the end of 2021 (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, we expect EU's ETS prices will remain high and make 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 phaseout is on track to be completed in 2022: since the start of the year, the country has taken 4 GW of nuclear capacity offline, and the remaining 4 GW (13% of total net production) are scheduled to be turned off by year-end.

Although renewables constitute more than 40% of total gross electricity production (41% on average for 2021, compared with 45% for 2020), they will be insufficient, even under optimistic expansion scenarios, to offset the drastic near-term closures of traditional energy sources, such as coal and nuclear power. Especially given incentives to accelerate electrification of other sectors. We expect Germany will become a net importer from 2023. Currently, Germany is still in a net electricity exporter position (17 TWh in 2021 down from 49 TWh in 2018). We estimate Germany will need at least 15 GW in additional flexible gas capacity for security of supply before 2030-–which will be ambitious to achieve and highly unlikely in the absence of investment incentives, such as the introduction of a market for flexible capacity.

Beyond 2026, we anticipate domestic electricity supply-and-demand imbalances in Germany will subside, assuming:

• Further penetration of renewables, paired with a buildup of sufficient 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 and supply side, and grid smartening (such as smart bundling and steering of prosumers) for which we expect markets will create financial incentives. This should include retail customer flexibility applicable to home appliances, storage, heat pumps, and EVs.

Beyond 2030, we expect renewable energy's cannibalization effect to necessitate new investment incentives beyond the government's current ambitions for a capacity mechanism for flexibility.

The energy transition and its cost are at the heart of German political action

The German energy landscape is undergoing a transformation to meet the country's ambitious goals around reducing greenhouse gas (GHG) emissions, which are derived from the EU's GHG emissions targets. Specifically, carbon emission reduction 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 for all sectors, including industry and transport. Germany's newly elected federal government has set in motion further acceleration of the energy transition to reach carbon neutrality no later than 2045, and consequently set ambitious targets for renewable capacity expansion and decarbonization of further sectors via electrification and power-to-gas technology (10 GW of electrolyzer capacity buildup for hydrogen production by 2030). Consequently, the new government aims to:

• Achieve 50% climate-neutral heating by 2030, via minimum requirements for renewable energy in heating (65% for new buildings).
• Achieve a minimum of 15 million fully electric passenger cars on German roads by 2030. This is likely to be upscaled to align with the European Commission's goals. As such, Germany intends to accelerate the establishment of an exhaustive charging infrastructure.
• Account for higher ongoing electrification. Germany assumes 680 TWh-750 TWh of annual gross electricity consumption (up from a previously assumed flat demand development of 580 TWh).
• Cover 80% of total electricity demand with renewables (up from 65% recently) by 2030.

The combination thereof translates into 2030 targets for wind (onshore and offshore) and solar generation capacity increasing to 320 GW-350 GW from the 190 GW targeted by the previous government. This compares with 123 GW of generation capacity at end-2021 and 117 GW at end-2020.

The cost of this transition is high and has so far been mostly borne by households. High wholesale power prices and increasing surcharges, specifically for network expansion and renewable generation, are increasing 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 €30 cents per kilowatt-hour (ct/kWh; 2021 average price of €32.16ct/kWh). In 2021, the German government capped the green power levy (the largest surcharge on power bills) at €6.5ct/kWh for 2021 and at €6ct/kWh for 2022, contributing about €11 billion from the federal COVID-19 measures budget. To retain public support for the energy transition, the government has further reduced the renewable energy (EEG) levy for 2022 to €3.7cts/kWh (instead of €6ct/kWh) and plans to abolish the EEG levy by the end of 2022 at the latest. German renewable feed-in tariffs instead will be remunerated by proceeds from the country's additional national ETS for heating and transport, with a carbon allowance price of €25 per metric ton starting in 2021 that will increase gradually (€30 in 2022) to €55 per metric ton by 2025. Furthermore, the government intends to introduce tax cuts or subsidies for low-income households. To mitigate wholesale market dependency, commercial and industrial 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).

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 major obstacles. The newly elected government, however, is promising swift action to overcome remaining hurdles. In particular, the expansion of onshore wind power is facing major challenges because of lengthy and difficult permitting process. After already falling short in 2018 by 400 MW of the 2.8-GW annual statutory target, onshore wind installations fell to 1.1 GW in 2019, then recovered to 2.7 GW in 2020 before falling to 1.6 GW in 2021. 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. Permitting and real estate scarcity are both identified as key development areas by the new government.

New cash flow streams for power generators will need stable remuneration mechanisms

We believe Germany will likely introduce flexibility means via incentives or capacity agreements. Our expectation has received tailwinds from the new coalition's announcement of corresponding reforms. Besides 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 better ensure security of supply, we expect the market will see the introduction of incentives for more supply-side flexibility, for example, for highly efficient gas generation, combined heat and power generation, and storage solutions like batteries and power-to-X. Furthermore, we anticipate 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 and procurement of green energy. We believe the ability to bundle, split, and facilitate marketing of renewable generation capacity via a combination of long-term contracts (or PPAs) and virtual power plants will be key to enable customers' decarbonization, especially in volatile power markets.

For Germany's coal generation fleet, after closure, operators could derive value from transforming the plants or sites that already benefit from grid connection. Given real estate scarcity in Europe and Germany specifically, we anticipate opportunities in the repurposing of coal and other brownfield sites for industrial--and security of supply--solutions, including renewable generation and other power assets. There will likely be low permit hurdles and limited public opposition for converting these sites to greener usage, such as efficient gas plants, waste incineration, commercial scale storage solutions, data centers, biomass, or other renewable generation.

Table 3

Key Power Companies We Rate In Germany
Company	Ratings	German merchant/total German generation 2021 (TWh)	2022 hedge	2023 hedge
Verbund AG	A/Stable/--	N.A./N.A.	N.A.	N.A.
Uniper SE	BBB/Stable/--	About 2.2/N.A.	90% at €49/MWh	90% at €51/MWh
E.ON SE	BBB/Stable/A-2	About 20/About 20	1.0	N.A.
EnBW Energie Baden-Wuerttemberg AG	A-/Stable/A-2	N.A./N.A.	90%-100%	50%-80%
N.A.--Not publicly available. MWh--Megawatt hour. TWh--Terawatt hour. Ratings as of publishing date. Source: S&P Global Ratings.

Table 4

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For France
(€/MWh, real 2020)	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	109.2	(1.4)	30.9
2022	157.7	(5.5)	49.5
2023	93.2	7.0	4.9
2024	82.4	2.7	(1.8)
2025	73.1	1.6	(19.3)
2026	64.7	3.0	(32.3)
2027	55.6	0.6	(40.3)
MWh--Megawatt hour. Source: S&P Global Platts.

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

Nuclear and hydro dominate the energy mix, despite growth of 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-carbon sources (about 75% nuclear and 15% hydro), which largely cover domestic demand (466 TWh of gross consumption in 2021). The country's energy law and the updated energy plan (PPE) for 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 in 2020, nuclear reactor closures will start only in 2027 at a pace of one per year, with the flexibility to close two additional plants in 2025 and 2026, depending on the energy policies of neighboring countries. Yet, given our expectations of increasing power demand (see below) and the current concerns regarding French nuclear output, we think such early closures are less likely now. While the plan envisages some nuclear plant closures, it also considers life extension of a majority of the nuclear fleet as well as new builds and eventually small modular reactors. We also expect that the country's 1.3-GW FLA-3 nuclear plant will be commissioned early 2024 (six months later than EDF's estimate of mid-2023, due to already numerous postponements).

This strategy on nuclear will be combined with the gradual increase in renewable installed capacity over the coming decade. We believe that capacity growth will be paced in conjunction with domestic demand and export needs to avoid overcapacity and strained prices. At this stage, we believe that France will struggle fulfilling its renewable energy goals, which would require French wind and solar capacity to more than double by 2030 from 2018 levels of 15 GW and 9 GW, respectively.

Power supply will remain constrained by nuclear availability

We expect that France's power supply will remain constrained by the fluctuating and low availability of nuclear over the next two-to-three years. This will need to be compensated for by other baseload sources, notably gas.

This was the case in 2020 during the pandemic when the incumbent nuclear power generator EDF had to reschedule maintenance and suffered from lower power demand, which lead to annual French nuclear output of 335 TWh compared with its historical production level of above 380 TWh. In 2021 output reached 365 TWh, and we now expect much lower nuclear volumes in 2022 due to lower availability following EDF's announcement on Feb. 7, 2022, of the extension of outages for five of its French nuclear reactors. The group subsequently lowered its output guidance by 35 TWh to 295 TWh-325 TWh. Because the group is currently inspecting the entire nuclear fleet, due to corrosion defaults identified at its Civaux plant, we lack visibility on the number of reactors impacted. While our current base case is for nuclear output of 300 TWh for 2022 and a recovery to 330 TWh-350 TWh in 2023, we may have to revise our assumptions downward when EDF and the nuclear safety regulator ASN provide an updated diagnosis on these technical defaults.

Until 2025, we anticipate that nuclear output will remain significantly below its historical level of 380 TWh, as uncertainty prevails on the magnitude of the operational setbacks for 2022. What's more, we anticipate that maintenance work and a high number of 10-year lifetime extension inspections scheduled will lead to lengthier outages as the fleet is growing older, as hinted by ASN.

We now see potential for power demand growth, in contrast to previous forecasts

Demand recovered in 2021 to almost pre-COVID-19 levels, evidenced by a 5% increase year over year in 2021 (after a 6% plunge in 2020) in line with our expectations and supported by economic recovery.

From 2022, we now expect flat-to-improving demand versus flat to declining previously. This is because we believe that energy-efficiency initiatives by all grid stakeholders will be more than offset by additional electrification needs from industries (power, building materials, chemicals, and oil and gas) and by e-mobility trends including heavy transportation. This reversing trend notably stems from the more ambitious decarbonization targets embedded in Europe's Fit for 55 package. However, electrification of 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 forecast that additional demand from EVs could boost demand further in the next decade, looking at the sharp increase in 2021. Total EV sales (battery and hybrids) in France increased by more than 60% in 2021 compared with a year ago (about 314,800 units up from close to 194,000 units in 2020 and about 68,600 in 2019) and now represent 15% of new car sales (versus 9.5% a year ago).

Combined with a low-single-digit demand increase, we expect French power prices to remain high over 2022-2023, yet down from the record highs of €109/MWh in 2021 (after a drop in 2020 to €32/MWh), and we are revising upward our base-case prices for 2022 to €55/MWh-€60/MWh from €50/MWh-€55/MWh and for 2023 to €62/MWh-€67/MWh from €50/MWh-€53/MWh.

France's export capacity from 2023 may be constrained by domestic needs

At this stage and given uncertainty on French supply, it's hard to project if France will be in a position to export from 2023. However, there would be more needs coming from the tightening capacity in neighboring countries and it could be facilitated by the new interconnection capacity. New interconnections are coming online: 2.0 GW with the U.K. (IFA2 and ElecLink) pushed to July 2022 and 1.2 GW with Italy (Piedmont-Savoy). And we anticipate a short-term tightening in capacity in neighboring countries, particularly Belgium, Germany, and Italy. The level of France's generation output will thus be key to balance the power markets of these countries. This is especially true for Germany, which faces the planned shutdown of 4.0 GW of nuclear capacity by end-2022, together with the withdrawal of about 1.6 GW of lignite capacity.

High wholesale power prices are putting a spotlight on affordability and leading to exceptional political intervention

The high wholesale power price market through 2021 would have translated, without any offsetting measures, to a sharp increase in consumers' electricity bills of about 35%. Indeed, the CRE adjusts the regulated tariff for households (Blue Tariff) every year for the electricity supply components of all power suppliers. The French government opted for the activation of the cap of regulated ARENH tariffs for alternative suppliers to 120 TWh (from 100 TWh). The extra volume is set at a fixed price of €46.2/MWh (compared with €42/MWh on the existing 100 TWh). These extra volumes are to be delivered over April-December 2022, and we understand that the increased volume is a one-off, unlikely to be rolled over in 2023. In our view, EDF will have to purchase significant additional volumes (20 TWh) of electricity in a very volatile and materially high power price environment, while selling at much lower contracted price. The government also announced that the regulated customer yearly tariff increase for February 2022 will be capped at 4%, with a postponement to February 2023 of any additional increase. This may imply €2.0 billion of additional costs for EDF in 2022, to be recovered in 2023. We believe this is the strongest materialization of political intervention to respond to affordability concerns throughout Western Europe so far. It led us to place EDF on CreditWatch with negative implications on Jan. 17, 2022 (see "Electricité de France Placed On CreditWatch Negative On Nuclear Outages And Adverse Political Decisions").

Reform of nuclear is a key unknown for power prices, but unlikely before 2023

EDF's French nuclear 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 (as exercised for 2022 and explained above). Therefore, ARENH plays a key role in retail electricity prices.

The French government has been seeking to reform its nuclear power sector over the past two years, but negotiations with the EU have been difficult and not proven fruitful. The current French government has been willing to set up a new mechanism, introducing a high floor price for nuclear output, which would better reflect the total cost of nuclear. We understand all negotiations have been put on hold until further notice, and we believe it is very unlikely that any agreement of principle to depart from ARENH can be reached before the presidential elections in April 2022. Hence, we believe probability and timing of a reform remain uncertain.

Renewables are lagging targets, given still-lengthy permitting processes

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 21% in 2021. All renewable technologies are suffering from delays though, due to administrative burden and length of permitting, even if progress is being made, notably on onshore wind acceptability compared to one year ago thanks to the government's recently released 10-point plan. However, onshore wind is facing rising uncertainty ahead of presidential elections, since the political debate highlights some adversity when it comes to deploying onshore wind (strong opposition from the right-wing party).

• Solar production faces delays and it is looking more challenging that it will meet 2023 target (20.6 GW of installed capacity, up from about 10.0 GW as of 2019 and 12.5GW in 2021) and 2028 target (35 GW-40 GW).
• Onshore wind should be able to meet or come close to its 2023 target of close to 25 GW and 2028 target of 32 GW-33 GW, according to our current forecasts.
• Offshore wind projects under developments by EDF, ENGIE, and Iberdola are progressing, and France looks on track to meet its 2028 target of 5 GW-6 GW embedded in the PPE. 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 installed capacity of about 500 MW at its Saint Brieuc offshore wind site (construction started in 2021).

As part of its 2020 economic stimulus package, the French government unveiled an ambitious hydrogen plan that aims 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 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 came 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 PV 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, taxpayers bear the costs arising from 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	Rating	Total production 2021 (TWh)*	2022 hedge	2023 hedge
Electricite de France S.A.	BBB+/Watch Neg/A-2	403.0	N.A.	N.A.
Engie S.A.	BBB+/Stable/A-2	13.5	75% at 54.6€/MWh	46% at €51.6/MWh
*S&P Global Ratings' estimates. N.A.--Not publicly available. MWh--Megawatt hour. TWh--Terawatt hour. Ratings as of publishing date. Source: S&P Global Ratings.

Table 6

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For U.K.
£/MWh (real 2020)	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	118.3	16.0	34.1
2022	152.7	6.0	46.8
2023	74.0	1.3	(8.4)
2024	66.9	(1.0)	(17.1)
2025	60.9	(0.9)	(23.9)
2026	50.1	(0.1)	(35.3)
2027	44.9	(2.3)	(40.1)
MWh--Megawatt hour. Source: S&P Global Platts.

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

High prices highlight U.K.'s still-significant dependence on gas and challenging decarbonization targets

The U.K. government has pushed up its target to fully decarbonizing the country's electricity system by 15 years to 2035 as part of its updated net-zero strategy. Despite these ambitious aims, the high power prices illustrate the U.K.'s still-significant reliance on natural gas amid rising domestic demand due to, among other reasons, unfavorable weather patterns. In 2021, the U.K. saw third-quarter wind speeds that were among the weakest recorded in the 21st century and a relatively subdued number of average hours of sunlight. This resulted in the proportion of renewables in total generation dropping below that of natural gas to 30.3% (77 TWh) from 33.8% (85 TWh) in 2020. This contrasts with fossil fuel generation, mostly gas, increasing to 44.3% (112 TWh) from 39.7% (99 TWh) over the same period.

While the U.K. has seen strong penetration of renewable assets in its energy mix, with about 49 GW of total installed renewable capacity at the end of third-quarter 2021, a significant ramp-up in generation is required for the country to reach its ambitious decarbonization targets. However, apart from offshore wind, its net-zero strategy does not specify any renewables capacity targets. That said, several projects are already under development from previous governmental renewables auctions, with the U.K.'s second and third Contract for Difference (CfD) auctions having resulted in additional capacity of 3.3 GW and 5.8 GW, with delivery years of 2021-2022 and 2024-2025, respectively. The fourth round, which aims to secure an additional 12 GW of capacity (more than the previous three auctions combined) opened in December 2021, with final results expected for July 2022. What's more, the government announced on Feb. 9, 2022, that CfD auctions, historically held once every two years, will be held on an annual basis from March 2023. This announcement signals the U.K. government's willingness to accelerate its decarbonization efforts in order to reach its net-zero target, while giving more visibility and flexibility to project developers and the rest of the renewables sector.

Offshore wind targets are ambitious, but achievable

Among renewable sources, offshore wind technologies will be a significant contributor to reaching the sector's net-zero target. The government has already signaled its intent to increase capacity to 40 GW by 2030--which far exceeds the targets of any other European country--from 11 GW at end-2021. The U.K. is already the European leader in terms of capacity and second globally behind China with about 12 GW. We expect the fourth CfD auction will significantly increase this total, with fixed-bottom offshore wind projects notably being awarded the biggest portion of subsidies.

On Jan. 17, 2022, the Scottish government announced the outcome of one of the biggest auctions of its kind in the world, with 25 GW of offshore wind project development rights awarded to 17 different projects--an amount that significantly exceeded the initial estimated capacity of 10 GW. While this is the first stage of the process, with final investment decisions and possible construction to be undertaken in later years, this outcome will likely boost the U.K.'s prospects for meeting its 2030 target.

We do see a few risks, however, to this timeline, notably on the scalability of floating wind assets (about 13 GW of the 40 GW total), given the relatively developing nature of the technology, with some projects more likely to come online at the start of the next decade. Other challenges include heightened pressure on returns stemming from the more competitive environment, tighter supply chains, and material increases in global demand and ultimately prices for raw materials, such as copper or nickel. Adequately skilled manpower may also become a scarcer resource this decade, as projects in the U.K. and the rest of Europe accelerate significantly.

Given the size of the current pipeline, we consider that the U.K. could achieve or even exceed its 2030 wind targets. Undoubtedly, this will also strengthen its leading position in offshore wind in Europe, benefitting companies with a significant exposure to the energy transition, such as Iberdrola S.A. (via its U.K. branch Scottish Power Ltd.) and SSE PLC. Both were among the biggest winners of the ScotWind offshore auction, securing respectively about 7.0 GW and 2.6 GW, mostly via joint ventures.

Security of supply versus decarbonization

Last year and the start of 2022 highlight the challenges of meeting decarbonization objectives while ensuring security of supply and the increasing importance of grid balancing and reliable generation in times of unfavorable weather. The country remains reliant on gas-fired power generation, and its proportion of the energy mix will continue to be sizable, given the closure of the U.K.'s coal fleet by 2024 and uncertainty surrounding the future of nuclear generation, which accounted for 17.1% of total power generation in 2021. Almost all the existing nuclear fleet will be shut down by 2028, with a significant capacity reduction (5.4 GW) in 2025, following the announcement of Dungeness B closure in 2021 (seven years sooner than initially planned). This would leave only Sizewell B remaining from 2028, although the 3.2-GW Hinkley Point C plant is set to start operations in 2027 and a decision on its sister project Sizewell C is still pending.

While political and economic links with Europe are diminishing following the departure of the U.K. from the single market, its energy system will also be increasingly linked to that of the Continent amid higher balancing needs induced by the rising penetration of renewables sources in the energy mix to meet ambitious decarbonization objectives across Europe. We expect the U.K. will expand its interconnections with the rest of Europe by 2025; it has plans to at least double its existing capacity (7.4 GW following the commissioning of National Grid's North Sea Link between Great Britain and Norway in October 2021) via new connections with France, Germany, Denmark, and Norway.

Political intervention to combat surging energy prices leaves suppliers and generators unscathed for now

On Feb. 3, 2022, the U.K. regulator Ofgem announced a 54% rise in its default tariff cap alongside reforms to its cap calculation method, following a record rise in gas prices over the past six months, with wholesale prices quadrupling in the past year. What's more, the government unveiled a support package for households worth about £9 billion to mitigate the shock for end customers. We consider these developments signals that intervention will likely focus on helping consumers rather than transferring the burden to power generation and energy supply companies, as we've seen in other European countries. If current conditions persist, however, power generators might be increasingly in the spotlight amid a steep rise in the cost of living for U.K. households, amplifying the risk of adverse political intervention for the sector, in our view. For more details on conditions for U.K. suppliers and generators, see "Higher Tariff Cap, Proposed Reform, And Support For Households Ease Pressure On U.K. Energy Suppliers For Now," published Feb. 10, 2022.

The energy crisis is gradually changing the U.K. energy supply market

As a result of unprecedented high energy prices, the number of retail power supplies in the U.K. supply market has considerably declined to 23 at the end of last year from nearly 50 as of midyear. We expect consolidation will continue but slow, as energy prices remain high and above the wholesale costs allowance for the updated cap in 2022. In the current situation, customer churn rates also markedly declined at end-2021, given that high commodity prices limit suppliers' ability to offer deals below the price cap.

We also understand that the regulator Ofgem will implement a series of reforms to ensure greater resilience for suppliers. New license conditions will allow the regulator to pause energy suppliers' uptake of new customers once they reach the 50,000 and 200,000 domestic customer milestones. In addition, the regulator launched financial stress testing for suppliers from January 2022, while reducing its focus on encouraging customers to shop around for the best provider. These factors will likely help temporarily ease competitive pressure and improve profitability margins for the sector, after years of challenging operating conditions.

We rate four of the largest suppliers in the market: Centrica PLC (BBB/Stable/A-2); EDF Energy Ltd. (BB+/Watch Neg/B); E.ON U.K. PLC (BBB/Stable/A-2); and Scottish Power Ltd. (BBB+/Stable/A-2).

Since the beginning of 2021, these suppliers have taken about 60% of the exiting suppliers' customers via the Supplier of Last Resort (SoLR) process. Since 2021, about 2.7 million customers have had to be reallocated to remaining suppliers through the SoLR process (excluding Bulb's special administration regime for its 1.7 million customers that have yet to be allocated).

While remaining players are increasing their market shares thanks to the allocated new customers, they are also facing material working capital outflows for fourth-quarter 2021 and first-quarter 2022. This is due to commodity purchases in the spot market at the current elevated prices to meet additional demand from new customers, which will only be recovered will a lag through future price cap changes (the April 2022 price cap notably includes £68 in SoLR levy costs in network cost allowances). The distribution network companies will pay levy claims (totaling about £1.83 billion) to energy companies and recover them from consumers via their charges.

We expect high prices will likely benefit larger, more established suppliers, due to, among other factors, stronger liquidity, better access to capital, and efficient hedging positions. These elements were among the drivers of our recent outlook revision on Centrica PLC (see "U.K. Energy Supplier Centrica Outlook Revised To Stable On Continuous Deleveraging; 'BBB' Rating Affirmed," published Dec. 15, 2021).

Table 7

Key Power Companies We Rate In The U.K.
Company	Rating	Total production for 2021 (S&P Global Ratings annualized estimates)(TWh)	2022 hedge	2023 hedge
SSE plc*	BBB+/Stable/A-2	25.0	About 80% at about £54.6/MWh	About 54% at about £53.3/MWh
Drax Group Holdings Ltd.§	BB+/Stable/--	15.2	About 76% at about £70.7/MWh	About 35% at about £61.2/MWh
InterGen N.V.†	B+/Stable/--	8.3	N/A	N/A
Scottish Power Ltd.†	BBB+/Stable/A-2	6.5	N/A	N/A
*As of Sept. 30, 2021 (H1), hedges are for renewables generation only (27% of total generation as of H1 2021) and for the nine last months of the year and first three months of the subsequent year. §As of July 31, 2020, contracted % as of Nov. 2021 versus 2020 full-year output of 16.4 TWh (post-divestment of CCGT assets). †As of Sept. 30, 2021. ‡ N.A.--Not publicly available. MWh--Megawatt hour. TWh--Terawatt hour. Ratings as of publishing date. Source: S&P Global Ratings.

Table 8

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Italy
(€/MWh, real 2020)	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	124.9	13.0	46.7
2022	169.2	5.3	61.0
2023	96.4	9.2	8.6
2024	89.9	8.9	(0.4)
2025	81.5	8.6	(10.9)
2026	71.6	8.5	(24.9)
2027	64.6	8.2	(30.3)
MWh--Megawatt hour. Source: S&P Global Platts.

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

Power prices will remain higher than other European countries' due to reliance on thermal power and imports

The Italian power market will see material changes in the next few years as its fuel mix undergoes a transformation. The country aims to cut emissions by 60% by 2030 from 1990 levels, and will benefit from €80 billion from the EU recovery fund for climate purposes (about one-third of the €200 billion share of the €750 billion recovery fund allocated to Italy). In particular, Italy targets increasing its renewables installed capacity to 88 GW by 2030 (43 GW of new solar and 12 GW of new wind, mostly onshore). This compares with about 33 GW installed at year-end 2020 (about 22 GW from solar and about 11 GW from onshore wind).

We expect Italy's power prices will remain higher than those in other European markets until at least 2025, due to comparatively low renewable penetration and the coal phaseout in 2028, which will leave the country increasingly reliant on gas and imports to balance supply and demand. Notably, we expect sustainably high gas and carbon prices will drive up power prices to about €60/MWh in 2022 (above the 2019 level of €52/MWh), from the historical low of €38/MWh in 2020. In our base case, we also anticipate power prices will increase to more than €70/MWh over 2023-2025. This high price environment will benefit the Italian integrated utilities we rate, notably Enel SpA, A2A SpA, IREN SpA, and Edison SpA.

Imports also play an important role for the Italian power market, given the lack of domestic production and supported by our expectation that interconnector capacity will increase to 13.0 GW in 2025 from 9.5 GW in 2021. Interconnection capacity on the northern border should increase by 3.5 GW by 2025, including 1.2 GW with France (which came 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 2020 levels, with imports covering about 20% of demand over 2022-2025.

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 132 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 6.2 GW at year-end 2021, 900 MW less than in 2020). By 2026, the only remaining coal units will be the two must-run plants in Sardinia: 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 for the next decade.

Italy's largest power generator, Enel, has publicly mentioned its ambition to exit gas production and supply by 2040. That said, S&P Global Platts Analytics expects gas generation to peak in mid-2020s with gas installed capacity starting to meaningfully decline below 30 GW only after 2040.

Higher risk of political intervention, but this should be manageable for utilities

We expect that high power prices in Italy relative to European peers through at least 2025 will translate into higher costs for final costumers, notably the industrial sector with potential consequences for productivity. Indeed, the General Confederation of Italian Industry, commonly known as Confindustria, estimated that total power bills for Italian companies will increase to more than €35 billion in 2022, from about €20 billion in 2020 and about €8.0 billion in 2019.

To tackle the situation, the Italian government issued a law decree on Jan. 21, 2022, which will have to be converted into law with parliament's vote within 60 days, with the following measures:

• Cancellation of the "other system charges" applied to customers with connection above 16.5 kilowatt (kW) for the first quarter, for a total amount of €1.2 billion, which will be financed with the use of the carbon tender proceeds of 2022.
• A tax credit of €0.5 billion in total for companies that consume high quantities of energy. In particular, companies that have seen electricity costs increase more than 30% versus 2019 (also taking into consideration eventual fixed-price contracts signed) are awarded partial compensation in the form of tax credit equal to 20% of expenses in the "energy component" acquired and effectively used in first-quarter 2022. The credit can also be sold.
• A clawback of profits for some renewables that would run from Feb. 1 to Dec. 31, 2022. The measure would apply to electricity produced from: (i) plants with renewable capacity exceeding 20 kW that benefit from fixed tariffs from Conto Energia and therefore do not depend on energy prices; and (ii) hydro, geothermal, and wind power plants not covered by green certificates. This measure applies a two-way contract-for-difference mechanism on the energy price realized in sales for the aforementioned categories. The energy operators will "cash in" or "pay back" the system operator the difference between: (i) the average price of energy measured in the period from the plant's commercial operation date and Dec. 31, 2020 (if the plant entered into function before Jan. 1, 2010, the average price is calculated from Jan. 1, 2020); and (ii) the price of electricity in the market or the price of the selling contracts, which are linked to the market prices (revalued for inflation). We estimate the strike price to be at about €66/MWh.

While we do not expect the first two measures will impact utility companies, since they will be financed using the proceeds from the ETS auctions, the third measure could affect power producers that have not entirely sold forward their production for 2022. The impact should not be major at a single-name level. That said, companies that are less hedged (such as A2A SpA as shown in Table 9) could see lower-than-expected earnings in 2022. For A2A, which has publicly mentioned this, we expect the law, if approved, to have an EBITDA impact of about €35 million in 2022.

Despite ambitious targets, renewables will remain a small part of the energy mix given slow permitting

S&P Global Platts Analytics forecast that Italian wind and solar capacity will almost double to 19.4 GW and 40.0 GW, respectively, by 2030, from 11 GW and 22 GW in 2020. As a result, renewables will represent about 30% of the mix by 2030 from 16% today. These numbers are still almost 30% lower than the government's 2030 targets. This is mainly because of slow permitting (stemming notably with competition from agricultural land use) that could slow the rollover of renewables at the national level. That said, Italy's Ecological Transition Ministry aims to achieve a meaningful simplification of rules and procedures for authorizing new projects. Specifically, the minister hopes to cut the time required to obtain a permit for an infrastructure project to 270 days from 1,200.

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.

Power demand to fully recovery only by 2025

Power demand rebounded about 5% in 2021, after a decline of about 6% in 2020 from COVID-19-related restrictions. Because of stagnant near-term economic activity impacted by supply chain issues and inflationary pressures, notwithstanding the strong recovery from COVID-19 and continued energy-savings efforts, we believe that average demand will reach 2019 levels only in 2025. This is later than the European average, with Italy benefiting less from demand electrification. We do not see hydrogen as changing its demand pattern before 2025 at the earliest, while EVs penetration in Italy is still relatively low and not increasing as quickly as other European markets.

Table 9

Key Power Companies We Rate In Italy
Company	Rating	Total production 2021 (TWh)	2022 hedge	2023 hedge
Enel SpA	BBB+/Stable/A-2	44	100% at 60.9€/MWh	38% at 70.7€/MWh
Edison SpA	BBB/Stable/A-2	18.1*	N.A.	N.A.
A2A SpA	BBB/Stable/A-2	16.8*	40% at 52.5/MWh	N.A.
Iren SpA	BBB-/Positive/--	9.7	N.A.	N.A.
*2020 level. N.A.--Not publicly available. MWh--Megawatt hour. TWh--Terawatt hour. Ratings as of publishing date. Source: S&P Global Ratings.

Table 10

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Spain
(€/MWh, real 2020)	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	111.9	(1.7)	33.7
2022	161.6	(4.8)	53.4
2023	92.7	4.1	4.7
2024	81.7	(0.3)	(7.3)
2025	71.6	(2.2)	(20.1)
2026	61.2	(2.8)	(35.2)
2027	53.3	(4.1)	(41.8)
MWh--Megatwatt hour. Source: S&P Global Platts.

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

With gas as the price-setter, prices are likely be high and volatile for longer, prompting policymaker intervention amid affordability concerns

During 2021, average wholesale power prices in Spain shot up about 230% compared with 2020, with peak average prices of €240/MWh in December, compared with close to €40/MWh for the same month one year before. The increase is mostly explained by gas being the predominant technology under the Spanish marginal price-setting system at peak hours, average gas prices tripling, and carbon prices more than doubling in 2021 compared with 2020. We expect declining coal capacity coupled with the acceleration of renewable capacity and imbalanced gas stocks will exacerbate wholesale price volatility at least until 2025, as these conditions will favor gas as the price-setting technology over the current decade. Even if a sharp increase in renewables reduces the hours in which combined cycle gas turbine (CCGT) plants set the price for electricity from 2025 to 2027, the expected gradual phaseout of Spain's 7.1 GW of nuclear capacity starting in 2027 will likely provide long-term fundamentals for gas remaining as back-up capacity.

Because roughly 11 million households in Spain consume electricity under the voluntary service for small consumers (PVPC), which is indexed to spot wholesale prices, the recent fluctuations led policymakers to design mechanisms to protect end customers through a series of royal decree-laws. Such measures include temporary tax suspensions on consumer bills and power generation, in addition to market intervention in the form of different mechanisms. These notably include the gas and carbon clawback mechanisms for non-gas and non-carbon emitting capacity, which has not yet been voted on in the parliament. Importantly, the Spanish government has amended the initial gas clawback proposal to exclude power generation that was contractually hedged until the enactment of the royal decree-law and generation that has a hedge of at least one year if it was signed after the introduction of the gas clawback. This change will reduce the financial impact for the sector to about €500 million from close to €2.6 billion initially. Although the carbon clawback proposal hasn't been finalized, we expect it will have a similar structure to the one implemented on gas. We note, however, that this mechanism is set to remain a permanent market feature, as opposed to the temporary nature of the gas one.

In the Royal Decree-Law 17/2021, the Spanish government created a mechanism for auctions for renewable capacity under which dominant operators are obligated to offer long-term PPAs with a price cap. This cap is set at 25% of the value of energy generated in the past 10 years by non-carbon-emitting capacity (renewables, hydro, and nuclear). As such, the price under long-term contracts is typically set well below the market clearance price. Such mechanism would affect Iberdrola S.A., Endesa S.A., EDP - Energias de Portugal S.A., and Naturgy Energy Group S.A., which each generate more than 10% of Spain's electricity and are the market's dominant players as defined by the Spanish regulator. The aim of this mechanism is to effectively lower customer bills by increasing competition in the sector.

We believe the Spanish government keeping affordability central to its climate and energy transition goals could mean further legislation if high prices persist in the next 12-18 months. For example, legislators might consider capping revenue related to electricity sales for renewables operating under a guaranteed return scheme, given the significant share renewable incentives represent on the electricity bill, although we understand there are no formal initiatives at this stage.

Spain is currently on track to meet its 2030 targets

With 63.7 GW of installed capacity as of December 2021, renewables (including hydro) now represent about 56.5% of the country's total capacity and about 49% of Spain's total electricity demand in 2021 (242 TWh, according to power transmission system operator Red Electrica Corporaction SA). Thermal production (mostly gas) now accounts only for 29% and nuclear for 22%. We expect renewables penetration will continue, as conventional thermal capacity is retired and replaced by more wind and solar capacity. Spain's coal capacity was fully decommissioned in 2021, mostly due to low profitability amid increasing carbon prices, with the only exception being 536 MW at EDP's Aboño coal power plant.

In its national energy strategy, outlined in the Plan Nacional Integrado de Energía y Clima (PNIEC), Spain targets generating 74% of its electricity with renewables by 2030, with an estimated €241 billion in related investments from 2021-2030. To reach this goal, the plan includes big changes to Spain's energy mix toward 2030, with total capacity increasing to 161 GW from 112 GW today: PV and thermo-solar (to 46 GW from 17 GW), wind (to 50 GW from 28 GW), 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 expect Spain could surpass its PV targets by 2030, but that it may fall 3-4 GW short of its 50 GW wind targets.

We believe that the recently unveiled Fit For 55 package could boost renewable development in Spain, since Europe's more ambitious goals will require increasing renewables capacity to cover 40% of the mix by 2030 up from the 32% previously targeted. The EU Commission will also enact a social climate fund, which will funnel €72 billion 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 beneficiaries and would receive about €7.6 billion (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. Moreover, we expect the Spanish government will continue laying the groundwork for accelerating the deployment of renewable energy in the country, including tackling local hurdles to accelerate permitting and connection.

Political intervention and supply chain disruptions may jeopardize renewables' growth trajectory

Although renewable capacity will continue to increase, Spain's political intervention slowed its deployment during the second half of 2021, despite the softening of the two clawback measures mentioned above, signaling a hit to investor confidence in Spain. For instance, only 95% of the 3,300 MW renewable capacity auctioned in October was allocated, mainly because relevant players abstained from participating. While ongoing power price volatility will make it increasingly hard to predict projects' profitability and returns, recent political interventions add a layer of complexity. S&P Global Platts Analytics estimates government intervention could cost the country about 3 GW by 2024 in terms of new renewable capacity.

An additional factor that will likely hinder new capacity additions in the short term are supply chain disruptions. Renewable deployment in 2022 will be more challenging and costly. After a decade of declining construction costs for solar PV and wind turbines, 2021 costs increased 10%-12% and 10%, respectively, compared to 2020. For instance, wind turbine manufacturers Siemens and Vestas have repeatedly issued profit warnings on persistently increasing costs and supply chain disruptions. We believe that this is a sign that supply chain disruptions are increasing in the sector, obscuring the short-term renewable development outlook.

Renewables growth is repositioning the Spanish power market in Europe

The acceleration in renewable capacity deployment will have two materially structural consequences in the Spanish market. On one hand, it will facilitate the country turning into a net power exporter from 2023-2024. On the other hand, we believe if Spain increases its excess power generation and the volatility of power prices rises, Spain will become 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 becoming 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 their renewable pipeline or trying to buy projects in advanced development stages.

We expect PPA prices in Spain will increase in the next 12-18 months, because of greater uncertainty and commodity price increases. We expect the volume of renewable capacity coming online toward 2025-2027 will contribute to reducing Spain's baseload power prices to one of the lowest in Europe, pushing down PPA contract prices again, eventually. However, this will depend on the phaseout of Spain's nuclear fleet, which is set to begin from 2027, since it could reintroduce imbalances in the power market as net power generation in the country declines.

Table 11

Key Power Companies We Rate In Spain
Company	Rating	Total production in 2021 (TWh)	2022 hedge	2023 hedge
Endesa S.A.	BBB+/Stable/A-2	73.9*	93% at €85/MWh§	49% at €86/MWh§
Iberdrola S.A.	BBB+/Stable/A-2	59.9*	About 100%	N/A
EDP - Energias de Portugal S.A.	BBB/Stable/A-2	35.4*	100% at €57/MWh	About 50% at €60/MWh†
Naturgy Energy Group S.A.	BBB/Stable/A-2	24.9	N.A.	N.A.
*2020 level. §Retail price. †About 50% of baseload generation is covered at €60/MWh over 2022-2025. N.A.--Not publicly available. MWh--Megawatt hour. TWh--Terawatt hour. Ratings are as of publishing date. Source: S&P Global Ratings.

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

As for rest of Europe, 2021 was eventful for the Nordic power markets. Power prices in the region rebounded strongly and Nord Pool System spot prices were up almost 6x and averaged close to €63/MWh in 2021, compared with €11/MWh for 2020. Thereby, the yearly average price was the highest ever recorded. Many factors contributed to the surge:

• A dramatic change in the hydrological balance, from a surplus to a deficit with reservoir levels currently well below historical averages;
• Lower nuclear capacity;
• While renewable capacity increased, its output has been dampened by lower wind speeds; and
• Increasing gas and carbon prices in Europe.

We anticipate that 2022 and 2023 will bring continued significant volatility in power prices, making prices more difficult to forecast than previous years.

Nord Pool System spot price might not tell the full story

During 2021, there were unusually large differences in prices between the Nordic countries and even between different price zones (within the same country), with prices spreading more than 10x at times (see Chart 15). Sweden has seen price spreads for years, but the disparity is much larger now, and Norway is following suit. In our view, the Nord Pool System spot price is therefore not a precise indicator of companies' achieved power prices. This is because the main generation capacity is typically located in the two most northern prices zones, which have the lowest prices. This implies that the generators in most cases are not selling electricity at Nord Pool System average prices, but rather the applicable price in the zone where the power is generated.

In Sweden, restrictions in the main grid mean that production from hydro and wind power in the northern parts of the country cannot be sent to the southern parts, where most of the consumption currently takes place. Investments are set to rise sharply to about Swedish krona (SEK)6.0 billion-SEK7.0 billion annually in 2022 and 2023, up from SEK3.5 billion 2021. However, we expect that it will take until at least 2025 for the Swedish electricity transmission system operator Svenska Kraftnät to address this bottleneck.

While the bottleneck is in Sweden, it is restricting electricity flow in the entire Nordic region. Norwegian transmission grid operator Statnett SF therefore curbed electricity transfers to southern Sweden during late 2021, cutting capacity by 1,000 MW, or 45%, in reaction to lower flows in the opposite direction. The transmission issue has been reinforced by reduced planned electricity production in the south of Sweden, since nuclear power plants were closed before the reduction in electricity production. For this reason, price area 4 (southern part of the Nordic region) is more linked to European electricity prices.

To a large extent, this is the result of Sweden's limited transmission capacity and historical underinvestment in power grids now impacting Norway and Finland. Over medium to long term, we expect the northern part of Sweden will see significantly higher consumption growth than the rest of the area, due to many large industrial projects. This will likely mute somewhat the power surplus in this region and the current large power price differences between north and south of the Nordic region.

Power prices are likely to remain high, with greater volatility than in the past

We expect power prices in the region will benefit from continued export potential as well as an increase in power consumption in coming years from electrification of the economy as countries put decarbonization plans into action. We see higher consumption coming from electrification of transport, heating, and industries. The latter are notably steel and battery manufacturing as well as green hydrogen projects, which are also scaling up in the region. By 2030, we believe annual consumption in the Nordic region could approach 450 TWh-500 TWh, an increase of about 25%-30% from 2020.

But beyond the fundamentally higher demand growth, we see increased price volatility as the power market becomes more sensitive to weather conditions, both on the supply and on the demand side. Indeed, power generation will increasingly depend upon hydrology and wind conditions, given the large installed base of hydro power and the fast-growing wind capacity. At the same time, sensitivity to temperatures could increasingly change demand for power, as few investments are directed toward baseload capacity. We note that prices have been abnormally high over the past six months, which is somewhat unusual in a region that consumes most electrical power in the colder winter months. This means that if there is a period of colder weather in February or March, we should expect to see even higher spikes in prices. For 2022, we now expect power prices of €50/MWh-€65/MWh and €35/MWh-€50/MWh in 2023 (see Table 12).

Table 12

S&P Global Ratings Price Assumptions For The Nordic Region
	2018a	2019a	2020a	2021a	2022f	2023f
Prices (€/MWh)	44.0	39.0	11.0	63.0	50-65	35-50
a--Actual. f--Forecast. MWh--Megawatt hour. Source: S&P Global Ratings.

Nordic power prices are closely correlated with German ones (see Chart 14), but with some discount. We notice that the discount has widened with rising prices, which has been triggered by the price of gas in Europe and carbon emissions. We believe the widening discount is explained by the large share of hydro production and renewable production in the Nordic area. Nevertheless, we expect that the fuel-based production costs and carbon emissions will remain an important price-setting factor also over 2022 and 2023, especially in the southern parts of Sweden (price zones SE3 and SE4). This is because of continuing coupling between countries via additional interconnectors. Rebounding gas demand, supply shortness across Europe, and reduced supply from Russia saw many European markets hit record prices, including the Nordics.

Despite the high prices, rated generators, such as Vattenfall AB and Fortum Oyj (including Uniper SE), are unlikely to fully capture the great increase in electricity prices. This is partly because of their high share of locked-in prices (hedges or long-term contracted renewables in particular), which we view positively, since this secures cash flow during periods of heavy investment, and partly also due to increasing differences between price areas limiting upside. Most producing assets are located in price zones that have the lowest level of achieved prices. Over 2021, we witnessed the spread as large and increasing. Statkraft AS is likely to be the exception because it sells a larger part of generation on the spot market than peers and has the lowest average cost of production in the Nordics. As such, we expect very strong cash flow for Statkraft in 2021 and 2022.

Table 13

Key Power Companies We Rate In The Nordics
Company	Rating	Total production 9 month 2021 (TWh)*	Expected effective prices 2021, including hedges and power purchase agreements (€/MWh)	2022 hedge (%) on Sept. 30, 2021	Expected effective prices 2022, including hedges and power purchase agreements (€/MWh)	2023 hedge (%) on Sept. 30, 2020
Fortum Oyj	BBB/Stable/A-2	41.4†	45-50‡	65% at €32/MWh	40-45	40% at €31/MWh
Orsted A/S	BBB+/Stable/A-2	14.9	N.A.§	N.A.	N.A.§	N.A.
Statkraft AS	A-/Stable/A-2	51.3	N.A.	N.A.	N.A.	N.A.
Vattenfall AB	BBB+/Positive/A-2	80.6	30-35	78% at €29/MWh	30-35	41% at €28/MWh
Uniper SE	BBB/Stable/--	N.A.	28-30	85% at €28/MWh	28-30	55% at €21/MWh
*Data for 2020 was not available. §Offshore wind capacity in Denmark is fully contracted. †Including Uniper from second-quarter 2020. ‡Only Nordic. TWh--Terawatt hour. MWh--Megawatt hour. N.A.--Not publicly available. Source: S&P Global Ratings.

High prices are raising affordability concerns, but we see limited risk of political intervention for generators

Spiking power prices and sharply increasing electricity bills have intensified public and political debate around the power market in the region in recent months. In Norway, the government announced that they intend to cover 80% of electrical bills when the spot price is above Norwegian krone 0.70/kWh. In Sweden, the government announced in January that all households that use more than 2,000 kWhs per month will receive up to SEK2,000 per month for January, February, and March. Despite increased political debate, we see limited risk that any government in the region would introduce intervention that would directly weigh on a rated generator, as was the case, for example, with Electricite de France S.A. in France. In Sweden, the Social Democrat minority gave unexpected support for nuclear in the EU taxonomy. The Swedish government has also taken a final decision about how to handle nuclear waste, which has been a long debate. Finland has already decided on how to store the waste and has the repository ready. This reduces uncertainty from a financial and operational standpoint on nuclear waste.

Material changes to the Nordic power landscape will gradually affect the power balance and prices

Over the past five years, the region's renewable capacity buildout has been rapid. To date, the capacity additions have been the largest in Sweden and Denmark, where we expect renewables will generate about 28 TWh and 16 TWh, respectively, or about 17% and about 50%, of the region's total electrical production. In Norway and Finland, the buildout has been slower, but is set to ramp up. Norway's strategy is to have 3 GW of offshore capacity by 2030, which should be doable; the country's power production is, however, already almost emission free given close to 100% is derived from hydro. Finland's strategy is to increase its use of renewable energy to more than 50% by 2030, primarily with the use of biofuel and wind. Denmark aims to cut emissions by 70% from 1990 levels by 2030 and for renewables to cover at least half of the country's total energy consumption by 2030, which broadly is already done. The country is however still relative dependent on fossil fuel for the remaining percentage of the production. According to International Energy Agency (IEA), Denmark is a global leader in wind energy, as it has the highest share of wind of any IEA country.

Nevertheless, we see a clear risk that the increasing share of wind in the Nordic power system will increase volatility, a trend that has already started. As can be seen in Chart 17, the generation from wind varies substantially, from close to zero to about 40% of total generation during peak hours in Sweden during 2021. This means, despite the large share of hydro in the Nordic system, which typically is very flexible, and which puts the Nordic countries in better position than most other European countries, we still see large needs for capacity that quickly can start to generate electricity when needed, given the recent years rapid wind expansion.

A major capacity increase should come in the near term in Finland. We expect TVO's nuclear power plant Olkiluoto 3 (OL3) will start operations and be ramped up over the year. The generation capacity of 1,600 MW should substantially reduce Finland's current need to import power, resulting in 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. Additional interconnectors that are currently under construction will likely lead to power prices approaching even closer to those of Continental Europe. All in all, interconnection capacity will increase Nordic export capacity to over 13.0 GW by end-2023 from 6.9 GW at end-2020. The main connections are the NordLink, which 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 NordLink cable has yet not been used at full capacity, because there appear to be some technical limitations in terms of its ability to handle increased capacity.

Related Research

• Higher Tariff Cap, Proposed Reform, And Support For Households Ease Pressure On U.K. Energy Suppliers For Now, Feb. 10, 2022
• S&P Global Ratings Revises Oil And Natural Gas Price Assumptions For 2022-2024, Jan. 20, 2022
• Electricité de France Placed On CreditWatch Negative On Nuclear Outages And Adverse Political Decisions, Jan. 17, 2022
• Nuclear In Europe: Lessons Learned And Ways Ahead, Dec. 16, 2021
• Energy Are High Prices Here To Stay?, Dec. 1, 2021
• U.K. Energy Reforms Unlikely To Prevent Imminent Supplier Failures But Will Boost Resilience Over Time, Nov. 2, 2021
• European Electric Utilities Face Higher Social Risks Than Their U.S. Peers, Oct. 13, 2021
• Price Tremors Threaten Europe's Gas Bridge, Oct. 5, 2021
• The Energy Price Crisis: Examining The Impact On U.K. Suppliers, Sept. 30, 2021
• Fit for 55: The Gains (And Pains) For European Utilities, Sept. 29, 2021
• The Hydrogen Economy: Hot Air Or Future Reality?, April 22, 2021
• Energy Transition: How Far Off Is The Hydrogen Economy?, Dec. 3, 2020
• How Hydrogen Can Fuel The Energy Transition, Nov. 19, 2020
• Clean Hydrogen Is Still A Leap Of Faith For European Utilities, Nov. 16, 2020
• The Path To Germany’s Coal Exit Has Diverging Credit Implications For Utilities, Nov. 16, 2020

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
	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
Research Assistant:	Alejandra Munoz, Milan