S&P Global Ratings generally sees higher, more credit-supportive prices by 2022 on the back of a recovery in gas and carbon prices and because Germany will swing from being a net importer of energy from being an exporter of about 40TWh today. The gap in energy supply is likely to be filled by further major additions of solar and power, growing to about 43% of the European generation mix in 2030 from 23% in 2018 (excluding hydro's 10% share). We believe the growth of renewables will imply more (weather-dependent) volatility in prices and will require grid investments and backup solutions to ensure supply security.

The push for energy efficiencies and deindustrialization in some countries is resulting in flattish demand. EU policies target 32.5% of energy savings by 2030. However, the electrification of industry, heating, and transportation mean demand might start growing substantially five years from now.

The upward slope in power prices in is likely to benefit more merchant-exposed baseload producers, such as Statkraft AS, EDF S.A., Fortum Oyj, Uniper SE, and Verbund AG. However, the credit impact of the forecast rise in power prices on most of the large European utilities we rate should be more limited because their EBITDA sensitivity to merchant power has decreased markedly. Most utilities have sold part of their generation fleet and have invested massively in long-term contracted or subsidized renewables projects.

Table 1

Power Price Historical And Expected Evolution For EMEA
€/MWh	2017 historical price	2018 historical price	2019-2021 S&P Global Platts baseload power forecast	2019-2021 S&P Global Ratings base-case assumption*
Germany	34	44	36-41	35-37
France	45	50	37-42	43-48
U.K.	52	65	43-50	40-52
Italy	53	61	48-53	50-60
Spain	52	57	41-50	45-55
Nordics	29	44	N.A.	30-40
*S&P Global Ratings' base case assumptions reflect a mix of actual price hedge levels contracted by the key rated generators in each market, together with our expectation of future prices. Even though we may be informed by them, our expectations may differ from the forward curve, our own commodity price assumptions, and forecasts by other market sources, including S&P Global Platts Analytics. Data that S&P Global Platts use includes independent and verifiable data collected from actual market participants. Any user of the S&P Global Platts' data should not rely on any information and/or assessment therein in making any investment, trading, risk management, or other decision. EMEA--Europe, Middle East, and Africa. MWh--Megawatt hour. N.A.--Not available.

The prices and assumptions that S&P Global Ratings uses, for the purposes of its ratings analysis, may differ from those that S&P Global Platts reports. Data that S&P Global Platts uses includes independent and verifiable data collected from actual market participants. Any user of S&P Global Platts' data should not rely on any information and/or assessment therein in making any investment, trading, risk management, or other decision.

Table 2

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Germany
€/MWh (real 2018)	Baseload power	Clean spark spread	Clean dark spread
2017	34.1	(3.3)	3.0
2018	44.5	(7.6)	1.5
2019	38.3	0.8	(6.4)
2020	36.4	1.8	(8.4)
2021	40.7	(0.6)	(9.3)
2022	48.6	(2.1)	(9.0)
2023	56.6	(2.3)	(4.1)
MWh--Megawatt hour. Source: S&P Global Platts.

The prices and assumptions that S&P Global Ratings uses, for the purposes of its ratings analysis, may differ from those that S&P Global Platts reports. Data that S&P Global Platts uses includes independent and verifiable data collected from actual market participants. Any user of the data should not rely on any information and/or assessment therein in making any investment, trading, risk management, or other decision.

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

Analyst: Bjoern Schurich

The generation mix is in continuous transformation

The German power landscape is undergoing a dramatic change to meet the country's ambitious climate goals of reducing greenhouse gas (GHG) emissions by 40% by 2020, by 55% by 2030, and 95% by 2050 compared to 1990. The country introduced its"Erneuerbare Energie Geset" (EEG) subsidy scheme in 2003, which sparked the change to its energy mix. As a result, renewable power contributed to more than 40% of total capacity in 2018 (up from 8.5% in 2003), constituting about 21% wind, 8% PV, 8% biomass, and 3% hydropower. Yet the country still relies on hard coal for about one-third (about 24GW installed net capacity in 2018) and lignite power plants (21GW in 2018). Germany plans to reduce those numbers to a combined 30GW by the end of 2022 and to 8GW and 9GW for hard coal and lignite by the end of 2030. We believe the pace of this partial phaseout will also depend on the cost position compared to gas. Gas plants represent about 14% of total net generation capacity. and we see their load factors increasing in the coming years, replacing coal and lignite.

After a fundamental shift in public perception following March 2011 Fukushima nuclear accident, the German government changed its policy on the role of nuclear as a bridge technology on its way to a green energy future. As a result, eight of 17 nuclear reactors were immediately shut down, reducing installed nuclear power's net capacity to 12 GW from 20 GW. The remaining capacity is scheduled to decline to zero by the end of 2022 from 9.5GW in 2018 (5% of total net capacity; 13% of total net production).

Gross power consumption has remained flattish at about 600TWh (540TWh net) in Germany since 2000. Electrification of further sectors, such as heating, transport, and data centers point to a rising trend, however, increasing energy efficiency and the "smartening" of electricity networks, including the bundling of electric vehicle and other storage capacities, have the potential to mitigate the trend at least for the coming five years.

Prices driven by imports, gas, and CO2

We expect power prices to increase faster in Germany than in neighboring countries over 2020 to 2025. We see the faster pace of reduction in conventional power capacity in Germany than in neighboring countries as the key inflationary driver. In addition, gas prices paired with evolution of CO2 prices, will become more prominent in determining German power prices in the medium term. Further, we expect Germany to become a net power importer, which will support its domestic power prices to catch up with European neighbors.

We see an upward trend in power prices, favored by reducing base load and higher-priced imports in the short term

We expect Germany's power prices to approach France's in 2023 given that France is set to become the main source of Germany's power imports. Europe's power markets are increasingly interlinked under EU single market rules and are currently still driven by exports from the biggest electricity market in the EU, Germany (foreign trade export surplus at about 40TWh in 2018). However, in 2022 Germany is expected to be hardly covering its peak demand of about 82 GW by reliable base load capacity, even after considering its additional capacity reserve of 2GW starting in 2020. With an increasing share of cross-border electricity interconnection capacity (EU regulation postulates a minimum of 70% of crosszonal trade capacity from 2020), imports could become a more prominent driver for EU market integration and hence power price alignment.

We expect domestic electricity supply and demand imbalances in the German price zone to relax and hence tensions on prices to reduce after 2025. That is, given the expected progress on:

• European and domestic network development, specifically North-South transport and cross-country interconnectors;
• Further renewable penetration, paired with a build-up of storage capabilities; and
• Sector coupling, that is, power to gas (green hydrogen, methane).

How do renewables play a role in the mix and in the price?

Germany is set to continue to achieve minimum of 65% of its renewable expansion goal by 2030 from about 43% in first nine months of 2019. The interplay of an increasing degree of volatile renewables generation, combined with inflexible base load within the energy mix, has led to more volatile as well as negative power prices. However, the expansion of onshore wind power--which Germany intends to drive the bulk of the energy mix transition--is facing major hurdles on the back of an ever-longer permitting processes. After already being 400 MW short of the 2,800MW annual statutory target in 2018, in the first half of 2019 onshore wind installations fell by 82% to 287MW versus 1,626MW in the first half of 2019. If the trend persists, more wind turbines could be taken off the grid than added, making German renewable targets impossible to reach. Next to permitting, we observe that real estate market conditions have become a prime consideration for onshore wind power expansion.

To counter the fallback, in October 2019, the German government scaled back Germany's PV expansion ambition to 98GW by 2030 and lifted the 52GW total capacity limit, after which subsidy payments were planned to stop.

The significant penetration of renewables will exacerbate the volatility of power prices. Germany experienced negative power prices over short period in the past, due to very high generation from wind and solar, paired with reduced demand and continued feed-in by inflexible base load capacity. While we see average power prices rising, we do not exclude high volatility due to similar intraday or seasonal situations. In the medium to long term, increased storage capabilities should mitigate supply and demand imbalances and therefore power price volatility.

Beyond power prices, how can generators remain profitable?

We believe it is likely that Germany will introduce a capacity market where gas turbines and storage solutions should play a crucial role. Besides the recently tendered 2GW of additional off-market capacity by the regulator, there are no medium- or long-term capacity payments contracted for the German power market as of now. However, to mitigate the mounting dependency on imports and to be able to provide sufficient security of supply, the German government has the option to follow the so-called coal commission's recommendation to introduce a risk-oriented monitoring of supply security with the help of facilitating expansion of gas-fired generation. As such, we expect incentives to be introduced for highly efficient CCGTs (combined cycle gas turbines) as well as for gas-fired CHPs (combined heat and power) generators. Efficient hard coal plant operators could still benefit from being moved into an off-market reserve or re-equip coal to CHP gas-fired plants. In any case, Germany as a future large-scale net power importer, without the help of flexible feed-in sources in the long term, is hardly sustainable against conventional power capacity falling nearly everywhere in Europe and more volatile capacity being built up to achieve Europe's CO2 neutrality goal by 2050.

Beyond capacity payments, relatively low natural gas prices, together with rising CO2 prices, already render gas turbines increasingly more profitable, pushing hard coal and even lignite plants out of the energy mix at times.

Renewable generation and storage

In 2021 the first 3GW (6,000 plants) of 20-year subsidy schemes are running out, resulting in plants becoming merchant power generators. As such, long-term contracting via the help power purchase agreements (PPAs) will become crucial for the generation of stable cash flow. We expect rising wholesale power price expectations in the short term to support the development. Further, renewable energy generators after the end of the EEG subsidy scheme are entitled to sell green certificates in the form of "guarantee of origin." Beyond, and in the long run, storage or power-to-gas will become a prime consideration, in combination with renewable energy plants, to boost profitability. As such, also fading coal-fired power plants can be converted into heat storage facilities fueled by renewable energy.

Key players that we rate

Among the key power producers, in Germany we rate:

• Uniper SE (BBB/Watch Neg),
• E.ON SE/innogy SE (BBB/Stable/A-2),
• EnBW Energie Baden-Wuerttemberg AG (A-/Stable/A-2), and
• Verbund AG (A-/Stable).

Table 3

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For France
€/MWh (real 2018)	Baseload power	Clean spark spread	Clean dark spread
2017	44.9	7.4	13.8
2018	50.3	(2.2)	7.3
2019	40.0	2.3	(4.8)
2020	37.7	2.8	(7.1)
2021	41.9	0.3	(8.1)
2022	48.0	(3.1)	(9.5)
2023	53.8	(5.7)	(7.0)
MWh--Megawatt hour. Source: S&P Global Platts.

The prices and assumptions that S&P Global Ratings uses, for the purposes of its ratings analysis, may differ from those that S&P Global Platts reports. Data that S&P Global Platts uses includes independent and verifiable data collected from actual market participants. Any user of the data should not rely on any information and/or assessment therein in making any investment, trading, risk management, or other decision.

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

Analyst: Claire Mauduit-Le Clercq

Generation mix dominated by nuclear and hydro; growth in wind and solar will not move the needle

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 (478TWh of gross consumption in 2018). The country's Energy Law, passed end-September 2019 (and related PPE energy plan over 2019-2028) sets a roadmap for ambitious growth in renewables and reduced nuclear in the energy mix to 50% by 2035 from about 75% today. However, nuclear reactor closures will only start in 2027 at a pace of one reactor closure a year (with flexibility on two additional plants in 2025 and 2026 depending on energy policy of neighboring countries). We believe this leaves little space for fulfilling renewables goals over the coming decade.

Flattish-to-declining demand driven by the push for energy efficiencies. We expect flat-to-slightly negative power demand until 2030 as the fruit of energy efficiency initiatives from all grid stakeholders more than offsets any additional demand, which should arise from the growing electrification of industry and e-mobility trends. Indeed, we believe France is country where electrification of industry and housing is already high compared with those of European peers (electric heating penetration for instance is about 30% according to ADEME). We also forecast that additional demand from electric vehicles will not be a game changer for demand patterns in the next decade.

Price drivers: dictated by nuclear tariff mechanism

EDF's French production is partly exposed to the ARENH mechanism, which is not only relevant for determining ARENH output sold to competitors, but also for setting the regulated customer Blue Tariff (about 30% of domestic consumption). ARENH, which stands for Regulated Access to Incumbent Nuclear Electricity, 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 (100TWh potentially increased to 150TWh option embedded in Energy Law). As such, ARENH plays a key role in retail electricity prices.

We see an upward trend in power prices, favored by export potential

We expect power prices to remain sustained in France over 2019-2022, on the back of a relative balance of internal supply and demand: €43/MWh in 2019, rising to €45/MWh by 2020 and €48/MWh in 2021.

Indeed, we are forecasting in our base case relatively stable nuclear output over the next five years. This is in line with the country's PPE roadmap that contains no preset closures of reactors before 2027. We assume the decommissioning of the two 0.9GW Fessenheim units is not perfectly synchronized with the start-up of the new 1.7GW Flamanville 3 (FLA-3) reactor and, as a result, nuclear capacity drops by an average 0.7GW in 2021-2022. We have not factored unexpected outages related to ASN's investigation into technical deviations regarding the manufacturing of 20 steam generators (affecting six reactors potentially). Any unexpected outages would squeeze capacity and create price spikes.

Renewables growth nevertheless remains a key unknown supply parameter with strong government ambitions when it comes to promoting the development of renewable energy, with French wind and solar capacity both forecasted to more than double by 2030 from 2018 levels (15GW and 9GW, respectively). We still believe that capacity growth will be paced in conjunction with export needs to avoid overcapacity and strain prices.

Indeed, we expect increased export potential for France because of tightening of neighboring countries and of new interconnection capacity. French net exports will increase in the first instance with new interconnections coming online: 2GW with the U.K. in 2020 (IFA2 & ElecLink) and 1.2GW with Italy (Piemont-Savoy) in 2020 as well. Short-term tighter capacity from neighbors, particularly Belgium, Germany, and Italy, is likely to provide additional export capacity for France's generation output. As a material key factor, Germany is expected to close down about 8GW of nuclear capacity by end-2022, combined with about GW lignite capacity being withdrawn from the sector.

How do renewables play a role in the mix and in the price?

France's energy transition law sets forth ambitious growth, with the share of renewables targeted to reach 23% of gross final energy consumption by 2020 and to 32% by 2030, and 40% of electricity production in 2030. While solar seems on track to meet the solar targets by 2023 (20.6GW installed capacity from about 10 GW as of 2019), we believe the increase will be more gradual for onshore wind in the context of acceptability and permitting issues slowing down progress.

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

Beyond power prices, how can generators remain profitable?

Capacity payments play a marginal role in producer's earnings, given the limited size of the capacity market in France.

However, we note that the stability of generation earnings is ensured by regulated end-users tariffs (TRV), promoted by CRE and calculated by aggregating all components of electricity prices. By allowing a form of cost pass-through to final customers, it provides a floor to electricity suppliers in case of a downturn in power prices.

Key players we rate

• Electricité de France S.A. is the historical dominant electricity operator in France, accounting for almost all of the market's generation capacity.
• Engie S.A. is a France-based natural gas and electricity supplier, focusing also on renewables (in France and in the Americas) with an ambitious plan of 10.8GW of sell-downs over the next five years.

Table 4

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For U.K.
£/MWh (real 2018)	Baseload power	Clean spark spread	Clean dark spread
2017	51.8	6.6	(2.7)
2018	64.9	4.4	(1.6)
2019	49.2	3.3	(17.6)
2020	43.2	0.6	(17.8)
2021	46.9	(0.5)	(15.5)
2022	52.0	(2.0)	(11.6)
2023	58.3	(2.7)	(6.4)
MWh--Megawatt hour. Source: S&P Global Platts.

The prices and assumptions that S&P Global Ratings uses, for the purposes of its ratings analysis, may differ from those that S&P Global Platts reports. Data that S&P Global Platts uses includes independent and verifiable data collected from actual market participants. Any user of the data should not rely on any information and/or assessment therein in making any investment, trading, risk management, or other decision.

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

Analyst: Matan Benjamin

Low carbon, higher imports, and lower consumption

Fossil fuel power sources no longer dominate the market. Environmental targets have been high on the political agenda in the U.K. over the last few years. Consequently, the U.K. government has committed to a net-zero carbon emissions policy by 2050 in June this year. The transformation toward low carbon generation is, however, already in play. Out of the 333TWh produced in 2018, low carbon generation accounted for about 55% of low carbon generation (33% renewables and nuclear 19%), compared with just 19% 10 years ago. Gas and coal generation accounted for about 45%, compared with about 77% in 2008, according to "Energy Trends: UK electricity," published June 27, 2013.

Imports are a significant source of electricity supply. The U.K. has been a net importer of electricity since 2010 and in first-quarter 2019 imports accounted for 6.8% of total electricity supply. This is based on five interconnectors that allow trade with continental Europe, representing overall capacity of about 5GW, according to "Energy Trends: UK electricity."

Electricity consumption in the U.K. is declining. Electricity consumption remained stable in 2018 at about 300TWh, compared with 2017, but current consumption is about 15% lower than in 2008. The decline in consumption is associated with weaker industrial activity and increased energy efficiency measures. For similar reasons, we see demand remaining stable over the next two to three years.

Prices driven by gas and CO2

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

U.K. power prices are further supported by the carbon price floor. The U.K. has taken steps to provide a stronger price signal to the market by implementing a carbon price floor since 2013, which is now set at 18£/ton, a level close to current ETS but well above where carbon has traded in Europe for years. This has notably led to higher prices than in continental Europe and also accelerated the closure of less efficient coal plants.

As a result, with expectations of uplift in both gas and carbon prices, we see power prices in the U.K. gradually recovering from current levels.

How do renewables play a role in the mix and in the price?

Renewables are becoming more competitive. The U.K. has had a long track record of supporting renewables through government policies and subsidies such as the Renewable Obligation Certificate (ROC) and contract for difference (CfD). Plus, improvements in product design and manufacturing efficiency have led to a material decline in the cost of renewables, making them competitive relative to traditional fuels such as gas. Given weather constraints, wind, both onshore and offshore, has been largely favored over solar. The cost competitiveness of renewable technologies was clearly demonstrated recently by the 15-year, 2.2GW contract (under the CfD scheme) secured by SSE PLC in September 2019 for strike price of about £40, at or below the market spot price. Over the long run, given the increasing share of renewables in the overall electricity mix continue, we believe power price are likely to decrease.

Beyond power prices, how can generators remain profitable?

The capacity market scheme in the U.K. is back. On Oct. 24, 2019, the European Commission approved the British Capacity Market scheme initially introduced in 2014. The U.K. Capacity Market scheme aims to ensure the security of electricity supplies in view of volatile demand and the closure of generation capacity, specifically coal generation. Successful bidders in market auctions make a commitment to provide capacity at times of stress events on the electricity system and, in return, they receive a steady payment for the duration of the capacity agreement. Failure to comply with the commitment exposes generators to financial penalties. The capacity market in the U.K. entered a standstill on Nov. 15, 2018, following the EU's General Court of Justice ruling in favor of Tempus Energy against the European Commission, revising the Commission's decision not to raise objections to the aid scheme establishing a capacity market in the U.K. As a result, the U.K. government couldn't hold any capacity auctions, make any capacity payments under existing agreements, or undertake any other action that could be seen as granting state aid for almost a year.

We previously stated that we expect the standstill to be temporary. In our view, the capacity market scheme has an important role in incentivizing sustainable investment, reducing the costs of energy to consumers, and ensuring the security of supply. The capacity market scheme creates incentives for generators to be available at times of system stress, which in turn reduces spark spreads and wholesale energy prices. With the U.K. capacity market being reinstated and deferred payments to be honored, we expect this to benefit companies that have committed to significant volumes as part of the capacity auctions. Among others, this includes EDF S.A., Uniper SE, Drax Group Holdings Ltd. (BB+/Stable), InterGen N.V. (B+/Stable), SSE PLC, and Centrica PLC.

The players we rate:

• SSE PLC (BBB+/Stable/A-2). SSE is a listed, investor-owned energy company with generation, transmission, distribution, and supply operations in Scotland, England, Wales, and Ireland, with S&P Global Ratings-adjusted EBITDA of around £1.8 billion as of March 2019. As of March 31, 2019, SSE had total installed capacity of 10.5GW and total generation output of 30,835GWh. Currently gas and oil still account to about 50% of total generation capacity, however, SSE has growing portfolio of renewable assets in the U.K. SSE had 2.4GW of renewable energy in 2010, and 3.8GW as of March 31, 2019, and it targets capacity of about 4.0GW by 2020. SSE has recently taken steps to better- manage its trading activities including its approach to hedging. Based on the new approach the group generally hedge 85% of expected output 12 month in advance of delivery. SSE has agreed a transaction to sell the U.K. supply operations as part of its strategy of focusing on networks and renewables.
• Centrica PLC (BBB/Stable/A-2). Centrica is an international integrated energy company operating in the U.K., Europe, the Republic of Ireland, and North America with S&P Global Ratings-adjusted EBITDA of around £2.4 billion as of December 2018. Centrica is the largest supplier of electricity and gas in the U.K. Centrica also has exploration and production (E&P) assets in North West Europe with reserves of 203 million barrels of oil-equivalent in 2018. In generation, Centrica has 20% interest in eight nuclear power stations in the UK, which has produced 11.8TWh of electricity in 2018. Centrica has recently announced its intention to sell the nuclear and E&P operations and focus on client facing business.
• Scottish Power Ltd. (BBB+/Stable/A-2). Scottish Power, as a subsidiary of Iberdrola, is a vertically integrated electric and gas utility with operations in the U.K. Its generation segment, exclusively from renewables (offshore and onshore wind), accounted for 29% of its total reported EBITDA (£1,744 million) as of Dec. 31, 2018. At the same period, its installed capacity totaled 2.1GW, with a total output of 10,675 GWh. With the gradual sale of its conventional generation assets--highlighted by the sale of thermal (and hydroelectric) assets to Drax in 2018-- Scottish Power has transitioned to carbon-free generation. The group currently benefits from attractive and stable remuneration scheme (such as CfD for its assets, as highlighted by Scottish Power's main renewables project's (EA1, 714MW) remuneration of £119.89/MWh (real 2012 + consumer price index) over 15 years cleared in 2015 for the first U.K. CfD renewable auction). Going forward, Scottish Power intends to see renewables generation to drive its future growth based on an ambitious business plan targeting a 49% increase in capacity by 2022 but this will be contingent on future renewable auctions clearing prices.
• Drax Group Holdings Ltd. (BB+/Stable). Drax is an integrated U.K.-based coal and biomass power generator. The group continues to carry a significant exposure to coal and thermal generations with approximately half of its 6.5GW installed capacity dependent on coal and CCGT power plants following the acquisition of Scottish Power's in 2018. Drax remains exposed to volatile market prices for commodities and power as a result, and is subject to rising regulatory and environmental constraints as two units remain coal-fired--the fourth unit was switched to biomass in 2018. The group nevertheless has an active hedging policy, which aims to hedge most of the company's output over two to three years, thereby somewhat reducing intrayear swings in earnings. Drax has achieved hedged prices of £50-£56 in 2018-2021 as of April 2019. The generation of renewable power from biomass fuel generates subsidized earnings from renewable obligation certificates and CfDs, which limits exposure to wholesale power prices.
• InterGen N.V. (B+/Stable). Following the sale of its Mexican assets, InterGen now operates a 3.3GW portfolio of which 2.9GW are located at three similarly sized CCGTs in the U.K.: Spalding, Coryton, and Rocksavage and a new built open-cycle gas turbine (OCGT). The Spalding CCGT is fully contracted until 2021, providing visibility and predictability on its future cash flows contribution to the group in the near term. However, the Coryton, and Rocksavage power plants continue to generate most of their cash flow from merchant energy margins, with minimal hedging, exposing them to volatility in the U.K. wholesale electricity market. This will also be the case of the new built OCGT power plant.

Table 5

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Italy
€/MWh (real 2018)	Baseload power	Clean spark spread	Clean dark spread
2017	52.7	10.7	21.6
2018	60.7	4.9	17.7
2019	52.8	10.3	8.7
2020	48	8.8	3.2
2021	52	6.8	2
2022	58.5	4.1	1
2023	63.9	1.2	3.1
Source: S&P Global Platts.

The prices and assumptions that S&P Global Ratings uses, for the purposes of its ratings analysis, may differ from those that S&P Global Platts reports. Data that S&P Global Platts uses includes independent and verifiable data collected from actual market participants. Any user of the data should not rely on any information and/or assessment therein in making any investment, trading, risk management or other decision.

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

Analyst: Massimo Schiavo

Italy to remain a premium market in terms of power prices due to the predominance of thermal generation and lack of domestic supply

The Italian power market will see significant changes in the next few years as its fuel mix undergoes a transformation, with more renewables and a decline in coal. However, we expect Italy to retain its position as the premium market in terms of power prices in Western Europe to 2025, and for prices to rise consistently in real terms between 2020 and 2025. We note imports play an important role (about 7.5GW expected over 2020-2025) for the Italian power market, given the lack of domestic supply. Capacity on the northern borders should increase by 2.2GW by 2025, including 1.2GW with France and 1.0GW with Switzerland. This new capacity and a steady Italian premium should increase imports by 50% in 2025 versus 2018 levels.

Gas will remain the price setter

This is partly due to Italy's large gas capacity, which makes its power prices heavily dependent on PSV ("punto di scambio virtuale" or virtual trading point) gas prices, which are also consistently above those of other European hubs.

Another element of dependence on PSV gas prices is Italy's coal phaseout, which is set to end by 2025 in the National Energy Strategy, translating into a forecast reduction of 2GW in coal capacity by 2024 and by a further 6GW in the following year. Coal closures mean that gas will remain the dominant technology in Italy in the near future.

Renewable energy will not provide credible mitigating factor

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

Rated Italian power producers have rather short-term hedges by European standards

We note Italian power companies are hedged at relatively high prices, especially compared with the rest of Europe, and we notice a fairly liquid market. For Italian integrated utilities, we note hedging from supply, given vertical integration.

Among the key power producers, in Italy we rate:

• Enel SpA (BBB+/Stable/A-2), with 80% of 2019 production hedged at 52€/MWh and 20% of 2020 at 55.8€/MWh.
• A2A SpA (BBB/Stable/A-2), with 65% of 2019 production hedged at 62.3€/MWh and 34% of 2020 at 62.2€/MWh.

Table 6

Baseload Power, Clean Spark Spread, And Clean Dark Spread Evolution For Spain
€/MWh (real 2018)	Baseload power	Clean spark spread	Clean dark spread
2017	52.2	N/A	21.2
2018	57.3	N/A	14.3
2019	49.6	7.8	4.9
2020	41.2	4.6	(3.6)
2021	44.9	1.5	(5.1)
2022	50.1	(2.8)	(7.5)
2023	52.8	(8.3)	(7.9)
MWh--Megawatt hour. Source: S&P Global Platts.

The prices and assumptions that S&P Global Ratings uses, for the purposes of its ratings analysis, may differ from those that S&P Global Platts reports. Data that S&P Global Platts uses includes independent and verifiable data collected from actual market participants. Any user of the data should not rely on any information and/or assessment therein in making any investment, trading, risk management or other decision.

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

Analyst: Gonzalo Cantabrana Fernandez

The Spanish market is dominated by thermal

The Spanish generation mix is dominated by thermal generation (about 50% of total production, mostly gas). Nuclear and wind each represent about 20%, with hydro providing between 7%-15% depending on weather conditions.

The Spanish acting government presented in March 2019 a draft of the Integrated National Energy and Climate Plan 2021-2030, which sets the scene for the country's energy transition. The draft foresees substantial changes in the energy mix from 2020 to 2030 to the detriment of coal (-9.2 GW of capacity), nuclear (-4.2 GW), and cogeneration (-2.1 GW). The plan envisages a substantial expansion of renewables, mainly PV (+28.5 GW), wind onshore (+22.3 GW), thermosolar (+5.0 GW), and pumping hydro (+3.5 GW).

Prices are driven by increasing renewables capacity

Spain, along with Portugal, are the only markets for which our forecast anticipates a drop in energy prices in real terms between 2023 and 2025. The main driver for the decline is our expectations for growth of 15GW of installed capacity in wind and solar capacity by 2025, which will be prioritized over other energy sources and that have a low marginal cost. As is already the case some days of the year, production from renewables will more often represent close to 100% of the country's needs. We expect energy consumption to remain flat, with an increase on consumption being offset by energy efficiencies.

Yet, we expect thermal generation to continue dominating the generation mix (historically 40%-50% of generation) most of the time, with gas as a price setter. We expect coal-fired generation to be gradually replaced by gas-fired generation because of increasing environmental constraints. The substitution of coal for gas-fired generation already accelerated in 2019, notably triggered by falling gas prices, an increase in the cost of carbon, and the elimination of the so-called "green cent" tax on gas used by CCGT turbines and cogeneration units. Together, these developments improved the operating cost of the relatively recent Spanish CCGT fleet by about €5/MWh, hence becoming more competitive than coal.

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

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

Although the national plan is not yet approved and Spain awaits its next government, the market seems to have moved earlier without waiting for public initiatives or policies. Both Spain and Portugal have favorable natural conditions for the development of renewables, allowing higher utilization rates, and renewables are therefore more competitive than in other European markets.

The already high existing share of renewables follows the huge development of renewables in the 2000s, driven by favorable subsidy schemes. This massive growth led to unbearable costs to the energy system, and the government changed the terms of the scheme in 2013 with grandfathering conditions, which was financially detrimental to operators and resulted in the absence of any new investments for some years. The relaunch of auctions in 2017 virtually led to zero-subsidy projects, reflecting the competitive cost of renewables compared with those other energy sources and the sponsors' new appetite for merchant risk. We nevertheless understand that new PPAs will mitigate the majority of the new merchant renewables.

However, we see hurdles in these ambitious growth targets: The financing of merchant projects remains hard to obtain, and the request of connection points for new renewable facilities to Red Electrica (the operator of the Spanish network) have escalated to levels hard to achieve, with more than 66GW of connection points for new renewables as of July 2019.

Beyond power prices, how can generators remain profitable?

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

Key players we rate

• Iberdrola S.A. (BBB+/Stable/A-2) engages in the generation, transmission, distribution, and supply of electricity in Spain, the U.S., the U.K., Mexico, and Brazil.
• Endesa S.A. (BBB+/Stable/A-2) engages in the generation, distribution, and sale of electricity, primarily in Spain and Portugal.
• Naturgy Energy Group S.A. (BBB/Stable/A-2) engages in the gas and power value chain in Spain and Latin America.

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

Analyst: Daniel Annas

Low-carbon, low marginal cost energy mix

The Nordics power market is characterized by a largely low-carbon, low marginal cost generation mix. Wholesale power prices are defined by Norwegian-based company Nord Pool, which governs seven different countries with 16 market zones: six market zones in Norway, four in Sweden, two in Denmark, one in Finland, and one in each one of the Baltic republics: Estonia, Latvia, and Lithuania. As interconnections improve across the zones, prices tend to increasingly converge. These seven countries represent an electricity demand around 420TWh.

Hydro has been the major electricity generator over the last 30 years, representing on average about 55% of total generation in Norway and Sweden. Nuclear comes second, with about 20% over the last 30 years. We do not expect the contribution from hydro or nuclear to decrease in coming years, notably since the upcoming commission of Olkiluoto 3 in Finland will offset the phaseout of Ringhals 1 & 2 in Sweden.

While the remaining share of the mix has historically been thermal (coal, gas, and fuel oil), ambitious energy transition targets have pushed for more wind power, supported by subsidy schemes. Wind generation doubled since 2012, reaching about 40TWh in 2018 and about 10% of total 2018 electricity generation. It will increase massively in the coming five years and we expect capacity to reach 30GW by 2023.

Interconnections are also an important part of the Nord Pool system, with links to Germany, the Netherlands, Poland, but also Russia, from which the zone has a net yearly import of more than 10TWh.

Sweden aims to reach 100% of renewable electricity generation by 2040, but without forcing a shutdown of nuclear. Denmark has a goal stating that renewables should cover at least half of the country's total energy consumption, and by 2050 the country aims to be a low-carbon society independent of fossil fuels. In Finland, renewables represent about 40% of energy consumption, and the objective set to 2030 is to increase the use of renewable energy so that during the 2020s its share in energy end-consumption rises to more than 50%. Norway's electricity is generated mainly from flexible hydropower, approximately 95%, and it is expected to continue to be the backbone of the nation's energy supply.

Price drivers: higher sensitivity to carbon prices

Nord Pool power prices are on average lower than in Europe, and we expect this pattern to remain for some time. This is to a high degree driven by the high proportion of low marginal cost hydro, nuclear, and wind generation, which pushes more expensive thermal power further out of the merit order. Even if declining, thermal power (gas and coal) remains for now the price setter in the region, implying great price sensitivity to carbon prices. In Norway, hydro represents about 95% of all generation, and fossil-based generation is almost only used for peak periods.

We do not see a significant increase in power demand over the coming three to five years, as energy efficiency measures will continue to balance economic growth. Yet as electrification trends continue to reduce carbon emissions, notably for industrial processes and heating solutions, we may see more upside on demand after 2025. This may have some upward price pressure by then.

We believe Nord Pool power prices will go through a significant transformation in coming decade with the ramp-up of renewables (mainly wind). We see price volatility likely increasing further as a result. This could, to some extent, be mitigated by more interconnections, for examples, connecting Norway and Denmark to the U.K. (The North Sea Link and Viking Link), and connecting Norway to Germany (NordLink). It could also result in slightly higher Nord Pool power prices as connecting countries have on average higher power prices.

Renewables targets have already been achieved, halting the need for subsidy schemes

In 2012, Sweden and Norway started a common subsidy system with the goal to increase investments in renewables. The common goal was to reach annual production of 46TWh by the end of 2030, which was accomplished at the end of 2018. As a result, Norway has halted the addition of new renewables into the system until the end of 2021 and will permanently close to the addition of more subsidized renewables in 2036. Sweden is on its way to implementing the same stop mechanism as in Norway.

Finland has not had a similar subsidy schemes for renewables, and therefore its contribution from wind been much lower than other Nordic countries because it has not been profitable to invest in wind power.

Denmark has launched a number of smaller subsidy schemes over the years to boost investments in renewables. The schemes aims to help Denmark achieve its goal of a 50% contribution from renewables of total generation by 2030 and to make the country free of fossil fuels by 2050.

The key Nordic power producers we rate

• Vattenfall AB (BBB+/Stable/A-2) has generation mainly in Sweden, with about 70% of 2019 production hedged at 29€/MWh, about 55% of 2020 at 32€/MWh and about 38% at 33 €/MWh.
• Statkraft AS (A-/Stable/A-2) has an exposure of about 70% of their generation portfolio to Nord Pool spot prices, about 30% if Statkraft's generation will be sold under long-term contracts until 2020. It is our understanding that about 18% of power produced for generation in 2021 is under long-term contracts.
• Orsted A/S (BBB+/Stable/A-2) Global leader in offshore wind with a global market share of about 30%. The company has no public hedging policy.
• Fortum Oyj (BBB/Watch Neg), with about 80% hedged at 33€/MWh for 2019, approximately 70% hedged at 33€/MWh for 2020 and about 35% hedged at 33€/MWh for 2020.

These companies have very different hedging strategies. Statkraft with its liberal hedging strategy has limited to nohedges. That's in contrast to Fortum and Vattenfall with about 80% and 70% hedged for the coming year.

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