Europaudvalget 2022-23 (2. samling)
EUU Alm.del Bilag 228
Offentligt
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Denmark’s response to consultation on electricity market reform
State of play
The EU’s integrated and liberalised electricity market
model has been carefully
developed over two decades with the aim to ensure that electricity is produced and
delivered to consumers at least cost. It does so by promoting prices that reflect
underlying costs and therefore utilises resources most efficiently to the benefit of
consumers. Marginal pricing provides investment incentives to producers, energy
efficiency incentives for consumers, as well as incentives for flexibility that is
essential to integrate renewable energy and reduce price spikes. When combined,
these incentives overall put downward pressure on prices in the long run.
At the same time, 2022 gave rise to a period of enduring high electricity prices
across the continent. This has largely been caused by a gas shortage combined
with an unusually low availability of generation capacity
–
that is, a supply crisis.
This supply crisis created distributive challenges in the short to medium term that
have been addressed. There could be a need to assess possible regulatory
measures that increase the possibilities for consumers to be shielded from
sustained periods of high energy prices, while safeguarding security of supply and
leaving long-term investment signals intact.
The supply shortage and resulting high electricity prices created a drive to act fast
and to make interventions in the electricity market model. Market model changes
can however have significant and wide-ranging consequences, some of which can
be unintended and harmful to a market that has generally worked well terms of
providing low prices and a cost-effective energy transition.
Changes need to be
grounded in careful analysis and impact assessments.
Regulatory
interventions at the pace seen last year should therefore not become the new
normal, nor should the short-term interventions create the basis for upcoming long-
term changes to the market model. In short, we should be careful not to introduce
permanent changes to the long-term electricity market model based on short to
medium term considerations.
Complementing short-term physical electricity markets with liquid forward markets
Stable and low electricity prices at all times should not be
an objective in itself
for
the short-term physical electricity markets. The physical reality of a decarbonised
electricity system is one of intermittent power production. This necessitates a
correspondingly flexible demand and supply. Varying prices on an hourly, daily and
monthly basis signal to market actors when they should consume less, produce
more and, looking ahead, whether to invest in new capacity. Without prices that
reflect the physical reality of a zero-emission power system, the consequence may
ultimately be a compromised security of supply and a lack of investment into new
Side 1/2
 EUU, Alm.del - 2022-23 (2. samling) - Bilag 228: Notat vedr. høringssvar til Europa-Kommissionens offentlige høring vedrørende reform af EU’s elmarkedsregler
capacity. Not only in
renewables’ capacity, but also
in the kind of flexible resources
(demand response, storage, thermal peaking plants, power-to-X etc.) needed to
match intermittent power production with demand to reduce price spikes across all
time horizons.
At the same time, consumers and producers must be able to feel confident about
future price developments. It is possible
–
indeed desirable
–
to attune market
actors to an energy system where flexibility is valued. This does not mean,
however, that e.g. consumers, particularly vulnerable consumers, should be
unprotected during long periods of high prices. Shocks causing high prices may
occur again in the future. A long-term priority must therefore be a more resilient
interconnected European energy market that can withstand these shocks without
putting an excessive burden on consumers.
Improvements in the financial electricity markets can provide price stability
to consumers and producers without compromising price signals on short-
term physical markets necessary for a cost-effective integration of renewable
power.
Power Purchase Agreements (PPAs) can have a role to play in this regard.
PPAs are existing tools and the Renewable Energy Directive already includes a
requirement to remove barriers to their use. Actively promoting physical PPAs risk
introducing
“produce-and-forget” incentives that are incompatible with system
needs. Financial PPAs do not suffer from this shortcoming, but still risk draining
liquidity from the forward markets.
Contracts-for-difference (CfDs) are also an existing tool today, but contrary to PPAs
these should not be considered as an instrument to decouple consumers from
short-term electricity markets. As long as the capacity on a CfD is inframarginal, the
CfD does not mitigate the effect of short-term markets on the price for final
consumers. In terms of supporting investments in new capacity,
promoting
market-based deployment of renewable energy should be a first priority.
To
the extent that public support is required, governments
can
use CfDs for new
capacity, but governments should also consider alternatives. CfDs are not
necessarily
in general
the best/efficient way to support new capacity. It is thus
crucial that CfDs neither become mandatory nor applied to existing capacity.
We would generally recommend focusing on one single approach to mitigate the
impact of short-term market volatility on consumers/producers. Simultaneously
promoting a selection of instruments such as PPAs or CfDs risks draining liquidity
from forward markets. Efforts should instead focus on promoting liquid forward
markets while ensuring a level playing field for PPAs and best-practices for CfDs.
Side 2/2