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REF-E Scenarios: Update II2021 of July 2021

Scenario Highlights

The Italian recovery path outpaced expectations during the first half of 2021, also sustained by turbulent energy markets. The new scenario update incorporates the most recent trends in import dynamics and commodities markets, the expected impact of the new European Fit for 55 package and the novelties concerning the upcoming Capacity Market auctions. The new scenario analyses also discuss potential pathways towards 2050 carbon-neutrality targets.

The relief of restrictive measures paves the way to an encouraging recovery path, with the Italian economic growth rate expected to align to other European countries by 2022 for the first time after years. According to the Italian Government, the measures of the National Recovery and Resilience Plan (NRRP) alone could contribute to a GDP increase by 3.6% in five years under the hypothesis that European funds are effectively invested, and the planned reforms implemented.
The fall of commodities and energy prices pulled the average Italian consumer price index for year 2020 to -0.1%. However, a faster-than-expected acceleration in prices growth is pushing the inflation higher, with the energy sector seen as the key driver. Very accommodative monetary policies are expected by both the US and the EU to support the economy. Inflation risk may be higher in the US than in the EU, and the exchange rate could reflect the latter divergence in the short-term, favouring a moderate recovery of the euro.

The recent compromise reached by Saudi Arabia and the UAE strengthens the leadership of the OPEC Plus cartel on the oil market and fosters price stability. Last year record cuts have been gradually relaxed, and production is going to be adjusted upward on a monthly basis starting from August 2021 and until the phasing out the overall curbs.
Demand for coal from China and India is expected to keep growing in the short- to mid-term, supporting coal prices globally and influencing the correlated European reference index (API2) consequently.
The slowdown in the growth of new liquefaction capacity, an unusual number of outages and strong Asian demand put significant upward pressure on LNG prices. The effects of the pandemic on investments are tangible, with several projects being delayed or cancelled. A slight compression of the demand-supply margin is expected for winter 2022-2023, but only in the event of colder-than-average temperatures and/or further unexpected supply outages, the market is expected to tighten further. LNG prices are expected to stabilize in the mid-term following a progressive move back to normal market conditions and the diffusion of energy transition policies also outside the EU. A firm recovery in the European gas demand combined with poor LNG arrivals and storages at their historical lows support the TTF price in the short-term. A progressive normalization of market fundamentals is assumed though, with quotations at the Dutch hub expected to stabilize consequently within the next couple of years.
Low LNG arrivals in Europe amid strong Asian demand competition leave room for increasing gas flows arriving from the southern areas in the short-term. The PSV-TTF spread is thought to become structurally tighter than historical averages (below the 1 €/MWh threshold) and to eventually nullify in the mid-2030s.
The Italian gas market follows hence European hubs movements, with dynamics at the PSV hub strictly correlated to the TTF’s. Demand resumption in Italy and the general recovery of European prices favour the parallel recovery of the PSV in the short-term, but a stabilization lead by a return to normal market conditions is expected from 2023.
CO2 prices under the European ETS mechanism moved higher than expected in the first half of 2021, driven by the overall commodities bullish sentiment and by significant buying interest from financial operators - fostered by expectations concerning the Fit for 55 package, that includes a revision of the ETS system. Long-term targets incorporate the reinforced commitment of the European Commission in maintaining the ETS system as key element of the decarbonization strategy: the new ETS configuration should incentivize a demand-offer equilibrium and price levels such to speed up the decarbonization process.
Rising CO2 prices are also expected to support the switch from coal to gas in the power sector, accelerating the green transition process and anticipating the economic phase-out of coal-fired capacity across Europe.

Electricity demand and net imports
The economic recovery is expected to drive electricity demand to pre-pandemic levels in the next few years. In the long-term, electrification and efficiency in final consumptions will become the main drivers of electricity demand. The development of hydrogen applications for industrial processes decarbonization, still undergoing an exploratory phase, could significantly influence the long-term demand trend. Additional electricity demand from EVs can significantly vary based on the future deployment of e-mobility applications in cities and long-term transports. The additional electricity demand for heating and cooling will depend on the pace of installations for civil uses, potentially sustained by support measures for decarbonization put in place in the post-pandemic recovery.
Coal-to-gas switching conditions in Europe influence the evolution of net import flows in the short- to mid-term, with decreasing volumes expected from the northern borders and increasing flows expected from the southern borders. From 2025 onwards, the gradual phase-out of coal-fired and nuclear capacity in continental Europe emphasizes the progressive reduction of imported energy, under the assumption of a partial achievement of 2030 targets by European countries.
Under policy-driven scenario assumptions, the impact of coal-to-gas switching dynamics on net import could be more than compensated by the rapid development of renewable sources, leading to opposite dynamics at the northern borders with imported flows outpacing historical values.
Net import dynamics include the potential impact deriving from the coupling with the Greek power market as indicated by dedicated analyses.

Capacity Market and thermoelectric generation
New Capacity Market (CM) auctions targeting delivery years 2024-2025 are in sight and will be probably held before the end of 2021. The level of adequacy demand to be auctioned will depend also on whether some new projects selected in the 2023 auction, that are still not authorized, manage to get the necessary permits on time with respect to current deadlines (that have been prorogued more than once). Projects obtaining the authorization would be however exposed to the risk of delays during the construction phase – a situation that would have to be managed coherently and considering the extra-time needed to get the authorization before the beginning of construction works. Anyway, the outcome of the 2022-2023 CM auctions is expected support nearly 6.4 GW of additional installed capacity which will join the market progressively in the next years. Such capacity can facilitate the phase-out of coal-fired plants in the peninsula by 2025 but is thought to be not enough to ensure full system adequacy after the coal-fuelled units exit definitively the market: up to 4.3 GW (also considering 500 MW of LNG-fuelled capacity to be auctioned in Sardinia) of new capacity investments are expected to be driven by the new CM auctions. Capacity additions are supposed to be mainly concentrated in the North market zone, where it is assumed the greatest adequacy demand level – the North zone accounts alone for more than half of the Italian electricity demand. All the new projects participating to the auctions are supposed to exploit the 1-year buffer permitted by the updated (proposed) rules of the mechanism.
The newbuild capacity is expected to have relevant impact on the electricity market dynamics, especially the Day-Ahead Market (DAM), where the increasing level of competition could affect the economic sustainability of existing gas-fired generation. Assuming 4.3 GW of new generation capacity to come online after the new CM auctions, missing money issues could arise for existing gas-fired units in the second half of the 2020s, despite the increasing DAM market space generated by the decrease of import flows. Potential extension of the capacity remuneration mechanism could cope with the risk of mothballing and avoid generation adequacy issues in the 2025-2030 period.
Coal-to-gas switching dynamics and increasing logistic costs lead to the economic phase-out of coal-fired units already in the short-term. The administrated phase-out of coal-fired generation by 2025, would bring to the closure of coal-fired plants in the peninsula. However, the substitution of Sardinian coal-fired units would require more time as proper power and gas infrastructures would be needed. For this reason, the gas-fired (LNG-fired) capacity in Sardinia is expected to become operational only at the beginning of the next decade, when at least the Sicily-Sardinia branch of the Tyrrhenian Link and proper gas infrastructures are thought to be operational. Gas-fired production consolidates its position in the short- to medium-term thanks to favourable coal-to-gas switching conditions also influencing the expected decrease of imported energy. After 2025, the positive effect generated by lower volumes from abroad is partially counterbalanced by the expected acceleration of renewable development, that could stress competitive dynamics in the gas-fired generation segment. Natural gas is however expected to exceed 90% share of fuels consumption by 2024, driven by the progressive replacement of coal-fired capacity and other residual fuels. The key role of CCGT technology for sector decarbonization is consolidated.

Renewables and storage systems
Renewable market parity will consolidate in the post-pandemic recovery, supported by increasing market prices - strongly influenced by CO2 quotations. A potential acceleration in renewable installed capacity could be possible by overcoming the current bureaucratic slowness in the permitting process. Promising renewables perspectives could be driven by decreasing technology costs and improving PPA best practices supporting merchant investments. The renewable energy target planned by the Italian NECP (or PNIEC, Piano Nazionale Integrato Energia e Clima) envisages a renewable quote over GDC (Gross Domestic Demand of electricity) equal to 55% in 2030, but it is expected to be achieved only through a significant turnaround in the trajectory of growth of renewable installed capacity over the next few years. The European upward revision of 2030 targets driven by the Green Deal would expectedly require a stronger effort for the Italian power system, that could be committed to reach a 65% GDC renewable energy coverage in 10 years starting from the current level of around 38%.
Market parity for solar technologies consolidates in the short-term driven by bullish commodity trends. Tracker projects’ profitability is expected to permanently outpace that of traditional solar technologies in the next decade. In the short-term, market parity conditions strongly improve even for purely merchant wind investments (complete market parity conditions could be reached in 2-3 years), but project features and localization are likely to strongly influence the economics of business plans.
The new Capacity Market configuration could emphasize opportunities for renewable projects included in technology-diversified generation assets portfolios.
Overgeneration could become significant in the long-term, following the high renewable penetration in the energy mix. The development of storage technologies could mitigate the market countereffects. Investments in power intensive electrochemical storages could become in-the-money already in the mid-term, with revenue streams deriving mainly from the participation to the Ancillary Services Market and the provision of specific ancillary services to the TSO. Investments in energy intensive storage assets are likely to become interesting only in the long-term when time-shifting applications on the DAM could become economically attractive. In the short-term, investment opportunities for electrochemical storage assets could be generated also by the upcoming Capacity Market auctions.
Market opportunities on the DAM for pumped storage hydropower increase together with the level of non-programmable renewable penetration in the energy mix.
The Italian Market Design reform - aiming at a full revision of dispatching rules for an efficient integration of renewable sources in the system - could foster new opportunities for innovative technologies contributing to system flexibility.

Prices and marginality
Commodities dynamics and decreasing import volumes will guide prices until 2030. In the long-term, CO2 prices are expected to become the main determinant of electricity prices despite the growing share of renewable sources and enhanced market competition. Even with increasing competition in the market, existing CCGTs are expected to remain the marginal technology in most hours of the year. Increasing solar penetration significantly impacts prices during central hours of the day and exacerbates daily price differentials in the long-term, effect only partially mitigated by the development of storage units.
In the very long-term, carbon-neutrality targets imply a different market paradigm, where the evolution of electricity prices and market dynamics are expected to change in a near-zero emission context. Assuming the DAM market mechanism to remain unchanged, operators’ bidding strategies are expected to reflect always more the LCOE of the new marginal source on the market – renewables coupled with energy intensive storages.
The new market zones configuration could mitigate systematic congestions among zones over the next few years, especially between Sicily and Calabria, but renewables variability could impact the future price differentials. The progressive convergence of zonal prices in the mid- and long-term horizon will be achieved only after 2035.
The potential realization of additional reinforcements on the Sicily-Calabria interconnection, recently introduced in the 2021 Network Development Plan by Terna, could reduce line congestions and affect Sicilian competitive dynamics, as investigated through dedicated analyses.
The CSS level is strictly connected to the evolution of the market share of existing CCGTs: after the short-term bullish effect generated by the coal-to-gas switching, the new wave of investments brought by the CM auctions is supposed to strongly emphasize market competitiveness and to eventually bring baseload marginality near zero.
The cannibalization effect becomes evident on solar captured prices in the second half of the 2020s, especially in the southern market zones, characterized by a high renewable penetration. Wind generation is less concentrated than solar production and its greater distribution over the year and the over the hours of the day leads captured prices to align with – or even outperform - baseload prices. Captured prices of run-of-river hydro generation are more sensitive to seasonal natural inflows trends than to hourly variability.

Ancillary Services Market
In the short-term, improved DAM conditions for the thermoelectric gas-fired capacity could translate into lower needs for regulation services. The exit of coal-fired units and the growth of non-programmable renewable sources are anyway supposed to sustain ASM volumes in the mid- and long-term. Grid developments and storage systems investments could however contain such increase.
The Capacity Market strike price is expected to constitute a cap to DAM prices and, especially, to prices related to upward services on the ASM, for power plants involved in the mechanism.
According to the regulation currently in force, the expected wind and solar imbalance cost depends, per each specific project, on the average absolute production forecast error and the level of concordance with the macro-zonal imbalance (of the macro-zone to which the power plant belongs).

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The REF-E scenarios are complete market studies, processed every four months, setting out the evolution of the Italian electricity market up to 2040. The accompanying documents put the reader in a position to investigate the methodological assumptions and knowledge of the main results presented.

In particular, the scenarios show:

  • fuel prices
  • electricity demand
  • the development of the transmission grid
  • production capacity from renewable sources
  • thermal generation
  • marketing strategy
  • the safety and effectiveness of the system

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