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Five trends reshaping European power markets
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FIVE TRENDS RESHAPING EUROPEAN POWER MARKETS
October 19, 2021 | Article
By Eivind Samseth, Fabian Stockhausen, Xavier Veillard, and Alexander Weiss
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Utilities, traders, and large power consumers face significant challenges
addressing the next normal.
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European power markets have entered a period of unprecedented change. Power
prices have touched new highs: baseload week-ahead prices have risen above €200
per megawatt-hour (MWh)1Platts European Power Daily, S&P Global, spglobal.com.
in a number of European countries—about four times the average historical level.
That increase has been prompted largely by a surge in natural-gas and carbon
prices, which currently exceed €100 per MWh2TTF (Title Transfer Facility). and
€60 per metric ton, respectively. This development has affected the cost of
power produced by natural-gas power plants, which broadly set prices in European
markets.
At the same time, price volatility is reaching new heights as a result of the
uncertain output of renewable assets and a tight supply-and-demand balance in
the European power system. Navigating this next normal will be a key challenge
for utilities, traders, and large power consumers, and that highlights the
importance of developing resilient power-asset portfolios and managing risk.
In this article, we explore five trends that will shape the European power
sector in the decade to come and offer some perspectives on how utilities and
large consumers might respond.
WHAT’S AHEAD FOR THE EUROPEAN POWER SECTOR?
The European power market is undergoing major changes. Five trends underpin
these developments.
SUSTAINED GROWTH IN POWER DEMAND, SUPPORTED BY CLIMATE-RELATED TARGETS
Electricity demand is expected to increase steadily in Europe, at a CAGR of
about 2 percent until 2035. The main factors behind the surge will be the
electrification of transport and a ramp-up in the production of green hydrogen
through electrolysis, requiring renewable power (Exhibit 1).
Exhibit 1
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Transport power demand will grow by 14 percent CAGR as a result of the rollout
of the electrification infrastructure and national regulations on emissions (for
example, if cities ban internal-combustion engines and impose fiscal measures to
discourage the use of nonelectric vehicles). The power requirements of
green-hydrogen production will expand by about 40 percent CAGR, absorbing 230
terawatt-hours (TWh) of renewables output by 2035 across Europe—the equivalent
of nearly a third of Germany’s total consumption. Demand will grow only modestly
in the industrial, commercial, and residential sectors because efficiency
measures will mostly offset the electrification of industrial processes and
residential equipment.
A FUTURE ENERGY SYSTEM DOMINATED BY INTERMITTENT PRODUCTION, WITH UNCERTAINTY
ABOUT TOTAL CAPACITY ROLLOUT
The expectation is that more than 650 gigawatts (GW) of intermittent renewable
power, including wind and solar, will be developed from 2021 to 2035.
Intermittent renewables will account for about 60 percent of total installed
capacity in Europe in 2035, compared with about 35 percent in 2021 (Exhibit 2).
However, it remains uncertain whether the pace at which renewables are rolled
out will be sufficient:
* Project permissions have been delayed in a number of European countries. As a
result, the gap between the time projects are proposed and commissioned is up
to seven years.
* The modernization of the grid faces significant challenges as the production
of renewable power drives nodal imbalances, requiring utilities to invest in
new transmission and distribution assets.
* Restrictions have been placed on the development of renewables assets in a
growing number of countries—for example, limitations on onshore wind
development as a result of concerns about biodiversity or noise and visual
pollution.
Exhibit 2
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THE PHASEOUT OF COAL AND NUCLEAR ASSETS
A large drop in dispatchable, or controllable, generation assets is expected
because the use of coal is being phased out and nuclear plants are being
decommissioned. This issue highlights the power system’s reliance on
weather-dependent renewables and on natural gas. Adverse wind and solar
conditions or a slower pace of development for renewables could lead to power
shortages. Gas prices may also fluctuate more, given the demand sensitivity of
heating and the need for dispatchable power generation. In particular, European
coal and lignite capacity will drop drastically—by about 70 percent from 2021 to
2035. Western and Northern European countries are taking the lead in these
cutbacks.
Meanwhile, a number of EU countries are not renewing their existing
nuclear-power assets and are making few new investments. Nuclear capacity is
expected to decline by 23 percent from 2021 to 2035 (Exhibit 3). Germany,
Belgium, and Spain have announced that they will close all their nuclear plants
by 2022, 2025, and 2035, respectively. France has started closing its oldest
nuclear plant while building a 1,650-MW new-generation reactor. The United
Kingdom is developing a new 3,200-MW nuclear project, though delays and costs
may hinder the further development of nuclear capacity there.
Exhibit 3
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THE CRITICAL ROLE OF GAS AND BATTERIES TO BRIDGE DISPATCHABLE-POWER CAPACITY
NEEDS
> To ensure the grid’s stability, the power sector must compensate for the drop
> in dispatchable assets.
To ensure the grid’s stability, the power sector must compensate for the drop in
dispatchable assets. We expect new ones, such as natural-gas power plants and
batteries, to partly balance the grid as coal and nuclear generation decline.
More than 14 GW of natural gas are expected to come on line, mostly from 2021 to
2030, and more than 80 GW in batteries, primarily from 2030 to 2035. Yet a
number of investments are contingent on national capacity mechanisms to avoid
the risks of stranded assets for investors. Capacity mechanisms will also depend
on compatibility with EU regulations and the EU’s Fit for 55 package. Overall,
natural gas is expected to remain a critical source of dispatchable power,
especially in periods with prolonged low renewables output.
Declining battery-storage costs may encourage the rollout of batteries to
alleviate the shortfall in dispatchable capacity. But the pace may be slower
than anticipated, since European countries have not kick-started the industry
with storage mandates like those in some US states. Still, doubts remain about
the potential for cost reductions. The uncertainties include recent inflation in
the cost of battery materials and questions about the pace of the rollout of
“giga-factories” for grid-scale batteries.
THE RISE OF AN INTEGRATED EUROPEAN POWER MARKET WITH GERMANY AT ITS CORE
We expect a more integrated European power market including significant coupling
of power hubs. With cross-border flows of about 200 TWh a year in 2030, Germany
is expected to be at the center of the European power system. The country, now a
net power exporter, is expected to become a net power importer by the mid 2020s.
Interconnection capacity could grow about 50 percent by 2030 (Exhibits 4 and 5),
and this should further reinforce Germany’s position as Europe’s most liquid
power market. The country represents a key strategic region for European
utilities and traders aiming to manage market risks in their power portfolios.
Exhibit 4
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Exhibit 5
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IMPLICATIONS FOR THE EUROPEAN POWER SYSTEM
Fundamental trends in the European power system are expected to lead to a much
more volatile power-pricing environment, as we already see from this year’s
power-price surge. Europe is entering a period of extreme volatility, with daily
and hourly prices hitting new highs. In Germany, upward of 3,000 hours a year
may be priced at more than €100 or at less than €10 by 2030, compared with just
several hundred hours today, according to McKinsey’s EU Power Model. This
volatility could spur new behavior from market participants—for example, the
level at which they bid for their electricity supplies or hedge their future
needs.
One way for players to better understand the power market’s dynamics, including
volatility, is the merit-order cost curve, which illustrates the price-setting
mechanism in the power market. Five elements are particularly important to
anticipate future movement in power prices and price volatility (Exhibit 6):
* Gas, coal, and CO₂ prices altering the marginal production costs of thermal
power plants. The rise or fall of gas, coal, and CO₂ prices will drive the
volatility of the market’s clearing price.
* The intermittency of renewables. The volume of renewables power output will
push the curve either to the left or to the right, potentially leading to
very low or very high clearing prices.
* Dispatchable-asset new builds. Uncertainty about the volume and cost of
dispatchable-asset new builds (for example, batteries and combined-cycle gas
turbines) could raise or lower clearing prices.
* Average load uncertainty. Volatility in hourly power demand from sources such
as electric-vehicle charging and industrial electrification could create
supply shortages leading to high clearing prices during certain hours.
* Strategic bids during shortages. In a growing number of hours, anticipated
supply shortages could lead market players to bid their capacity at prices
higher than the marginal cost, theoretically up to the maximum allowed price.
Exhibit 6
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HOW CAN MARKET PLAYERS RESPOND?
The European power market is entering uncharted territory. When utilities and
large power buyers face that kind of uncertainty, strategic risk management
becomes a matter of survival. In the United Kingdom, recent defaults of power
and gas retailers, following the surge in gas prices, illustrate the high
stakes. Here are some steps players can take to address the uncertainties:
* Investing in best-in-class risk-management models. These would cover
market-price risks along with the nonlinear volume or shape risks of
day-ahead and intraday power markets. For example, players could make more
use of advanced stochastic profit-at-risk or cash-flow-at-risk models, such
as running them in quasi-real time to best inform hedging strategies. Ad-hoc
stress tests will also be critical to run on a periodic basis.
* Pursuing flexibility in portfolios. To reduce exposure to price surges in
wholesale power markets, players could source more flexibility both on the
demand and supply sides of portfolios, including, for example, demand-side
response aggregation and investments in gas-peaker assets, grid-scale
batteries, and virtual power plants (VPP).3VPPs can provide the flexibility
of a traditional power plant. They are executed through a financial agreement
between parties.
* Developing an active presence in the most liquid European power hubs. Germany
is expected to remain the most liquid market and an ideal place to optimize
hedging strategies across Europe—for example, by employing proxy hedges and
cross-border hedges in the event of strong market coupling and limited
liquidity in other markets.
* Using power purchase agreements with partial or full fixed-price
arrangements. Companies could use this strategy to hedge long-term power
purchases or sales, thus reducing exposures to volatile power prices.
--------------------------------------------------------------------------------
The European power market is entering an unprecedented phase. Market
participants that hope to be industry leaders must urgently invest in
best-in-class risk and portfolio management.
ABOUT THE AUTHOR(S)
Fabian Stockhausen is a consultant in McKinsey’s Düsseldorf office. Eivind
Samseth is a solution manager in the Oslo office. Xavier Veillard is a partner
in the Paris office. Alexander Weiss is senior partner in the Berlin office.
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