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REF-E Scenarios: Update III2021 of November 2021

Domestic consumption and a positive performance of all major sector aggregations – due to public incentive measures and favourable financial conditions – drove a greater-than-expected growth of the Italian GDP, now seen to come back to 2019 levels in the first half of 2022 keeping closer to European growth rates 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, raw materials shortages and the remarkable growth of energy prices pushed upwards the 2021 Italian Consumer Price Index (CPI), expected slightly below the 2% threshold. A growing economy and international prices developments should add support to the inflation rate during the next two-year period, pushing the CPI above 2%.

OPEC Plus production is gradually resuming and the short- to mid-term market scenario is seen as moving towards a structural rebalancing as the cartel decided to stick to the existing production increase path. The recent Chinese power and coal supply crisis could support oil demand in the short-term, but Brent prices are however seen stable below the 70 $/bbl threshold between 2022 and 2024. Growing Chinese coal demand ahead of the country’s ban on Australian imports is expected to keep the market tight and to supportive both Asian and European reference prices in the short-term. The combination of a slow global demand recovery in the mid-term – also considering the effect of more ambitious decarbonization targets in Europe – and a 2%/year projected global production growth is expected to lead to a cumulated surplus, which should eventually bring the market back to normal conditions. Global LNG demand grew more than expected led by the Asia-Pacific region. A series of unplanned outages in the facilities of the Pacific area reduced the overall LNG availability and became a bullish factor. Demand-supply margins may remain tight into the upcoming winter keeping prices close to current levels. Production recovery and normalizing demand are however expected to ease market conditions and push prices lower starting from Q2-22. LNG prices are expected to stabilize in the mid-term as more than 150 Mtpa of liquefaction capacity is under construction around the world and a structurally short global LNG market is reckoned an unlikely event. Global LNG market dynamics are affecting European gas prices. Record high spot prices and limited LNG supply weighed on European gas inventories, supporting the TTF price. 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. Arrivals to Italy from southern areas (Libya, Algeria) gained weight following reduced flows from the north (Russia, Norway) and the ramp-up of the TAP pipeline (Azerbaijan), pushing the PSV-TTF spread below zero. A recovery of the Russian flows to Europe – also via the Nord Stream 2 pipeline – should cause the spread to widen back above 1 €/MWh in 2023. The PSV-TTF spread is thought however to become structurally tighter than historical averages in the mid-term (below the 1 €/MWh threshold) and to eventually nullify in the mid-2030s. The Italian gas market follows European hubs movements, with PSV dynamics strictly correlated to the TTF’s. Poor LNG arrivals, demand resumption and the recovery of European prices favoured a parallel recovery of PSV prices during 2021. A progressive stabilization lead by a return to normal market conditions in Europe is expected in the mid-term. CO2 prices moved higher in 2021, following the commodities surge and the release of the Fit for 55 package, which is expected to support a structural mid-term price upkeep. Long-term targets incorporate the commitment of the European Commission in supporting the ETS system as it is considered a key enabler of the decarbonization process. Sustained CO2 prices are expected support the switch from coal-fired to gas-fired production in the European power sector in the coming years, leading the economic phase-out of coal-fired capacity by the mid-2020s.

Electricity demand and net imports
The economic recovery is expected to drive electricity demand to pre-pandemic levels already by the end of 2021. 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. Italian net imports are seen peaking in 2021. In subsequent years, coal-to-gas switching dynamics in Europe are thought to influence the evolution of net import flows, 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, assuming a partial achievement of 2030 decarbonization 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.

Capacity Market and thermoelectric generation
New Capacity Market (CM) auctions targeting delivery years 2024-2025 are in sight and could be held in Q1-22. The Ministerial Decree of October 28, 2021, approved the new rules of the discipline, confirmed the auction for the delivery year 2024 and hypothesized the auction for delivery year 2025 to be held in function of the results achieved in the previous one – that depend on the degree of participation of new projects in relation to the adequacy demand envisaged. The level of residual adequacy demand to be auctioned for target year/s 2024-2025 will depend also on the status of the new projects selected for the 2023 auction. Authorized projects would be exposed to the risk of delays during the construction phase but are confirmed in the 2023 mechanism. Some projects selected in the 2023 auction did not manage to complete the authorization process in due time (the last deadline was October 31, 2021) and got excluded from the 2023 mechanism but are reckoned to participate in the new auction/s instead. This is coherent with our hypothesis envisaging that a portion of the 6.4 GW of new capacity initially auctioned by CM 2022-2023 could be subject to delays and come online a couple of years after the initial 2023 target year. Such capacity can facilitate the phase-out of coal-fired units in the peninsula by 2025 but is estimated to be not enough to ensure full system adequacy after these are definitively shut down: 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 auction/s. In our assumptions both auctions for 2024 and 2025 are held, as we assume that, based on the experience related to 2022-2023 auctions and given the tight timings (adequacy demand not published yet, but 2024 auction likely to be held in the first months of 2022) some investors proposing new projects could decide to skip the 2024 auction making necessary the deployment of the 2025 auction. Capacity additions are supposed to be mainly concentrated in the North market zone, where it is assumed the greatest adequacy demand level. This is coherent with the results of an analysis of the factors influencing the adequacy of the Italian power system we conducted in summer 2021, which is in turn aligned with the key results of the latest adequacy report on the Italian system, recently published by Terna. All the new projects participating to the 2024-2025 auction/s are supposed to exploit the 1-year ca. buffer permitted by the updated 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 auction/s, missing money issues could arise for a part of the existing gas-fired fleet in the second half of the 2020s, despite the increasing DAM market space generated by the decrease of import flows. Such conditions could be emphasized by highly competitive market conditions in the long-term. Therefore, we assume the need for a continuation of a capacity remuneration mechanism to cope with the risks of mothballing and generation adequacy issues after 2025 and onwards in the long-term. Despite the recent uptrend of fuel prices supported the temporary recovery of competitiveness of coal-fired output, switching dynamics are expected to favour back gas-fired generation and economically phase out coal-fired competitors within the next few years. 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 realized. Gas-fired production consolidates its position in the short- to medium-term thanks to progressively supportive coal-to-gas switching conditions, also influencing the expected decrease of imported energy. After 2025, the positive effect generated by lower imported volumes is partially counterbalanced by the expected acceleration of renewable development, that is expected to further stress competitive market dynamics in the long-term. Natural gas is however expected to exceed the 90% share of fuels consumption by 2024, driven by the progressive replacement of coal-fired capacity and other residual fuels.

Renewables and storage systems
The bullish trend of commodities influences market prices and fosters the definitive consolidation of renewable market parity in the short-term. 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. Further investments to reach more ambitious Green Deal targets could be supported by a new programme of incentives, as it is envisaged by the ‘RED II’ European Directive and its recent national transposition. The renewable energy target planned by the Italian NIECP envisages a renewable production to GDC (Gross Domestic Demand of electricity) ratio 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 coming 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 65-70% 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 by the end of the decade. In the short-term, market parity conditions strongly improve even for merchant wind investments, but project features and localization are still likely to strongly influence the economics of business plans. The new Capacity Market configuration could emphasize opportunities for renewable projects included in technologically diversified generation assets portfolios. Overgeneration and curtailment risk could become systematic in the long-term, following the high renewable penetration in the energy mix and possible delays in already planned grid reinforcements, and could be mitigated by the development of new storage assets and the use of existing pumped-hydro resources, for which market opportunities on the DAM increase together with the level of non-programmable renewable penetration in the energy mix. The sustainability of electrochemical storage projects and the permitting process are gradually being clarified but are still to be carefully evaluated based on the many possible configurations (large-scale, small-scale, stand-alone, coupled with renewables, behind-the-meter aggregation, ...). Investments in power intensive electrochemical batteries can be in-the-money already in the mid-term, with revenue streams deriving mainly from the participation in the balancing phase of the Ancillary Services Market and a long-term capacity remuneration, that could be provided by new specific projects which future adoption has been anticipated by the Italian transposition of the European Directive on the Internal Energy Market or existing mechanism such as the Capacity Market – that could generate short-term investment opportunities for storage systems integrated into properly designed asset portfolios. Investments in energy intensive storage batteries are likely to become interesting only in the long-term when time-shifting applications on the DAM could become economically attractive. In the long-term, up to 7 GW of energy intensive batteries and around 5 GW of power intensive batteries are expected to be developed in our Reference scenario. Besides the future adoption of new specific projects as anticipated by the recent regulatory developments, the Italian Market Design reform - aiming at a full revision of dispatching rules for an efficient integration of renewable sources in the system - could open new market segments on the Ancillary Services Market which will allow the competitive participation of storage and renewable resources. Our market view is prudential with respect to the application of the supportive mechanisms for renewables and storage systems envisaged by the recent regulatory updates, as a formal definition of the details regarding the new 2030 national targets is still missing. The effective application of the new mechanisms could accelerate the growth of low-carbon sources beyond the levels assumed in our scenario.

Prices and marginality
Following the demand recovery and the bullish trend of commodities, the PUN is expected to attain slightly below the 100 €/MWh threshold in both 2021 and 2022. Commodities dynamics are expected to guide prices also in the mid-term, with a price level stabilized in the 70-80 €/MWh range and aligned to the variable generation costs of marginal CCGTs. In the 2030s, increasing solar penetration will significantly impact prices during central hours of the day and exacerbates hourly price differentials, effect only partially mitigated by the development of energy intensive storage and PV with tracker. In the second half of the 2030s, the number of yearly hours in which existing CCGTs determine the system marginal price on the Day-Ahead-Market is expected to strongly decrease (from more than 90% today to around 50%) in the face of intensified competitive dynamics deriving from an ever-increasing renewable generation. In a similar market context, the weight of the variable cost of gas-fired units in the average baseload market price is expected to decrease. 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. Key grid reinforcements are expected in 2030, when the Adriatic Link (Centre-South – Centre-North) and the Sardinia-Sicily branch of the Tyrrhenian Link are assumed to come online. The progressive convergence of zonal prices in the mid- and long-term horizon will be achieved only after 2035. Sicily is expected to maintain a price premium over other southern zones until the mid-2020s and again in the early 2030s supported by export flows towards Tunisia. The CSS level is strictly connected to the evolution of the market share of existing CCGTs. Improving coal-to-gas switching dynamics are expected to foster baseload CSS up to 2019’s levels in the next few years, but the realization of the new wave of investments brought by the forthcoming CM auctions is supposed to strongly affect market competitiveness in the CCGT sector and to eventually bring baseload marginality to zero. In the second half of the 2030s market opportunities for existing CCGTs are expected to decrease, leading to below-zero baseload marginality and to amplified missing money / mothballing risks for existing capacity. In the mid-term, the existing CCGT fleet is expected to achieve an average DAM captured marginality of around 10 €/MWh and an average load factor level in the 2300-2400 EOH (equivalent operating hours) range. In the long-term, in the face of highly competitive market conditions, the average DAM captured marginality of the existing CCGT fleet is expected to decrease to around 5 €/MWh, with an average load factor performance aligned to the mid-term level. 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 thermoelectric units could lead to lower regulation needs. The exit of coal-fired units and the growth of non-programmable renewables are however supposed to sustain ASM volumes in the mid- and long-term. Grid developments and storage systems investments could contain such increase, though. Moreover, the realization of grid investments (e.g., synchronous compensators to better manage voltage criticalities) and the reform of Terna’s incentive mechanism (expected application 2022-2024) for a more efficient use of regulation resources – currently in consultation – could furtherly emphasize the competition on the ASM. The Capacity Market strike price will certainly constitute a cap to DAM prices and, especially, to prices related to upward services on the ASM, for power plants involved in the mechanism, but it may influence also the pricing strategy of units/operators not participating. Even considering the DAM prices currently experienced by the market, it is reckoned however unlikely the strike price to influence DAM prices in forthcoming years. With high commodities prices influencing DAM prices, ASM prices showed different dynamics for upward and downward services. Downward prices followed the trend of DAM prices while upward prices did not experience the same increase, with a consequent compression of margins. The situation is expected to persist until the turmoil characterizing the commodities markets gets reabsorbed after the winter. In the mid- and long-term, the Capacity Market strike price and the LCOS of storage technologies will become the main factors influencing ASM price dynamics and strategies.

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