The EU’s rising CO2 prices since December 2020 contribute to transition risks of carbon-intensive utilities, particularly if they remain structurally high beyond 2H21, through greater pressure on margins and decarbonisation, Fitch Ratings says.
This has no immediate rating implications for coal-exposed utilities due to mitigating factors such as hedging, investments in renewables and reflection of higher CO2 costs in wholesale electricity prices in markets where coal-fired plants typically set wholesale electricity prices. However, CO2 prices remaining at or above EUR40 per tonne from 2021 will ultimately have a negative impact on generation margins from coal, in turn forcing quicker decarbonisation of the electricity market. For countries where coal is still important in the electricity mix, such as Poland, quicker decarbonisation will increase systemic risks due to the large size of the coal-fired assets requiring replacement.
CO2 prices in the EU rose to EUR38 per tonne in February 2021 (monthly average), from EUR34 in January and EUR31 in December 2020, exceeding the previous high of EUR30. This was attributed to purchase of CO2 allowances to cover 2020 emissions by end-April 2021, inability to use the new quotas tendered in the primary CO2 market for 2021 to cover 2020 demand as the EU ETS enters its new phase spanning 2021-2030, and a delay in the first primary CO2 market auction to end-January 2021. In addition, Europe experienced a colder winter in 2020, which increased demand for electricity and CO2 allowances.
However, some drivers of the high CO2 prices are more long-term. These include the December 2020 conclusions from the European Council meeting, which paved the way for more ambitious CO2 reduction targets for 2030 of 55% from 1990 levels, compared with the existing target of 40%, which will decrease the supply of new CO2 allowances in 2020s. Another price driver is hedging by utilities, but also investments by financial companies seeking to profit in what is widely perceived as a bullish market, stimulated by the EU’s climate policy.
Poland is among the countries most exposed to CO2 pricing. We expect that the additional CO2 burden will be largely reflected in wholesale electricity prices, but some of the least efficient coal-fired power plants will be pushed out of the market by imports. Profitability may be eroded in 2022 once the existing hedges roll off, but this will be mitigated by capacity payments from 2021. Suppliers of electricity could be hit if they are unable to fully reflect higher electricity purchase costs in prices being offered to retail customers.
For Polish utilities higher CO2 costs are mostly passed on, albeit gradually narrowing, to end customers, and offset by capacity payments. PGE Polska Grupa Energetyczna S.A. (BBB+/Stable), ENEA S.A. (BBB/Stable) and TAURON Polska Energia S.A. (Tauron, BBB-/Stable) have integrated business profiles with around 40%-75% contribution from more stable electricity distribution. They also have headroom under our leverage guidelines for their current ratings and the government has announced plans to segregate their coal-related assets into a separate entity (no details at this stage).
For Germany’s RWE AG (BBB/Stable) the impact is mitigated by long-term hedging and its progressive reorientation into renewable generation. For Czech CEZ, a.s. (A-/Stable) higher CO2 costs are mitigated by its lower carbon footprint due to nuclear generation, and an integrated business profile with more stable electricity distribution, on top of hedging.
In the case of Bulgarian Energy Holding EAD (BB/Positive) most of its electricity generation is derived from nuclear and hydro. For Greek Public Power Corporation S.A. (BB-/Stable) its low Standalone Credit Profile of ‘b+’ already reflects loss-making lignite-fired power plants and an ambitious lignite decommissioning plan to 2023.
Source: Fitch Ratings